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Collaborating Authors
SPE Improved Oil Recovery Conference
Abstract Transient N2-foam flow experiments were conducted in a heterogeneous sandstone core to improve our understanding of how foam flows in these complex systems. An apparatus with an aluminum core holder and a medical x-ray CT scanner was built to measure the aqueous-phase saturation nondestructively. Pressure readings along the length of the core, were recorded using six pressure taps drilled into the core. We coinjected the foamer solution and the gas at the core's inlet and allowed foam generation to occur inside the core. Measurements of the aqueous-phase saturation and of the pressure at various times enabled us to track and analyze the transient foam behavior in the core. Three foam qualities were tested ranging from low quality (gas fractional flow) of 33% to high quality of 90%. Results show that gas initially drains the core and forms weak foam before crossing a permeability discontinuity present in the core. The travel distance from the inlet until the point of entrance into the permeability discontinuity was inversely proportional to the water content of the foam. Wetter foams required a shorter distance before the gas entered the low-permeability layer. Crossing the permeability discontinuity, the weak foam became stronger as evidenced by the drop in aqueous-phase saturation and the increase in the pressure gradient. Once strong foam was generated, it traveled to the outlet in a piston-like fashion. After it breaks through the outlet, a second front appears to be traveling backward toward the inlet against the direction of flow. Diversion to lower-permeability layers occurs during this second front movement. This observation was validated qualitatively by a simple pore network model that is equipped with the invasion percolation with memory algorithm. The results of the network show the diversion occurring once strong foam generates in the high-permeability zone and explain the discontinuous aqueous-phase saturation observed during the first foam front movement.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Abstract The Wasson Field in the Permian Basin has been the forerunner in the use of carbon dioxide (CO2) enhanced oil recovery (EOR) to tap the potential of the residual oil zone (ROZ). This field is one of the largest ROZ oil producers in the Permian with multi-billion barrels of oil in place, and it is a prime target for EOR as well as CO2 sequestration. Twenty-seven ROZ development projects implemented over three decades in three of the largest Wasson San Andres units (Denver, ODC, and Willard) comprise the scope of data analyzed for this paper. These projects targeted the ROZ pay in mature CO2 floods in the Main Oil Column (MOC) by utilizing existing wells and commingling production from both the MOC and ROZ to reduce costs. However, commingled production makes interpreting the incremental ROZ recovery challenging, which ultimately increases the uncertainty in predicting the technical and economic performance of future ROZ projects. This paper presents a reliable, geo science-driven forecasting technique for ROZ development based on a comprehensive study of the production and injection performance of the 27 ROZ projects. This study uses in-place volumes from a geological model that integrated log, core, and seismic data; historical production and injection data; multi-year zonal flow profiles; and established dimensionless forecasting methods. This paper presents a consistent methodology to: Estimate MOC performance through dimensionless analysis and deduce historical ROZ performance; and, Forecast ROZ ultimate recovery after history matching the resulting injection and production. The estimated ROZ oil recovery across the three Wasson units has been analyzed to establish correlations with the residual oil saturation (Sorw), reservoir quality index (RQI), reservoir heterogeneity, pattern configuration, waterflood maturity, and the water alternating gas (WAG) ratio of the CO2 injection. The key performance indicators of ROZ oil recovery have been determined to be the residual oil saturation and reservoir quality index. The study also shows that the average Sorwin the MOC after waterflooding operations can be higher than the Sorwin the ROZ post"natural" waterflood, resulting in higher oil recovery from the CO2 flood in the MOC than in the ROZ. A correlation has also been established between the ROZ and MOC oil recoveries as a function of floodable volumes using petrophysical properties, which can be applied to analogous ROZ development in mature MOC assets. Most published ROZ oil recovery estimation methods have used reservoir simulation models or analytical approaches like scaling the MOCoil recovery or use of analogous actual ROZ performance. These approaches have limited applicability and cannot be applied widely over different ROZ projects. This paper is the first study that utilizes voluminous historical field data from multiple ROZ projects spread over an extensive duration and acreage across the Wasson Field to estimate ROZ oil recoveries and then propose a novel approach to correlate and scale these estimated ROZ recoveries using petrophysical properties.
- North America > United States > Texas > Gaines County (0.92)
- North America > United States > Texas > Yoakum County (0.83)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (29 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Reduction of residual oil saturation (1.00)
- (2 more...)
Abstract 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 applications.
- North America > United States (1.00)
- Africa > Angola (0.89)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth (0.28)
- Overview (1.00)
- Research Report > New Finding (0.48)
- Geology > Rock Type (0.48)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 13/22a > Captain Field > Captain Formation (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Block 5 > Al-Shaheen Field > Umm Er Radhuma Formation (0.99)
- Asia > Malaysia > Terengganu > South China Sea > Malay Basin > Block PM 305 > Angsi Field (0.99)
- (3 more...)
In-Depth Water Conformance Control: Design, Implementation and Surveillance of the First Thermally Active Polymers Treatment TAP in a Colombian Field
Gutierrez, Mauricio (Ecopetrol S.A.) | García, Joan Sebastian (Ecopetrol S.A.) | Castro, Ruben Hernan (Former Ecopetrol S.A.) | Zafra, Tatiana Yiceth (Ecopetrol S.A.) | Rojas, Jonattan (Ecopetrol S.A.) | Ortiz, Rocio Macarena (Ecopetrol S.A.) | Quintero, Henderson Ivan (Ecopetrol S.A.) | Garcia, Hugo Alejandro (Ecopetrol S.A.) | Niño, Luis (TIP) | Amado, Jhon (TIP) | Quintero, Diego (ChampionX) | Kiani, Mojtaba (ChampionX)
Abstract 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.
- South America > Colombia > Santander Department (0.68)
- South America > Colombia > Bolivar Department (0.51)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- South America > Colombia > Tolima Department > Middle Magdalena Basin > Casabe Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Casabe Field (0.99)
- (13 more...)
Mapping Chemical EOR Technologies to Different Reservoir Settings at Harsh Conditions in North Kuwait
Al-Dhuwaihi, Abdul-Aziz (Kuwait Oil Company) | Tiwari, Sanhita (Kuwait Oil Company) | Baroon, Bodoor (Kuwait Oil Company) | AlAbbas, Reem (Kuwait Oil Company) | Al-Ajmi, Moudi (Kuwait Oil Company) | De Bruijn, Gerbert (Shell Kuwait Exploration and Production B.V.) | Nabulsi, Randa (Shell Kuwait Exploration and Production B.V.) | Abu Shiekah, Issa (Shell Kuwait Exploration and Production B.V.) | Glasbergen, Gerard (Shell Global Solutions International B.V.) | van Batenburg, Diederik (Shell Global Solutions International B.V.)
Abstract EOR is a key focus area for sustaining long term production and maximizing of recovery in Raudhatain and Sabriyah oil fields of North Kuwait (NK). NK oil fields consist of multiple stacked reservoirs containing both clastic and carbonate with challenging temperature and formation water salinity conditions for Chemical EOR. In addition to these harsh conditions, reservoirs have geological structural complexity, reservoir heterogeneity and aquifer strength settings. Kuwait Oil Company is putting large efforts into Chemical EOR (cEOR) maturation through two ongoing ASP pilots and polymer flooding maturation studies. Ongoing studies and preliminary piloting performance results revealed that different reservoir segments have different cEOR requirements for viable incremental oil opportunities on top of ongoing water flooding. An expansion strategy has been developed that provides a view on how to transition from pilot results to larger scale commercial implementation of cEOR for each reservoir segment. This includes front end elements, beyond conventional cEOR screening studies, injectivity, conformance control, inorganic scaling, facility impact and pattern configurations. For larger scale, many additional aspects such as water source, well location, phasing, logistics and impact of back production are important factors. For commerciality, there needs to be abalance between schedule, maximizing economic recovery, operability,availability of source water and costs. A holistic, structured approach has been established in defining production forecasts and life cycle cost estimates for ASP, SP and polymer development concepts screening for major NK reservoirs. The approach has allowed comparison between recovery methods and reservoirs which helped in defining an EOR expansion plan. The novelty in this EOR expansion strategy is in application of a structured and holistic approach to map viable cEOR technologies to different reservoir segments based on in-depth screening criteria. The methodology allowed generating "standardized" time bound forecasts and cost estimates for screening a range of viable mapped cEOR methods for a range of reservoir segments- facilitating like for like comparison.
- Asia > Middle East > Kuwait > Jahra Governorate (0.66)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.17)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Upper Burgan Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Mauddud Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > Raudhatain Field > Lower Burgan Formation (0.99)
- (5 more...)
Abstract Surfactant flooding is a promising technique that can reduce interfacial tension (IFT) between oil and water to ultra-low values, mobilizing previously trapped oil. For reservoirs at moderate to high pressures, understanding and modeling how pressure affects the phase behavior of a surfactant-brine-oil system is crucial to the design and implementation of efficient/cost-effective surfactant flooding project. Typical phase behavior experiments and models are done only at low pressures. Objective of this paper is to comprehensively model realistic range of pressure, temperature, and other parameters, using hydrophilic-lipophilic deviation (HLD) and net-average curvature (NAC) based equation-of-state (EoS). This paper shows how to model an anionic surfactant system consisting of a surfactant, co-solvent, brine (up to 10 wt%) and synthetic oil over a large range in pressure (up to 8000 psi), temperature (up to 60 °C), and compositions. The model is developed from measurements made using a high-pressure PVT cell. Parameters such as the oil-water ratio and the surfactant concentration were varied in ternary space under both atmospheric and reservoir conditions. Selected experimental results were then matched to our new EoS based on HLD-NAC. The advantage of this approach is that the tuned model can predict phase behavior in a unified way for all experiments. The pressure and temperature scans show that pressure has a significant effect on the surfactant microemulsion phase behavior, shifting it from an optimal three-phase system at low pressure to a nonoptimal two-phase system at high pressure. Further, multiple scans at different oil-water ratios show a shift in the optimum indicating that phase behavior partitioning of the various components is changing with oil saturation. In addition, we show how to determine the optimum pseudocomponent composition for such a ternary pseudocomponent system. We further show that the micellar correlation length in the three-phase region can be predicted well using linear functions with temperature, pressure, and salinity. The change in characteristic length is a critical aspect of modeling the phase behavior accurately with the HLD-NAC EoS, and ultimately to predict and scale the phase behavior for other reservoir conditions. We show that there is a well-defined optimum 3D surface in the pressure, temperature, and salinity space that can aid the design of surfactant floods for field use and reduce the risk of those projects. Further, the use of the tuned HLD-NAC EoS can define and reduce the number of experiments needed to model the optimum owing to a unified EoS prediction of the phase behavior. When input into a numerical simulator, the improved prediction of the size and shape of the two-phase lobes with changing pressure, temperature, and salinity will also improve estimations of surfactant slug size needed to maintain ultra-low IFTs.
Abstract Historical production data from unconventional oil wells show rapid decline, that leads to low ultimate recovery. With more and more production wells entering low rate period, it’s critical to conduct well stimulation to recover more from existing wells. Alternate application scenarios for production enhancement is during parent pressure up operations. Operators usually pump large volume water to parent well to prevent frac-hit while performing hydraulic fracturing. EOR application can be easily combined into this process to achieve multiple goal the same time. Microbial EOR has been developed as an environmentally friendly EOR technology. The objective of this paper is to present the full cycle of a MEOR process, from microbiology theory, to prove concept though lab experiments, then to implementation in field. The lab laboratory experiments are to investigate the mechanism that the microbes can be stimulated and effective to clean up near wellbore fractures. The field trials are to demonstrate the effectiveness of MEOR to shale wells. Field results show that MEOR can be an economical effective approach to add reserves to shale wells at low cost. Additional value of microbial technology is that it doesn’t change oil and water quality in production, then there is no treatment cost as other stimulation methods.
- Europe (0.47)
- North America > United States > Texas (0.35)
- Geology > Geological Subdiscipline (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
CCUS in China: Challenges and Opportunities
Guo, Hu (China University of Petroleum-Beijing) | Lyu, Xiuqin (Sinopec Northwest Oil Field Company) | Meng, En (China University of Petroleum-Beijing) | Xu, Yang (China National Logging Company Ltd) | Zhang, Menghao (China University of Petroleum-Beijing) | Fu, Hongtao (China University of Petroleum-Beijing) | Zhang, Yuxuan (China University of Petroleum-Beijing) | Song, Kaoping (China University of Petroleum-Beijing)
Abstract CO2 emission was the major cause that accounted for the global warming and climate chance. How to reduce CO2 footprint to stop or slow down the global warming has been hot topic. As a developing country, China has become the largest CO2 emission nation in the world during the industrialization process to develop economy, although the CO2 emission intensity has been reduced significantly compared to previous stage. China has promised and succeeded to keep the promise reduce carbon intensity to meet the requirement of Paris Agreement. To meet the promise to attain carbon peak emission in 2030 and carbon neutrality in 2060 (CPCN), carbon capture, utilization and storage (CCUS) is an important and necessary step. Considering the high cost, high energy intensity and complex technology integrated optimization add uncertainties of CCS, utilization of captured CO2 can be of vital importance. One of the most attractive CCUS in China is CO2 enhanced oil recovery with captured CO2 (CCS EOR). CO2 EOR with captured CO2 may be one the best CCUS ways for China for the following three reasons. First, it can meet the increasing oil demand while reducing the carbon intensive coal. Second, around 66 CO2 EOR field tests have been conducted in China and experiences have ben gained. Finally, CO2 EOR in the USA was a proven technology which can increase oil production significantly and stably. Latest CCUS technology progress in China was reviewed. As of July 2021, 49 projects were carried out or under construction. Net CO2 avoided costs from 39 projects varied from 120 to 730 CNY/ ton CO2 (18.5-112.3 USD/ ton CO2). Although CCUS technology development in China was significant, the gap between global leading levels are obvious. Current challenges of CCS EOR include high CO2 capture cost, small scale, low incremental oil recovery, long-time huge capital input. The costs can be significantly reduced when the scale was enlarged to a commercial scale and transportation costs were further reduced by either pipelines or trains. CO2 transportation with well-distributed high-speed rail in China may be a feasible choice in future. If the CO2 EOR in China develops with the same speed as the USA, CO2 used for EOR in 2050 can be as high as 87.27 million tons. CO2 used for CO2 EOR in 2050 can account for 17% to 44% of the CO2 emission. CCS EOR in China will provid both domestic and international companies with good opportunities.
- Asia > China (1.00)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.31)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wichita Albany Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Northwest Field (0.99)
- (8 more...)
Abstract Polymer flood improves the sweep efficiency of viscous oil recovery over water flood. The low-tension polymer (LTP) flood has the potential to improve the displacement efficiency due to low interfacial tension without sacrificing sweep efficiency. The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sand pack. Over 20 non-ionic surfactants/co-solvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dynes/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. For the experiments with connate water saturation, the sandpack was water-wet/intermediate-wet. A base-case polymer flood (without any surfactant) with a viscosity ratio of 10 showed a stable displacement and 82% OOIP oil recovery at the first pore volume injected (PVI).LTP flood with an IFT of 0.1 dynes/cm also showed stable displacement front, but ahigher oil recovery at 1 PVI (90% OOIP).Further reduction in IFT to 0.05 dynes/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet, the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding the nonionic surfactants did not improve displacement efficiency nor oil recovery in oil-wet sandpacks.
- North America > Canada > Alberta (0.46)
- North America > United States > Texas (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline (0.66)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Pelican Lake Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Mooney Field > Bluesky Formation (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
First Nanoparticle-Based EOR Nano-EOR Project in Japan: Laboratory Experiments for a Field Pilot Test
Kaito, Yutaro (Japan Petroleum Exploration Co. Ltd.) | Goto, Ayae (Japan Petroleum Exploration Co. Ltd.) | Ito, Daisuke (Japan Petroleum Exploration Co. Ltd.) | Murakami, Satoru (Nissan Chemical Corporation) | Kitagawa, Hirotake (Nissan Chemical Corporation) | Ohori, Takahiro (Nissan Chemical Corporation)
Abstract "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.
- Asia > Japan > Honshu Island > Akita Prefecture (0.87)
- Europe > United Kingdom > North Sea (0.40)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- North America > United States > Montana > Target Field (0.99)
- Asia > Japan > Honshu Island > Akita Prefecture > Sarukawa Field (0.99)