Day 3 Wed, April 27, 2022最新文献

{"title":"Water Alternating Alkane Injection: A Molecular Dynamics Simulation Study","authors":"Y. Coskuner, E. Dean, Xiaolong Yin, E. Ozkan","doi":"10.2118/209363-ms","DOIUrl":"https://doi.org/10.2118/209363-ms","url":null,"abstract":"\u0000 In a recent study, we observed that the diffusion coefficient of common hydrocarbons in crude oils are more affected by the presence of different hydrocarbon components than the effect of confinement. Based on our previous observations, in this study, we investigated the efficiency of smaller-chain alkane injection into oil-soaked sandstone pores to dilute the oil with alkane. We used molecular dynamics simulations of C2, C3, C4 and C5 as well as a mixture of C3 and C4 to rank the effects of different alkanes on the diffusion and distribution of oil molecules in pore. As water-alternating-alkane injection would bring water into the pores, our simulations included water. Our results indicate that alkane injection into sandstone reservoirs has a significant potential due to the fact that it effectively dilutes the oil. Water always wets quartz surface relative to the oils. Injection of water therefore should be effective in detaching oil molecules on the surface. Presence of water layers did not affect the diffusion coefficients of oil molecules.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121088888","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":"Residual Oil Zone Recovery Evaluation and Forecast Methodology: A Wasson Field Case Study","authors":"N. Gupta, Sameer Parakh, Tao Gang, Nick Cestari, P. Bandyopadhyay","doi":"10.2118/209474-ms","DOIUrl":"https://doi.org/10.2118/209474-ms","url":null,"abstract":"\u0000 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.\u0000 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.\u0000 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.\u0000 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.\u0000 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 a","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129796295","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":"Modeling of High Pressure and Temperature Microemulsion Experiments Using HLD-NAC Based Equation of State","authors":"Daulet Magzymov, R. Johns, Hafsa Hashim, B. Dindoruk","doi":"10.2118/209470-ms","DOIUrl":"https://doi.org/10.2118/209470-ms","url":null,"abstract":"\u0000 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).\u0000 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.\u0000 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.\u0000 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.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"214 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131688355","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":"Viscous Oil Polymer Flood Milne Point Field Case History Concept to Full Field Implementation","authors":"R. Edwards, Almas Aitkulov, C. Redwine, Katherine Cunha","doi":"10.2118/209372-ms","DOIUrl":"https://doi.org/10.2118/209372-ms","url":null,"abstract":"\u0000 Milne Point Field initiated the first polymer injection pilots on the North Slope of Alaska starting in 2018 and have rapidly progressed to full-field polymer injection within four years. The two initial pilot projects injected at an initial total rate of 6,000 bwpd utilizing 5 horizontal injection wells. Expansion activities began two years later in 2020 with the addition of 4 additional polymer injection units. By the end of 2021, total field polymer injection rate was 32,000 bwpd via 29 horizontal injection wells. Targeted reservoirs have average permeabilities ranging from 100 – 1000md and in-situ oil viscosities ranging from 40 cp to 1300 cp. Both secondary and tertiary floods are being conducted in both greenfield and brownfield development areas each with varying, yet all promising, results. The highest observed recovery is in a secondary polymer flood pattern at 27% of OOIP with an oil viscosity of 850 cp and no water breakthrough observed to date. Responses in injection well injectivities have ranged from as low as 0% up to 50% loss to date and are observed to be correlated by well spacing and total reservoir mobility. Multiple polymer injection designs exist throughout the field which were driven by existing infrastructure, specific needs from pattern to pattern, and increased learning over time. A logistics system has also been successfully developed that allows for large scale polymer flood on the North Slope of Alaska. The intent of this paper is to a.) provide sufficient historical context to give insight into field development when polymer flood was started b.) highlight what has been done to date in regards to moving from polymer flood concept to near full field expansion and c.) present observed results with the hope that they can help set expectations for future polymer flood projects.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133523045","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":"Gas-Oil Ratio GOR Characterization of Unconventional Wells in Eagle Ford","authors":"Yajie Zhao, J. Nohavitza, R. Williams, Wei Yu, M. Fiallos-Torres, Reza Ganjdanesh, K. Sepehrnoori","doi":"10.2118/209408-ms","DOIUrl":"https://doi.org/10.2118/209408-ms","url":null,"abstract":"\u0000 With the increased exploration and development of unconventional reservoirs, the complicated production mechanisms of unconventional wells have gradually become a hot topic among the oil and gas industry. Due to the ultra-low permeability and porosity, the fluid phase behavior in shale reservoirs significantly differs from the conventional fluid phase behavior, increasing the production forecasting complexity. A substantial effort to better understand the mechanisms is the ability to characterize the unconventional well gas-oil ratio (GOR) behavior. The GOR always plays a critical indicator to help predict long-term oil/gas production trends and develop appropriate production strategies. In this paper, GOR behavior was discussed based on an unconventional parent-child horizontal well set in the Eagle Ford shale formation. Subsequently, fracture hit intensity can be determined through the producing GOR characterization. Afterward, the historical production data were well matched. The long-term GOR trends (20 years) were then predicted with the calibrated reservoir model. Based on the simulation results, an interpretation of the fracture hit impact on GOR behavior, and the well productivity was established. This study provides some key insights into GOR behaviors, especially for the parent-child well GOR trends with considering the impact of fracture hits. The Eagle Ford GOR is strongly influenced by the flowing bottomhole pressure. Meanwhile, the GOR trends of both parent and child wells are extremely sensitive to fracture hits, strong correlations between GOR and fracture hits are observed. Compared to the parent well, the flat GOR period of the child well is much shorter due to pressure depletion. The existence of a child well also reduces the rising speed of the parent well with a lower plateau. In addition, the long-term production prediction shows that fracture hits negatively influenced both well performances, where the child well has a more severe production loss than the parent well. Through the findings presented in this work, a better understanding of the unconventional well GOR behaviors can be obtained. The analysis approaches proposed in this paper provide valuable insights into GOR characterization and contribute to the production forecasting from unconventional plays. The results can help to improve the efficiency of reservoir management, field development, and economic valuation in future projects.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116849302","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":"Coupled Well-Reservoir Heat Modelling for Closed-Loop Geothermal Wells - A Feasibility Study","authors":"S. Livescu, B. Dindoruk","doi":"10.2118/209437-ms","DOIUrl":"https://doi.org/10.2118/209437-ms","url":null,"abstract":"\u0000 Naturally occurring hydrocarbon resources have been powering the world since the second half of the nineteenth century with increasing proportionality in terms of the energy mix, allowing tremendous economic growth globally. However, another subsurface resource is estimated to hold several orders of magnitude more energy than all hydrocarbon resources. Geothermal energy is renewable, abundant, and has a small carbon footprint, but its current use is geographically sparse and represents only 1% of the global energy production. To scale it up economically to other regions and applications, several critical problems need to be solved. In a recent paper, the effects of several well parameters were studied on the thermal output, assuming steady-state temperature (or successions of steady-state temperature for a given period) in the near-well region. In this paper, the effects of the transient near-well temperature and heat inflow from the formation are studied.\u0000 The hydrocarbon industry is evaluating the opportunity of producing geothermal energy from existing oil and gas wells, as electricity and/or low-temperature waste heat. This can potentially yield significant advantages over traditional geothermal wells, especially in terms of reduced capital expenditure. For instance, the performance of geothermal wells, both injectors and producers, is limited by formation damage issues, such as drilling fluid invasion, fines migration, plugging, and mineral scaling. The scale composition is dependent on the formation mineralogy, for producing wells, and on the injected water quality, for injecting wells. Addressing these issues over the entire well life may be expensive and difficult to predict. Depending on the assumed boundary conditions and other simplifying assumptions, numerical simulations of coupled well and reservoir heat and mass transport may help predict more accurately the thermal output and longer-term economics.\u0000 In a previous study, a mathematical model was proposed for closed-loop wells (i.e., U-shaped wells, single pipes in wells, and concentric pipes in wells) to study the effect of several well parameters on the thermal output. The focus on that study was on repurposing existing hydrocarbon wells to geothermal wells. The time- and space-dependent temperature solutions for all well configurations were obtained for time- and space-dependent fluid and flow properties. The near-well temperature was considered as steady-state, at least for a given time frame. A sensitivity study was also performed, showing the effects of several well parameters on the temperature of the fluid flowing to surface. Sensitivity results were included for such parameters as fluid flow rate, well length, inner tubing and annulus diameters, geothermal temperature, and overall heat transfer coefficients. The learnings and outcome from that study can also be incorporated in terms of adding wellbore lift models in various reservoir models. In this study, the effect of t","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"96 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127216362","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":"Polymer Containing Produced Fluid Treatment for Re-Injection: Lab Development to Field Deployment","authors":"Gayani Pinnawala, S. Subrahmanyan, D. Alexis, S. Palayangoda, Harold C. Linnemeyer, Gojko Matovic, Do Hoon Kim, Timothy Theriot, Taimur Malik, V. Dwarakanath","doi":"10.2118/209402-ms","DOIUrl":"https://doi.org/10.2118/209402-ms","url":null,"abstract":"\u0000 Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR.\u0000 Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime.\u0000 Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121815282","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":"Enhanced Oil Recovery Experiments in Wolfcamp Outcrop Cores and Synthetic Cores to Assess Contribution of Pore-Scale Processes","authors":"A. Kamruzzaman, H. Kazemi, Timothy J Kneafsey, M. Reagan","doi":"10.2118/209455-ms","DOIUrl":"https://doi.org/10.2118/209455-ms","url":null,"abstract":"\u0000 This paper assesses the pore- and field-scale enhanced oil recovery (EOR) mechanisms by gas injection for low permeability shale reservoirs. We performed compression-decompression laboratory experiments in ultratight outcrop cores of the Permian Basin as well as in ceramic cores using n-dodecane for oil. The EOR assessment strategy involved determining the quantity of oil produced after injection of helium (He), nitrogen (N2), methane (CH4), and methane/carbon dioxide (CH4/CO2) gas mixtures into unfractured and fractured cores followed by depressurization. Using the oil recovery volumes from cores with different number of fractures, we quantified the effect of fractures on oil recovery—both for Wolfcamp outcrop cores and several ceramic cores. We observed that the amount of oil recovered was significantly affected by the pore-network complexity and pore-size distribution.\u0000 We conducted laboratory EOR tests at pore pressure of 1500 psia and temperature of 160°F using a unique coreflooding apparatus capable of measuring small volumes of the effluent oil less than 1 cm3. The laboratory procedure consisted of (1) injecting pure n-dodecane (n-C12H26) into a vessel containing a core which had been moistened hygroscopically and vacuumed, and raising and maintaining pressure at 1500 psia for several days or weeks to saturate the core with n-dodecane; (2) dropping the vessel pressure and temperature to laboratory ambient conditions to determine how much oil had entered the core; (3) injecting gas into the n-dodecane saturated core at 1500 psia for several days or weeks; (4) shutting in the core flooding system for several days or weeks to allow gas in the fractures to interact with the matrix oil; (5) finally, producing the EOR oil by depressurization to room pressure and temperature. Thus, the gas injection EOR is a ‘huff-and-puff’ process.\u0000 The primary expansion-drive oil production with no dissolved gas from fractured Wolfcamp cores was 5% of the initial oil in place (IOIP) and 3.6% of IOIP in stacked synthetic cores. After injecting CH4/CO2 gas mixtures, the EOR oil recovery by expansion-drive in Wolfcamp core was 12% of IOIP and 8.2% of IOIP in stacked synthetic cores. It is to be noted that the volume of the produced oil from Wolfcamp cores was 0.27 cm3 while it was 6.98 cm3 in stacked synthetic cores. Thus, while synthetic cores do not necessarily represent shale reservoir cores under expansion drive and gas-injection EOR, these experiments provide a means to quantify the oil recovery mechanism of expansion-drive in shale reservoirs.\u0000 The gas injection EOR oil recovery in Wolfcamp cores with no fractures yielded 7.1% of IOIP compared to the case of one fracture and two fractures which produced 11.9% and 17.6% of OIP, respectively. Furthermore, in the no-fracture, one-fracture, and two-fracture cores, more EOR oil was produced by increasing the CO2fraction in the injection gas mixture.\u0000 This research provides a basis for interpreting core flooding","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"88 2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128988699","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":"Microscale Dynamics of Oil Connectivity and Mobilization by Controlled-Ionic-Composition Waterflooding at Evaluated Temperature Using Synchrotron 3D X-Ray Microscopy","authors":"Tianzhu Qin, P. Fenter, M. Alotaibi, S. Ayirala","doi":"10.2118/209384-ms","DOIUrl":"https://doi.org/10.2118/209384-ms","url":null,"abstract":"\u0000 Controlled-ionic-composition waterflooding improves oil displacement efficiency in heterogeneous carbonate rocks. Recent microscale experimental studies confirm that the injection of brines containing high sulfate ion concentrations alters the wettability of the pore surfaces and improves oil mobilization at elevated temperature. However, the dynamics of associated with changes in the microscale brine/oil/rock interactions at typical field flow rates is unclear due to the limited temporal resolutions of leading micro-CT scanners, which often require hours for data acquisition.\u0000 The goal of this study is to investigate microscale dynamics of oil connectivity and mobilization by controlled-ionic-composition waterflooding at evaluated temperature using synchrotron-based 3D X-ray microscopy. Heterogeneous carbonate rocks were saturated and aged with formation brine and oil at 90 °C, then flooded with brine containing different ion types and concentrations at 90 °C. Each flooding cycle was visualized using 3D X-ray microscopy at Advanced Photon Source. This source is the brightest hard X-ray source in the U.S. and therefore enables us to visualize the oil displacement at high temporal resolutions (45s). The experimental results show that injection brine containing high sulfate concentration rapidly increases the oil connectivity across the porous medium within the first few minutes and consequently improves oil recovery from pores regardless of pore sizes.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114224843","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":"Successful Implementation of an EOR Field-Trial Using Surfactant Induced Wettability: Formulation Design, Implementation & Interpretation and Key Lessons Learned","authors":"Neeraj Rohilla, Amit Katiyar, Amit Kumar, Peter Hutson, P. Rozowski, Adriano Gentilucci","doi":"10.2118/209393-ms","DOIUrl":"https://doi.org/10.2118/209393-ms","url":null,"abstract":"\u0000 Wettability Alteration from oil-wet to water-wet condition is a very promising EOR technique for producing significant incremental oil recovery from oil-wet tight pores. A thorough lab program led to development of a wettability altering surfactant formulation and was validated via various laboratory Coreflood tests. Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique was implemented in an offshore carbonate reservoir. The field implementation was done in a systematic step wise manner to mitigate the risk in implementing such a technology field wide.\u0000 An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases).\u0000 Reservoir modelling, logistical challenges, Environmental Health & Safety (EH&S) considerations, field applicability, and cost implications were considered for determining the optimum solution to help de-risk field scale implementation. A long term surfactant injection pilot was then conducted to evaluate efficacy of developed solution at field scale. This paper presents a phased approach to scale up an EOR project in a highly complex offshore carbonate field. Post surfactant injection, a rigorous Monitoring and Surveillance program was put in place to carefully monitor production data and quantify incremental oil gains. The pilot demonstrates the value of a phased approach to implement and monitor EOR project in an offshore carbonate field. Injection-Production data analysis shows no adverse effects at injector and significant volumes of incremental oil produced making the trial a technical as well as economic success.","PeriodicalId":437331,"journal":{"name":"Day 3 Wed, April 27, 2022","volume":"136 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-04-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115691112","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}