Day 2 Tue, June 29, 2021最新文献

{"title":"Analysis of Nitrogen Minimum Miscibility Pressure MMP and Its Impact on Instability of Asphaltene Aggregates - An Experimental Study","authors":"Mukhtar Elturki, Abdulmohsin Imqam","doi":"10.2118/200900-ms","DOIUrl":"https://doi.org/10.2118/200900-ms","url":null,"abstract":"\u0000 Minimum miscibility pressure (MMP) is a critical parameter when undergoing miscible gas injection operations for enhanced oil recovery (EOR). Miscibility has become a major term in designing the gas injection process. When the miscible gas contacts the reservoir oil, it causes changes in the basic oil properties, affecting reservoir oil composition and equilibrium conditions. Changes in conditions may also favor flocculation and deposition of organic solids, mainly asphaltene, which were previously in thermodynamic equilibrium. The main purpose of this study is to investigate how the most important parameters, such as oil temperature and oil viscosity, could affect the nitrogen (N2) MMP and the instability of asphaltene aggregation. Three sets of experiments were conducted: first, the determination of MMP was performed using a slim-tube packed with sand. The impact of crude oil viscosity using 32, 19, and 5.7 cp; and temperature using 32, 45, and 70 °C, were investigated. The results showed that the N2 MMP decreased when crude oil temperature increased. The temperature is inversely proportional to the N2 MMP due to the N2 remaining in a gaseous phase at the same conditions. In terms of viscosity, the MMP for N2 was found to decrease with the reduction in oil viscosity. Second, the effect of miscibility N2 injection pressure on asphaltene aggregation using 750 psi (below miscible pressure) and 1500 psi (at miscible pressure) was investigated using a specially designed filtration vessel. Various filter membrane pores sizes were placed inside the vessel to highlight the effect of asphaltene molecules on plugging the unconventional pore structure. The results demonstrated that increasing the pressure increased asphaltene weight percentage. The asphaltene weight percent was higher when using miscible injection pressure compared to immiscible injection pressure. Also, the asphaltene weight percentage increased when the pore size structure decreased. Finally, the visualization of asphaltene deposition over time was conducted, and the results showed that asphaltene particles started to precipitate after 2 hours. After 12 hours, the colloidal asphaltenes were fully precipitated.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115285859","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":"Optimising Oil Field Net Present Value with Produced Water Salinities and Tracers","authors":"B. Daramola","doi":"10.2118/200941-ms","DOIUrl":"https://doi.org/10.2118/200941-ms","url":null,"abstract":"\u0000 This paper presents case studies of how produced water salinity data was used to transform the performance of two oil producing fields in Nigeria. Produced water salinity data was used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production.\u0000 A reservoir simulation study was unable to history match the water cut in 3 production wells in Field B. Water salinity data enabled the asset team to estimate the arrival time of injected sea water at each production well in oil field B. This improved the reservoir simulation history match, increased model confidence, and validated the simulation model for the placement of infill drilling targets. The asset team also gained additional insight on the existing water flood performance, transformed the water flooding strategy, and added 9.6 MMSTB oil reserves.\u0000 The asset team at Field C was unable to recover oil production from a well after it died suddenly. The team evaluated water salinity data, which suggested scale build up in the well, and completed a bottom-hole camera survey to prove the diagnosis. This justified a scale clean-out workover, and added 5000 barrels per day of oil production. A case study of how injection tracer data was used to characterise a water injection short circuit in Field D is also presented.\u0000 Methods of using produced water salinity and injection tracer data to manage base production and add significant value to petroleum fields are presented. Produced water salinity and injection tracer data also simplify water injection connectivity evaluations, and can be used to justify test pipeline and test separator installation for data acquisition.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"84 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124128352","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":"Investigation of Reduced Interfacial Tension by Surfactant Flooding in Mixed-Wet Reservoirs","authors":"U. Aslam","doi":"10.2118/200902-ms","DOIUrl":"https://doi.org/10.2118/200902-ms","url":null,"abstract":"\u0000 Surfactant flooding has long been considered a reliable solution for enhanced oil recovery, either by reducing oil-water interfacial tension (IFT) or through wettability alteration. This paper reveals the effect that reduced IFT has on capillary trapping in heterogeneous reservoirs. This effect is investigated through various numerical experiments on different simulation models where rock capillary pressure is assumed to scale with IFT. Capillary contrast on the scale of a few centimeters to a few tens of meters is reduced in the presence of surfactants. This reduction in IFT, under very specific circumstances, creates favorable conditions for increased or accelerated hydrocarbon production from mixed-wet reservoirs. The focus of this study is to ascertain the effectiveness of surfactant flooding in mixed-wet reservoirs.\u0000 Simulation studies of different mechanisms which are believed to occur in mixed-wet reservoirs are presented. Simulation results indicate the promising effect of surfactant flooding on oil recovery, depending on the type of reservoir. Detailed fine-scale simulation studies are carried out with representative relative permeability and imbibition capillary pressure curves from mixed-wet cores. By designing and selecting a series of surfactants to lower the IFT to the range of 10-3dynes/cm, a recovery of 10 to 20% of the original oil-in-place is technically and economically feasible.\u0000 The efficiency of surfactant flooding is investigated through sensitivity scenarios on formation rock/fluid parameters, including permeability, interfacial tension, rate flow, etc. Geological heterogeneity (layering and heterogeneous inclusions), imbibition capillary pressure curves, viscous/capillary balance (Nc), and gravitational forces were all found to have an impact on recovery by surfactant flooding. Numerical model dimensions, permeability, IFT, density contrast between oil and water, and injection flow rates were found to be the critical parameters influencing simulation results.\u0000 Gravity segregation, typically ignored in earlier studies, was found to have a significant effect on reservoir performance. Two different numerical models, with and without impermeable shale streaks, were used to capture the gravity segregation effect. The results revealed that the reduction in interfacial tension helps gravity to segregate oil and water, ultimately resulting in improved oil recovery. Moreover, results from the numerical simulation studies revealed that either an inexpensive or a good quality surfactant at low concentration can be used to obtain the same enhanced oil recovery. The effect of change in oil relative permeability curvature, due to reduced interfacial tension, also revealed a reduction in the remaining oil saturation with an increase in the capillary number.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130491109","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":"A Potential Approach for Paraffin Control for Wells in South West Trinidad Oilfields Using Wax Inhibitors and Paraffin Solvent","authors":"Joel George King, K. Francis-LaCroix, C. Orosco","doi":"10.2118/200966-ms","DOIUrl":"https://doi.org/10.2118/200966-ms","url":null,"abstract":"\u0000 Paraffin deposition in production tubing and flow lines is a phenomenon that affects many oil producers. Once paraffin wax has precipitated there is a tendency to agglomerate peripherally to the production flow path which eventually leads to a sectional decrease in tubing or, even, flow blockage across production zones. The impact of paraffin deposition ranges from wellbore issues, flow assurance challenges to total production impairment. In many mature fields, paraffin remediation can be challenging when deposition occurs in the formation especially in near-wellbore regions of producing wells. Temperature loss at these locations induces wax crystallization and subsequent formation damage.\u0000 A mitigative approach to paraffin deposition in these areas can typically include the utilization of both paraffin inhibitors and paraffin solvents individually or in combination. However, as it pertains to paraffin remediation downhole, inhibitor placement in the formation or at near-wellbore has proven to be very challenging. This paper reviews the performance of two main chemical applications applied to address downhole wax deposition in a well from a South West Trinidad oilfield. The paper also discusses the strategy behind identifying the chemical type for the application and considerations for the placement of the chemical treatment to impact its intended target based on well data and well infrastructure.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126729153","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":"Experiments and Simulation on Integrated Approach of CO2 EOR and Storage in Mature Reservoirs","authors":"Rui Wang, Chengyuan Lv, Liu Xuan, Tang Yongqiang, Maolei Cui, Zhao-peng Yang","doi":"10.2118/200980-ms","DOIUrl":"https://doi.org/10.2118/200980-ms","url":null,"abstract":"\u0000 CO2 storage mechanisms in an EOR process in mature reservoirs are measured to determine three types of storage factors, which are introduced into compositional numerical simulation. The hybrid objective function coupli ng the oil recovery factor and the CO2 storage ratio is proposed to optimize the injection and production parameters in CO2 flooding. Three storage factors of the oil and water partition coefficient, the permeability change coefficient and the CO2 retention factor are measured in a laboratory, which is utilized to modify the grid properties of oil, brine, rock in compositional numerical simulation. The restart procedure is automatically adopted to consider these storage mechanisms in CO2 EOR. The bi-objective function of the oil recovery factor and the CO2 storage ratio is used to optimize the injection and production parameters for CO2 EOR, which concludes the design principles on CO2 EOR and storage. The oil and water partition coefficient defined as the ratio of the CO2 solubility in the oil phase and the brine phase is a constant for a specific reservoir condition. The permeability change coefficient caused by the mineral dissolution effect of carbonate water decreases slightly in the early stage and increases gradually with the long term injection. The CO2 retention factor that is induced by the relative permeability hysteresis decreases with the pressure and the permeability. These equivalent treated methods that modify fluids and rock in the real-time are inserted into the procedure of compositional numerical simulation to take into account the storage mechanisms in CO2 EOR. The results show that the effect of the storage mechanisms on EOR is evident. Furthermore, the bi - objective optimization indicates that the injection rate should be reduced largely in the medium and the later stages to control gas channeling as the EOR scenario is focused. And the bottom wellhole pressure of producers should be decreased to the lower level to maximize oil recovery. As the storage scenario is concentrated, the injection rate is required to be slightly controlled. As the producers are shut off, the injection rate must be increased significantly to maximize CO2 storage. The storage mechanisms in the CO2 EOR process have not been understood thoroughly. The methodology of numerical simulation coupling CO2 EOR and storage is not mature, which is still not taken into account in commercial software. The results above provide a way to optimize CO2 EOR and storage simultaneously, which is significant for the large scale storage after CO2 EOR in mature oilfield.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124077828","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":"Improving Production Forecasting in a Mature Onshore Oilfield Brownfield in Southern Trinidad by Making Use of Software Modeling","authors":"S. Paul, G. Dukhoo, Murchison Phillip, Jediael Persadsingh","doi":"10.2118/200953-ms","DOIUrl":"https://doi.org/10.2118/200953-ms","url":null,"abstract":"\u0000 In Trinidad's mature onshore oilfields, operators have traditionally forecasted the initial production rates back calculated from decline models. These rates, then reduced annually by a predetermined decline model has been used to evaluate financial feasibility. This method does not make use of the reservoir pressure. This paper demonstrates how software modelling, utilizing the reservoir pressure can reasonably forecast the performance of low rate oil producers and alert the operator of the need for artificial lift from the inception of the production cycle.\u0000 The objectives of the project were to determine remaining recoverable reserves, evaluate the potential for redevelopment (workovers and infill drilling) and to demonstrate that software modeling can be used to forecast production for an oil reservoir in a mature onshore oilfield in Southern Trinidad. Petroleum Experts Integrated Production Modeling (IPM) software suite was used for building all models. A comparison of the production forecasted by software modelling and the traditional method of forecasting initial production rates by back calculating from decline models was also undertaken.\u0000 Using the available data and net oilsand maps, the fault block bulk volumes, oil in place and the remaining reserves were determined. These results were then used to identify fault blocks with potential workover well candidates and infill well locations. Research of well files and well logs were used in evaluating zones for potential recompletions, reperforation or perforation of additional footage for production. Forecasting and comparison of the initial production rates and ultimate cumulative production for the proposed infill wells and recompletions using the traditional IP/Decline model method and computer modeling was then performed.\u0000 Form the data available, it was determined there were four blocks with remaining reserves that could be successfully recovered. The recovery methods proposed included the workover of two existing wells and drilling of two infill wells. Initial production rates and ultimate production volumes obtained by modeling of workover and new well performance had reasonably close agreement with those obtained by the traditional IP/Decline models. The results of the modeling, however indicated that all the wells required the use of pumping mechanisms (sucker rod/beam pumps) to sustain production over a ten-year period. The need for this important production mechanism would not have been realized from the IP/Decline method. An important distinction is that the modelling makes direct use of the reservoir pressure, whereas the IP/Decline model does not.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"111 3S 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122490811","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 Particulate Diverter During Acid Treatments Progress in Carbonate Assets in Northern Region of Mexico","authors":"E. Medina, Alejandro Flores, K. Campos","doi":"10.2118/200896-ms","DOIUrl":"https://doi.org/10.2118/200896-ms","url":null,"abstract":"\u0000 Enhancing stimulation treatments in carbonate reservoirs is a continuous process that includes input from previous operations and production results. Individually, stimulation provides an opportunity to improve the treatment design by means of various factors, such as changes to rates and volumes, new fluid designs, use of nitrogen to increase energy and recover additional fluid after the operation, changes to the well completion, novel diversion techniques, and additional additives. These factors affect overall optimization of fluid distribution. This paper discusses the use of particulate diverter systems during acidizing treatments and highlights how such treatments have progressed. A case study of a carbonate formation in northern Mexico is also presented.\u0000 A carbonate field in northern Mexico was analyzed in 2010 to implement a stimulation treatment. The operations ranged initially from reactive and nonreactive stimulation treatments at low-pumping rates to hydraulic acid fracturing in a single formation. After understanding the use of hydraulic acid fracturing in a single zone, multiple formation zones were fractured to improve production while introducing changes in the well completion to enable a faster operation. Multiple acid fracturing treatments during a single intervention were performed with a particulate diversion material to increase the zonal coverage. The successful diversion application has been documented using diagnostics, such as temperature profiles and radioactive tracers.\u0000 When a reactive and nonreactive stimulation treatment was performed, the average production in the field was 30 BOPD. Later, with the implementation of hydraulic acid fracturing in a single interval (more than 20 fracturing operations), the average production per well increased to 100 BOPD. More recently, in the last 15 wells, the application of fracturing improvements and the stimulation of two to three zones using particulate diversion to distribute the fluid achieved average production results of approximately 300 BOPD. These results represent a threefold increase since the initial fracturing operations and a tenfold increase since stimulation operations began in the field.\u0000 Improvements in acid diversion techniques using particulate diverters has provided significant advantages by enabling effective treatment of several zones in one step, without stopping the operation. This paper describes the design and implementation of the diverting system used during the case study to improve production in a carbonate formation.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129516241","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":"New Technology Allows for Hands-Off Intervention During Cementing Operations Increasing Safety and Operational Efficiency","authors":"Michael Ramon, Tony Wooley, Kyle Martens, Amy L. Farrar, Seth Fadaol","doi":"10.2118/200961-ms","DOIUrl":"https://doi.org/10.2118/200961-ms","url":null,"abstract":"\u0000 The culture of safety within the oil and gas industry has undergone an evolution since the advent of significant E&P operations in the late 1800s. The initial focus on safety was to protect property, not people. This mentality has shifted over time to include a greater focus on the safety of personnel, in parallel with technology developments that have pushed the limits of operators’ and service providers’ abilities to drill and complete more complicated wells. The safety efforts introduced to date have yielded results in every major HS&E category; however, falls and dropped objects continue to be areas in need of improvement.\u0000 During cementing rig up and operations there are still many manual activities that require working at heights in the derrick. New technological advances have allowed the industry to reduce the number of hands-on activities on the rig and operators have moved to eliminate these activities by automating operations. Man lifting operations are recognized as a high-risk activity and, as such, many rigs require special permitting. During cementing operations, not only are personnel lifted into hazardous positions, but they are usually equipped with potential dropped objects. Some of these objects, if dropped, reach an impact force that could seriously injure or, in worst cases, result in a fatality. During these operations, personnel are also hoisted along with a heavy cement line in very close proximity. This introduces other dangers such as tangling, pinch points, and blunt force trauma. These risks are heavily increased when working in adverse conditions, such as high winds or rough seas. By utilizing a wireless cement line make up device, along with wireless features on a cement head to release the darts/plugs/balls and operate the isolation valves, an operator can eliminate the need for hands-on intervention.\u0000 This paper will discuss current cement head technologies available to the operator that allow them to improve safety and efficiencies in operational rig time. Three field studies will be presented that detail running cement jobs with all functions related to the wireless attributes of the cement head. The field studies will present the operational efficiencies achieved by utilizing the wireless features compared to the standard manual method.\u0000 Before the recent introduction of a wireless cementing line make-up device, a wireless cement head still required hands-on intervention to rig up the tools, putting people in high-risk situations.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133251898","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":"Proposal EOR Fiscal Incentives to Increase the Recovery Factor in Mexican Fields Implementing Enhanced Oil Recovery Methods through Sensitivity Analysis with Different Contracts","authors":"O. Espinola, F. Núñez, Pedro Tomas Malibran","doi":"10.2118/200916-ms","DOIUrl":"https://doi.org/10.2118/200916-ms","url":null,"abstract":"\u0000 The current business strategy of Operators in Mexico has considered finance Enhance Oil Recovery projects. Moreover, the potential in Mexico for EOR is represented by 80% of the total production coming from mature fields. However, these projects are difficult to be executed below current circumstances, oil prices and existing fiscal terms. For this reason, there is an opportunity to evaluate how to switch the situation and generate scenarios where it might be possible to perform such as complex project.\u0000 Therefore, this study presents a methodology from a technical and economical perspective that includes the selection of a representative reservoir, evaluating different production forecast scenarios below EOR schemes, comparing fiscal models and running sensitivity analysis to end up with an incentive adjustment, to evaluate the potential benefits of fiscal incentives and how they could be applied effectively to EOR implementation projects.\u0000 To demonstrate the potential of these projects in Mexico, a reservoir with specific characteristics had been selected to simulate the performance of a mature field where thermal pilot projects are conceptualized. Nevertheless, the focus of this study is to evaluate the current fiscal terms and taxes versus innovative fiscal terms with applied incentives.\u0000 This work pursuits to find a window of opportunity for complex projects that embraces current oil prices, appropriate fiscal terms, tax incentives, and technical considerations. Overall, the proposed methodology defines how to apply the appropriate incentive in combination with several parameter to enable the execution of these projects.\u0000 Finally, as a result of this study, it had been demonstrated that at given conditions and adding a package of incentives, there is a win-win schema where the Government and the Operators obtain higher returns than the conditions of exploiting the fields only with natural depletion. These proposed conditions can be used to promote economic benefits that encourage EOR projects and attract investment in Mexico, and consequently, increase recovery factor of mature fields.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115244982","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":"Experimental Analysis of the Effects of Varying Temperature and Viscosities on Foamy Oil Production","authors":"Jasmine Shivani Medina, Iomi Dhanielle Medina, Gao Zhang","doi":"10.2118/200919-ms","DOIUrl":"https://doi.org/10.2118/200919-ms","url":null,"abstract":"\u0000 The phenomenon of higher than expected production rates and recovery factors in heavy oil reservoirs captured the term \"foamy oil,\" by researchers. This is mainly due to the bubble filled chocolate mousse appearance found at wellheads where this phenomenon occurs. Foamy oil flow is barely understood up to this day. Understanding why this unusual occurrence exists can aid in the transfer of principles to low recovery heavy oil reservoirs globally.\u0000 This study focused mainly on how varying the viscosity and temperature via pressure depletion lab tests affected the performance of foamy oil production. Six different lab-scaled experiments were conducted, four with varying temperatures and two with varying viscosities. All experiments were conducted using lab-scaled sand pack pressure depletion tests with the same initial gas oil ratio (GOR).\u0000 The first series of experiments with varying temperatures showed that the oil recovery was inversely proportional to elevated temperatures, however there was a directly proportional relationship between gas recovery and elevation in temperature.\u0000 A unique observation was also made, during late-stage production, foamy oil recovery reappeared with temperatures in the 45-55°C range.\u0000 With respect to the viscosities, a non-linear relationship existed, however there was an optimal region in which the live-oil viscosity and foamy oil production seem to be harmonious.","PeriodicalId":332908,"journal":{"name":"Day 2 Tue, June 29, 2021","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121921232","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}