Day 1 Wed, June 28, 2023最新文献

{"title":"Rejuvenation of Watered-Out Fractured Carbonate Horizontal Well by Microgel/Gel Injection","authors":"N. Gaillard, G. Omonte, J. Bouillot, A. Zaitoun, F. Duboin, C. Bertrand","doi":"10.2118/213838-ms","DOIUrl":"https://doi.org/10.2118/213838-ms","url":null,"abstract":"\u0000 In a world where oil production declines and where investments in fossil resources are lower and lower, operators are looking for solutions to optimize the production of existing wells. This is the case for horizontal wells in carbonate formations suffering from channeling with strong bottom aquifer. Such problem occurred for well MRS-1H located in France. Its production started in 2001 with high water-cut (80-85%) that increased rapidly with time to reach 99.7% in 2022 for a gross production of 5000 bpd. Even with a barrel at 80 USD, the extraction of oil in such conditions is not economical due to the high OPEX required for pumping and water disposal. A Water Shutoff (WSO) treatment was designed having as target to decrease water production by, at least, a factor of 2, while keeping the volume of oil production at same level.\u0000 The bottom aquifer is located in the very permeable Upper Bathonian formation, just below Lower Callovian formation. Oil in place is 36° API with a viscosity of 3.3 cp. Reservoir temperature and pressure are 70 °C and 186 bar respectively. Reservoir water salinity is between 5 to 10 g/L TDS.\u0000 The main problem is the presence of a channeling connection between the well and the aquifer by a fracture network localized close to the heel of the horizontal drain. WSO treatment consisted in injecting by bullheading a first slug of microgel followed by a slug of elastic gel followed by a third slug of microgel. The total volume of the chemical treatment was 300m3.\u0000 During the injection, wellhead pressure increased and remained stable below 60 bar for an injection rate of 3bpm. The fact that pressure did not build up (especially during the injection of the gel slug) indicates that the treatment penetrated in low resistance flow areas (fractures). After 15 days of shut in, the well was put back on production, showing a dramatic drop of gross production rate, reaching 630 bpd while it was 5000 bpd before the treatment. The oil production reached 17 bpd corresponding to an oil cut of 2.5% (compared to 0.3% initially). The well has kept this behavior with time, making its production economical.\u0000 The bullhead treatment combining microgel and gel proves to be a good WSO strategy for wells suffering from strong bottom aquifer channeling and should have many applications in fractured carbonate reservoirs.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"318 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124498932","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":"Kinetic Experimental and Modeling Evaluations of Asphaltene Morphology and Growth Rate under Varying Temperature and Brine Conditions","authors":"Kwamena Ato Quainoo, Imqam Abdulmohsin, Cornelius Borecho Bavoh","doi":"10.2118/213811-ms","DOIUrl":"https://doi.org/10.2118/213811-ms","url":null,"abstract":"\u0000 The utilization of predictive mechanisms to resolve asphaltene precipitation during oil production is a cleaner and less expensive means than the mechanical/chemical remediation techniques currently employed. Existing models lack predictive success due to opposing views on temperature-asphaltene precipitation interactions. In this study, the effect of varying temperatures (40, 50, 60, 70 80 and 90 °C) and brine concentrations (0 – 5 wt.%) on the long-time kinetics of asphaltene precipitations was evaluated. A series of experiments were conducted using the filtration technique and the confocal microscopy to study asphaltene precipitation on a model oil system consisting of asphaltenes, a precipitant, and a solvent. Furthermore, the Avrami modeling technique was employed to predict the morphology, and growth rate of the precipitating asphaltenes. The experimental results suggested that temperature significantly affects asphaltene precipitation including imparting its precipitation mechanism with a cross-behavioral pattern. Asphaltene precipitation in the system displayed an initial fast kinetics upon increasing temperature. The fast kinetics observed in the early times is due to the increasing dipole-dipole interactions between asphaltene sub-micron particles stimulated by increased temperature. However, the pattern changes into slower precipitations as the time progresses upon continuous heating of the reservoir fluid. The reason is the increased solubility of the asphaltenes imparted into the model oil system upon further increments in temperature. The presence of brine in the model-oil system also enhanced the rate and precipitation of asphaltenes. The experimental data were further analyzed with the Avrami crystallization fitting model to predict the formation, growth, morphology, and growth geometry of the precipitating asphaltenes. The Avrami model successfully predicted the asphaltene morphologies, growth rates and the crystal growth geometries. The growth geometries (rods, discs, or spheres) of the asphaltenes in the model oil systems upon temperature increments, ranged from 1.4 – 3.5. These values are indicative that temperature impacts the growth process of asphaltenes in the model system causing variations from a rod-like sporadic process (1.0 ≤ n ≤ 1.9) to a spherical sporadic growth process (3.0 ≤ n ≤ 3.9). This work precisely emphasizes the impact of temperature on asphaltene precipitations under long kinetic time, thus, providing a clear pathway for developing successful kinetic and thermodynamic models capable of predicting asphaltene precipitation reliably. The accurate prediction of asphaltene precipitation will eliminate the need for the use of harmful remediation solvents like benzene/toluene/ethylbenzene/xylene (BTEX). This study is therefore a critical step in the right direction to achieving accurate predictive model evaluations of asphaltene precipitations.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"155 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133685122","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":"The Impact of Variations in Water and Gas Flow Rates on Scaling Potential of Carbonate Reservoirs Under CO2-WAG Injection","authors":"Patricia Braga Gusmao, E. Mackay","doi":"10.2118/213864-ms","DOIUrl":"https://doi.org/10.2118/213864-ms","url":null,"abstract":"\u0000 This paper uses reactive transport modelling to analyse the impact of variations in the water and gas injection flow rates from a geochemical perspective on the scaling potential of carbonate reservoirs under CO2-WAG injection. A sensitivity analysis of the calcite saturation index is performed for different water and gas injection flow rates. Geochemical properties of the injection fronts are analysed through the reservoir.\u0000 The study is carried out using a 1D model of water-alternating-gas injection, assuming a light oil with 1.2% CO2 concentration, desulphated seawater injection and calcite as the rock substrate. The reactive transport modelling is performed using a commercial compositional reservoir simulator with the WOLERY database. Pressure, temperature, formation water (FW) and injected water (IW) compositions are based on published data. The scale potential is measured by calculating the saturation index and water production rates.\u0000 Results show that calcite dissolution occurs continuously in the block closest to the injection well, and equilibrium is not reached in this region during water injection, but it is reached during CO2 injection. The extent of the reaction decreases from the injector to the producer well because the fluid becomes more saturated with CO2 as it flows through the reservoir. The reaction also decreases as the water and gas injection flow rates decrease, mainly due to the reduced volume throughput. The reactions during the water injection part of the cycle occur further away from the waterflood front as the water injection rate declines, and the reactions during the CO2 injection part of the cycle occur further away from the gas flood front as the CO2 injection rate declines. The system takes longer to reach equilibrium at lower flow rates, and so the water composition varies for longer. In the highest water flow rate model, it takes a very short time to reach equilibrium after the water breakthrough in the producer well. In the lowest water flow rate model, it takes more than five times as long.\u0000 This work indicates the previously unreported finding that the water and gas injection flow rates may affect the geochemical equilibrium in the reservoir, specifically demonstrating that the reactions during the non-equilibrium stage may occur further away from the water and gas flood fronts, depending on the water and gas flow rates.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122574468","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":"Physicochemical Phenomena of Diffusion Relaxation: Experimental Results and Application for Acid Stimulation Operations","authors":"Igor B. Ivanishin, Viacheslau Y. Kudrashou","doi":"10.2118/213810-ms","DOIUrl":"https://doi.org/10.2118/213810-ms","url":null,"abstract":"\u0000 Accurate prediction of the rock dissolution process is crucial for designing efficient acid stimulation treatments. At typical conditions, the dissolution of carbonates in most acids is limited by the rate of convective diffusion of reactive species to the surface of the rock. The experimental techniques used to determine the acid-diffusion coefficient are comparably well-understood by the research and engineering community. However, one important physicochemical phenomenon termed diffusion relaxation has not been studied in detail and accounted for in all the existing acid fracturing and matrix acidizing modeling software programs. The objective of this work is to address these gaps in research and optimize acid treatment designs. Diffusion relaxation occurs downstream of an inert or less reactive rock layer and results in higher mass transfer, i.e., dissolution rate of the rock located immediately downstream of an inert layer. To study the process of diffusion relaxation, 15 wt% hydrochloric acid at a temperature of 150°F was injected through a composite acid fracture model. This model was prepared by inserting 0.5 and 0.25 in.-long sandstone layers into a standard 7 in.-long fracture model made of Indiana limestone. Laser profilometry of the fracture surfaces after the experiment revealed the presence of 0.1 in.-deep channels of more etched limestone downstream of inert layers, as compared to the upstream of inert layers. The zone of an enhanced dissolution rate—termed diffusion relaxation zone—extends to a distance comparable to the length of an inert layer and appears because of the following. As soon as the acid flow encounters inert areas, the concentration of reactive species at the fracture surface starts to accumulate since there is no dissolution reaction. Right downstream the inert areas, the limestone surface contacts with the acid that has not been spent by the diffusion of reactive species. Because of that and an impact of tangential mass transfer in the diffusion boundary layer, downstream of inert areas the diffusional mass transfer significantly—often more than two times—exceeds the limiting mass transfer established upstream of the inert areas. Etched channels formed in diffusion relaxation zones contribute to the fracture conductivity, which is not considered in existing modeling software programs. Results indicate that the observed phenomenon is universal, i.e, it also occurs during dissolution of rocks with different reactivities. This research innovatively discusses the impact of physicochemical phenomena of diffusion relaxation on the dissolution of carbonate rocks, and formation of conductive flow channels. Presented results are integral for designing acid stimulation operations.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122802928","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":"An Innovative and Sustainable Portland Cement Alternative for Oil and Gas Wells","authors":"Andrey A. Yakovlev, V. Lafitte, S. Kapoor, M. Meade, W. Smith, Nathan Fischer, C. Parton, Veronica Richter McDonald, Yeukayi Nenjerama, Xia Wei, G. Landry","doi":"10.2118/213805-ms","DOIUrl":"https://doi.org/10.2118/213805-ms","url":null,"abstract":"\u0000 The manufacturing process of oilfield cement is one of the largest contributors to carbon emissions. Thus, finding sustainable alternative materials has become the main focus globally. Geopolymers are low carbon cement alternatives that have been used in the construction industry for many years, yet their applicability for oil and gas wells remains unproven.\u0000 For geopolymers to be successfully implemented in the oilfield industry, a customization of the formulation is critical to eliminate logistical constraints and ensure compatibility with oilfield pumping equipment. Geopolymers are typically prepared with liquid alkaline activators, which render them impractical for onshore applications due to the complicated logistics of transporting liquids to a wellsite. Dry blending of the various components and handling constraints is an important condition for field use.\u0000 A comprehensive lab study of geopolymer activator and functional additives was conducted. In the end, unique chemistries were identified that are compatible with dry blending and continuous live mixing for field application. A key focus was given to achieving parameters needed from operations, and compliance perceptive, and those which are comparable to the oilfield cements currently in use. Introducing an innovative geopolymer solid activator package enables mixing and pumping of geopolymer slurries without any modification of the current equipment or the job execution method and eliminate the need to handle corrosive liquids. After extensive lab studies, mixability, and pumpability of the newly designed geopolymer system was validated via yard trials.\u0000 The current work has opened new avenues to make geopolymers adaptable to cementing land equipment while meeting the requirements needed to sustain performance under well conditions. This is a step change toward field deployment of a sustainable well integrity technology.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"44 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131474548","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":"Clues from Dispersion and Deposition Based Test Methodologies to Solve the Asphaltene Jig-Saw Puzzle","authors":"A. Punase, W. Burnett, J. Wylde","doi":"10.2118/213829-ms","DOIUrl":"https://doi.org/10.2118/213829-ms","url":null,"abstract":"\u0000 Changing thermodynamic and compositional conditions of producing fields can cause decreased asphaltene stability and initiate aggregation, subsequent precipitation, and eventual deposition within flowlines. Usage of asphaltene inhibitors that prevent aggregation and tackle the problem right at the inception is widely preferred. However, such chemistries were observed to be counter-productive and led to higher asphaltene deposition in many cases. Thus, raising the question of what approach works best for assessing asphaltene stability: Dispersion or Deposition?\u0000 The focus of this study is to explore the relationship between the underlying working mechanism of dispersion and deposition-based test methods. Multiple crude oil samples produced from different regions of the world were evaluated using asphaltene inhibitor chemistries with optical transmittance, thermo- electric, and flow loop methods. Optical transmittance method evaluates sedimentation rate and cluster size distribution of asphaltene cluster within the test fluid medium. Thermoelectric method describes the dispersion state of asphaltenes within native crude oil. Flow loop setup assesses total mass deposited when the oil (blank or dosed) and precipitant mixture is flown through capillary tubes.\u0000 The results from these tests indicated that a fine balance between the dispersion and deposition mechanisms must be maintained as these may not respond linearly or in direct relationship at all conditions. It was seen that dispersing the asphaltene clusters too small may lead to high diffusional rate within the low flow shear regime and build up more deposit in depositional dominant test methods. Variation in treatment concentration (especially overtreatment) of an effective asphaltene inhibitor can result in lowering of cluster size to a range which in effect can cause more deposition. The overall assessment suggests that not having a holistic overlook at these test methods and following the standard process of giving specific focus on a singular approach, can mislead the asphaltene stability and inhibitor performance evaluation.\u0000 The key role of asphaltene cluster size as a bridge relating the dispersion and deposition-based test method is revealed in this paper. It is seen that there exists an effective range of cluster size within which the results from different test methods correlate well. Therefore, it is imperative that the asphaltene inhibitor development philosophy must include test screening methods focusing on each instability stage (precipitation, aggregation, and deposition) individually and combine the learnings to come up with the best recommendation.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"27 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124060892","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 Novel AMD Nanosheet and Surfactant Synergy System to Increase Oil Production under Harsh Reservoir Conditions","authors":"D. Cao, M. Han, Mohanad M. Fahmi, A. AlSofi","doi":"10.2118/213789-ms","DOIUrl":"https://doi.org/10.2118/213789-ms","url":null,"abstract":"\u0000 Amphiphilic molybdenum disulfide (AMD) nanosheet is a novel flake type nanomaterial for increasing oil production. It shows unique behaviors on oil/water interface as the flake nature compared with particulate nanomaterials. However, nanosheet solution in high salinity water at elevated temperature had poor compatibility, which limited the applications at harsh reservoir conditions. An improved nanosheet system synergetic with a cationic surfactant was developed and showed good compatibility improvement at 95°C and salinity as high as 57,670 mg/L. The interfacial tension (IFT) of the developed nanosheet and surfactant system with crude oil was not ultra-low, but it showed excellent interfacial activities in emulsification tests and phase behavior tests even at low concentrations. Nanosheet produced much stable emulsion than surfactant. Mixing nanosheet and surfactant increased emulsion stability. The hydrophilic and lipophilic balance of the nanosheet and surfactant system could be controlled by surfactant concentration. Winsor III type microemulsion was formed at nanosheet/surfactant concentration ratio of 1:2 to 1:8. For the performance in porous media, the surfactant component reduced the retention of nanosheet and decreased the plugging to the cores. Corelfooding tests in limestone and carbonate cores demonstrated the good incremental oil production performance of the nanosheet and surfactant system at 95 °C. Both oil bank at early stage of nanosheet injection and a long-lasted emulsified oil contributed to the oil production. The oil production performance of nanosheet/surfactant system was affected by both concentration and concentration ratio of the two components. A 50 mg/L nanosheet and 2000 mg/L surfactant formulation showed highest oil production after waterflooding compared with other combinations.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134315490","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":"Modelling Elemental Mercury Partitioning and Transport: A Case Study of Fenris: A New Offshore High Pressure, High Temperature Gas-Condensate Field","authors":"A. R. Farrell, D. Frigo, G. Graham, B. Hugaas, Christian Vikre, J. Carney, Paul Kirchner","doi":"10.2118/213823-ms","DOIUrl":"https://doi.org/10.2118/213823-ms","url":null,"abstract":"\u0000 Mercury is highly toxic and corrosive to certain metals and is therefore a highly undesirable contaminant in produced hydrocarbons. Its concentration in reservoir fluids differs by over four orders of magnitude globally, which means its operational consequences can differ enormously. We present a case study of the Fenris field: a new, offshore HPHT gas-condensate tieback to Valhall (North Sea) in which mercury has been detected but there remains considerable uncertainty about its abundance in the fluids.\u0000 Predictions from a cubic Equation of State (EoS) model are strongly dependent on the parameter set chosen and there is not common agreement within the industry on the most suitable. Prior to field simulations, the suitability of commercially available models was evaluated by comparing outputs with literature data. Once a suitable EoS parameter set was selected, partitioning of Hg0 over all possible phases (gas, condensate, MEG-water and liquid Hg0) was evaluated for a variety of Hg0 concentrations (due to the uncertainty thereof), as well as the influence of conditions both in the subsea flowline and in the facilities.\u0000 A plausibly conservative base case was selected for the Hg0 concentration in the reservoir fluids. This allowed partitioning and transport of Hg0 to be evaluated in terms of both the quantity and concentration of Hg0 in each produced fluid stream. Specifications for mercury-removal units (MRUs) were initially set using these values. A set of simulations performed using a higher Hg0 concentration allowed for evaluation of the suitability of these values under worst-case conditions. Considerable seasonal variation was anticipated, with the fluid arrival temperature at the facilities expected to fluctuate between 0 and 10 °C with related changes in the Hg partitioning. It was identified that the greatest quantity of liquid Hg0 was expected to form in the flowline and facilities at around Year 3 following First Gas, consistent with the maximum gas rate expected over field life and winter conditions. Of particular interest is the influence of the condensation and agglomeration kinetics of liquid Hg0, which may not only change the locations where the liquid accumulates but can also affect Hg0 partitioning into the other produced phases and can therefore affect the sizing of any MRUs to achieve product specification for this contaminant.\u0000 This work describes the challenges in predicting the consequences of mercury production at FEED when its expected Hg0 concentration is significant-to-high but substantially uncertain. A conservative approach was taken in modelling quantities at various locations to ensure risk is suitably managed without adopting design specifications that unduly increase capital expenditure. The paper describes the predicted risks associated with Hg0 in this new development and the steps identified to manage risks during the upcoming production stage.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116715588","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 Flood Pilot to Recover Heavy Oil Using Heated Water","authors":"Sriram Solairaj, G. Pope, Erica Pin","doi":"10.2118/213872-ms","DOIUrl":"https://doi.org/10.2118/213872-ms","url":null,"abstract":"\u0000 The Days Chapel area of the Slocum oilfield was investigated as a target for conducting a polymer flood using heated water. The crude oil in the Carrizo zone of the Slocum oilfield is a heavy oil with an API gravity of about 19 degrees and a viscosity of about 1000 cp. The Carrizo formation is a shallow sand with high porosity and permeability. A new well was drilled for the purpose of obtaining log and core data needed to characterize the target area. Simulations using these data were used to assess its potential in this area of the field. Polymer flooding using heated water is significantly more complicated than conventional polymer flooding with respect to the surface facilities, the design and prediction of the flood, the operation of the flood, and the reservoir performance. One of the most important variables is the temperature of the heated water. Higher temperature results in lower oil viscosity, but it also results in higher heat losses from the wellbores and reservoir, and higher energy costs to heat the injected polymer solution. Injection and production rates are also key variables. Another important design variable is the duration of hot water injection before starting hot polymer flooding. Preliminary results indicate this innovative approach to polymer flooding of heavy oil zones is promising and should be evaluated in other heavy oil reservoirs.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114415738","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 Retarded Acid System for High Temperature Applications: An Efficient Alternative to Emulsified and Viscosified Acid Systems","authors":"R. Nazari Moghaddam, A. Bokkers, Koos Aaldering, P. Ferm, Cees Kooijman","doi":"10.2118/213854-ms","DOIUrl":"https://doi.org/10.2118/213854-ms","url":null,"abstract":"\u0000 Acidizing of high-temperature carbonate reservoirs faces many challenges and requires a superior retarded acid system with high thermal stability, controlled reaction rate, and acceptable corrosion profile as compared to lower-temperature formations. In this study, a novel retarded acid system is introduced to address the shortcomings of the available retarded acid systems in the market. The proposed retarded acid system is based on a unique formulation of HCl and the sodium salt of monochloroacetic acid and does not require gelation by a polymer or surfactant or emulsification in diesel.\u0000 The proposed acid system combines the use of a strong mineral acid (i.e., hydrochloric acid) with sodium monochloroacetate (HCl/SMCA). The acid system benefits from two mechanisms: 1) hindering the fast reaction of HCl and 2) in-situ acid generation by hydrolysis of SMCA towards glycolic acid which provides dissolution capacity for deeper penetration. The hydrolysis of SMCA occurs over time as acid penetrates through the formation. The HCl/SMCA system has an initial pH of 2-3, which significantly reduces corrosion rates at high temperatures. In this study, the dissolution capacity of the acid system was first measured. Then the potential risk of unwanted precipitation of the reaction products was investigated. Finally, the performances of the SMCA system at various formulations were investigated by performing coreflood experiments at high temperatures. The coreflood experiments were conducted at different injection rates to obtain the acid efficiency curve or pore-volume-to-breakthrough (PVbt) curve. Finally, corrosion experiments were conducted at high temperatures using three SMCA formulations.\u0000 From the dissolution experiments, it was found that the dissolution capacity of the HCl/SMCA acid system, containing only 6 wt% HCl, can be as high as 1 lb CaCO3 scale/gal. It was shown that the reaction products from the calcite dissolution are fully soluble and the chelation by sodium gluconate is the main responsible mechanism. From the coreflood results, it was found that the new HCl/SMCA system can efficiently stimulate limestone formations with no face dissolution. It improves the wormholing performance significantly over HCl acid only and the PVbt decreases from 2.6 to 1 at 130°C. Benefiting from the gentle nature of the acid/SMCA system, tighter formations can be treated at much lower injection rates. CT scan images confirm the favorable wormhole propagation characteristics of the SMCA formulations. It was shown that 60% of the acid capacity remained unused even at very low injection rate, showing the retardation properties of the proposed system. According to the corrosion data, when SMCA used as retarding agent the corrosivity of HCl is decreased and much lower inhibitor concentrations are needed.\u0000 The new HCl/SMCA system effectively retards initial non-uniform HCl acidizing and adds in-situ acid generation, thereby improving overall the uniformity of the ","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"214 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133806461","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}