Day 1 Wed, June 28, 2023最新文献

{"title":"Reduce Fresh Water Usage While Mitigating Scale","authors":"Minh Vo, Frances Debenedictis, N. Spurr","doi":"10.2118/213883-ms","DOIUrl":"https://doi.org/10.2118/213883-ms","url":null,"abstract":"\u0000 Current seawater fluid systems were designed to reduce the usage of fresh water and the number of trips needed to transport the water. The composition of such fluids needed gel stabilizers to reduce the negative effects high salinity waters have on fluid performance. However, in solving one problem, another potential problem may have been overlooked. Sea water when met with the formation waters can cause scale production and formation damage. The damage is often worse when wells are shut in for extended periods of time. This paper will discuss the evaluation of a scale inhibitor package for immediate and long-term scale protection that can be delivered in the seawater fracturing operation without detrimental effects to fluid performance. Traditional and nontraditional screening methods were used to demonstrate the longevity of the scale inhibitor additive. Evaluation studies consisted of inhibitor compatibility studies, static bottle testing, and fluid rheology compatibility testing. Inhibitor compatibility studies were conducted to determine the inhibitors efficacy in high calcium environments at the pH of the fracturing fluid. Static bottle longevity testing was completed over 6 weeks using various inhibitor concentrations to optimize the scale inhibitor loading across varying seawater to formation water ratios. Fluid rheology studies were performed to determine compatibility with the inhibitor.\u0000 Various loadings of the scale inhibitor were evaluated to determine the best loading across varying ratios of seawater to formation water. The scale inhibitor demonstrated that it could effectively inhibit calcium and barium scale formation for at least 6 weeks. Results were confirmed with ICP testing showing more than 80% of the cations in solution as per industry standard. The scale inhibitor had no determinantal effects to the fracturing fluid stability compared to the baseline.\u0000 The data clearly shows the potential of using a scale inhibitor package with a seawater based fracturing fluid to fracture the formation while simultaneously inhibiting any scale formation. The inhibition was shown to last a minimum of 6 weeks at temperature to simulate shut in.\u0000 The novelty of this scale package is to decrease use of fresh water and carbon footprint while providing long term prevention of scale through scale control additives. The optimized fluid and additives can provide enhanced management and protection from damaging scale deposition in HTHP wells later in the life of the well.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"10 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":"129420449","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":"Novel Modified Polycarboxylate Paraffin Inhibitor Blends Reduce C30+ Wax Deposits in South Texas","authors":"Liangrui Xu, I. Zhuk, Sofia Sirak","doi":"10.2118/213853-ms","DOIUrl":"https://doi.org/10.2118/213853-ms","url":null,"abstract":"\u0000 A typical challenge encountered during shale oil and condensate production in South Texas is severe wax deposition on fractured rock surface near the wellbore and flowlines from wellheads to separators, potentially reducing surface areas for oil and gas flow. Commonly used surfactant dispersants and wax inhibitors such as comb shaped polyacrylate/methacrylate (PAMA) and alpha-olefin modified maleic anhydride (OMAC) sometimes fall short and do not always address challenges associated with C30+ waxy crude oil and condensate. This is typically due to the mismatch of molecular weights and the incorrect ratio of polar and non-polar groups between the polymeric additive and the targeted wax species.\u0000 In this study, we present the findings of a new modified polycarboxylate and polyacrylate blend that provides a balanced approach of optimized non-polar and polar groups on the polymer backbone. Additionally, the inherent long polymer chains with a broad chain density distribution appear to interact well with C30+ waxy compounds, effectively lowering pour point, reducing wax appearance temperature (WAT) and suppressing wax deposition.\u0000 A gradual reduction of WATs in polymer treated waxy deposit was observed via DSC/CPM measurements when the polymer blends were varied with polyacrylate/methacrylate/modified carboxylate ratios. Cold finger tests were performed at selected temperature differentials that closely represented field conditions in order to demonstrate the efficacy of the optimized blend, in which deposits of C30+ waxy compounds were significantly eliminated.\u0000 It's commonly accepted that comb shaped polymers interact with wax crystals via incorporation and perturbation. The polymer blend presented here, with an optimized ratio of non-polar and polar groups, appear to enable a secondary mechanism that introduces a repulsive force between growing wax crystals, which is reminiscent of interfacial polarization of charged wax crystals under an external electric field. Through Zeta Potential, Cold Finger, Yield Stress, DSC, SARA and HTGC analysis, it was demonstrated that this additional interference rendered the comb shaped polymer blend much more effective, against other PAMAs, OMACs, and linear polymers such as ethylene vinyl acetate (EVA).","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"8 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":"128490795","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":"Non-Ionic Surfactants as Boosters for FR Hydration in Brines","authors":"Allen Kelley, Kristina Fontenot, Christinna Becktold, Carla Morgan, C. Stanciu, Jorge Fernandez","doi":"10.2118/213793-ms","DOIUrl":"https://doi.org/10.2118/213793-ms","url":null,"abstract":"\u0000 A theoretical model of polyacrylamide polymers (PAM and PHPA) hydration dynamics is explored, with emphasis on the effect pf salinity on the hydration dynamics of traditional PAM and PHPA polymers. By understanding the interactions at a molecular level between the polymer and the solvent system it is expected that the polymer’s usability as a viscosifying agent can be extended into brackish and possibly produced water.\u0000 In this study, viscosity vs. time plots are used to find the hydration rates for PAM and PHPA emulsions in fresh water and various brines. Special brines were designed, including one with Fe(III) among components. The study is done by using common, commercial viscometers, utilizing an R1 B1 bob configuration with heated cup. The overall mixing shear generated is low and kept constant throughout the runs. The temperature and length of runs are also kept constant. This allows the determination of the rate limiting hydration step, maximum viscosity and the hydration rates of a wide variety of nonionic surfactants to be explored.\u0000 By comparing the PAM and PHPA hydration rates for the neat brine, tap water and brine with non-ionic surfactant it is shown that by choosing the correct nonionic surfactant the hydration rates can be increased by over 3500% from the brine solution and more than 10-50% from tap water. It is also shown that the maximum viscosity can be increased by over 700% from the brine solution and 27% from tap water. This trend was also shown to be true using Nano pure water. The results support the theoretical hydration dynamics we propose, showing the effect the nonionic surfactants have on the rate limiting hydration step and transitions between different hydration steps. The data is strong proof that by understanding the processes of polymer hydration, brackish and possibly produced water in a wide range of TDS can be used to successfully hydrate the polymer.\u0000 The novelty of this testing is that it provides further examples of how non-ionic surfactants can be used successfully to allow PAM and PHPA polymers to be hydrated in brine waters of various compositions with no damage to performance. Care was taken to utilize very common instrumentation and to develop simple and clear procedures for testing, to make the method easy and reliable to use by field labs that may not necessarily have state-of-the-art equipment available.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"6 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":"125078511","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":"Novel High-Efficient Key Component of Steel Corrosion Inhibitors Formulation for Acidification: Indolizine Derivatives of the Conventional N-Heterocyclic Quaternary Ammonium Salts","authors":"Zhen Yang, Yefei Wang, M. Finšgar, Jiajia Wu, Wengang Ding","doi":"10.2118/213814-ms","DOIUrl":"https://doi.org/10.2118/213814-ms","url":null,"abstract":"\u0000 Acidizing, the widely used technique for well stimulation, requires a great consumption of effective Corrosion Inhibitors (CIs), due to the severe and fast corrosion of metallic equipment caused by strong hot acid as soon as the acidizing fluids are pumping down to reservoir. This paper presents a new concept of indolizine derivative inhibitors with remarkable inhibition effectiveness for steel under acidizing condition, which will reduce the cost and environmental burden of acidizing CIs significantly.\u0000 Indolizine derivatives of several quinolinium salts (serves as main component of currently used acidizing CIs) were synthesized respectively through an optimized mild procedure from quinoline and different halides. The inhibition of the new inhibitors for N80 steel were evaluated in hot 15 wt.% HCl by gravimetric and electrochemical analysis, while their corrosion prevention mechanism were studied. Surface adsorption and thermodynamic aspect of inhibition process were also investigated. Synergistic inhibition performances of the indolizine derivatives with surfactant, KI and other additives were examined.\u0000 For the synthesis step, a relatively high yield of the crude products were reported. Inhibition assessment results showed that compared with their quinolinium salt precursors, the dimer derivative can dramatically mitigate the corrosion speed and exhibit considerable inhibition efficiencies even at an extremely low dosage. The results obtained from gravimetric tests, electrochemical methods as well as the surface analysis are in good agreement and confirmed the well-behaved anti-corrosion properties of the derivatives. Conclusion from biotoxicity experiments showed that compared with their precursor quinolinium salts, both the indolizine derivatives and the original quinolinium salts share almost the same EC50 values, revealing the advantages in eco-friendly aspect. Mechanism study reveals that the new compounds can be characterized as cationic \"mixed type\" and the special molecular structure (conjugated aromatic moiety) may contribute a lot to their remarkable inhibition. Besides, the studied dimer derivatives also presents a good solubility and thermo-stability in acid solution. The amazing synergistic inhibition of indolizine derivative obviously shows that the inhibitive mixture could be utilized as new effective CI for acidizing.\u0000 The inhibition of conventional quinoline salts CIs would get greatly updated after been converted to their indolizine dimer derivatives. This provides a smart solution for exploring innovative acidizing CI with better protection efficiency. The use of indolizine derivatives may largely minimize the total amount as well as the total expenses of CIs in acidizing fluids and showing good prospects in replacement of the current main components of acidizing CIs in the near future.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"272 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":"122768843","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":"Assessment of Friction Reducer Performance Within a Continuous Brine Spectrum","authors":"C. Aften, Keith Sullivan, Russell Thorpe","doi":"10.2118/213885-ms","DOIUrl":"https://doi.org/10.2118/213885-ms","url":null,"abstract":"\u0000 The performance of friction reducers in standard flow loops is a function of the specific friction reducer, environmental factors such as brine composition and fluid temperature, and the unique loop design and run procedure. This study examines the performance of various commercial and experimental friction reducers using Design of Experiments with variables of friction reducer loading expressed in gallons per thousand gallons, brine Total Dissolved Solids expressed in parts per million, and R+ Hardness expressed as the mole ratio of cationic hardness ions to the Total Dissolved Solids in decimal percentage. The ultimate percent friction reduction is generally dependent upon these variables, and each friction reducer generates unique profiles used to predict performance within the above variable space.\u0000 This study evaluated 12 inverse emulsion friction reducers of various charge types in a 100 foot once through pipe. For this design of study, the Total Dissolved Solids was varied from 5,000 to 150,000 parts per million, the R+ Hardness varied from 0.0 to 0.3, and the friction reducer loading varied from 0.25 to 1.00 gallons per thousand gallons. Each reducer was injected into a reservoir containing a brine with the previously referenced, pre-established levels of Total Dissolved Solids and R+ Hardness, and the resulting maximum percentage friction reduction calculated by standard differential pressure protocol.\u0000 The response surfaces generated had Ajusted-R2 values from 0.86 to 0.99 demonstrating an exceptionally good fit for the chosen regression model. The contour profiles expressed a general similarity between related charge types with type of charge significantly influencing the response surface profile. Typically, as friction reducer loading increased, percent friction reduction increased or a maximum plateau was achieved, or performance declined. Certain friction reducers’ performances increased as Total Dissolved Solids and/or R+ Hardness increased whereas many reducers’ performances decreased. The gradient of the response surfaces varied from linear progressing to cubic functions with arithmetic transformations.\u0000 How friction loop results transmute to full scale hydraulic fracturing operations is not yet fully understood and no delineated process currently exists. However, mapping response surfaces of specific friction reducers then comparing responses to other friction reducers’ response data provides insight and can articulate how reducers’ performances are affected by friction reducer loading, TDS, and R+ Hardness, particularly in operations involving highly variable water quality. As brine character can vary during a hydraulic fractioning treatment, the best practice may be to either use a friction reducer known to perform well within the expected brine level or anticipate using multiple friction reducers for a specific treatment.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"74 3 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":"131358509","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":"Water Digital Avatar—Where Chemistry is Mixed with Machine Learning","authors":"J. Farrell, S. Makarychev-Mikhailov","doi":"10.2118/213869-ms","DOIUrl":"https://doi.org/10.2118/213869-ms","url":null,"abstract":"\u0000 Water affects almost every operation in the exploration and production (E&P) industry, with its properties important to flow assurance, to three-phase flow pressure/volume/temperature (PVT) modeling, and for fluid compatibility purposes across well construction, stimulation, and production operations. Until now, time-intensive laboratory tests or cumbersome third-party simulators were required to extract physicochemical properties. Here, a family of machine-learning-based reduced-order models (ROM), trained on rigorous first-principle thermodynamic simulation results, is presented.\u0000 Approximately 90,000 representative produced-water samples were generated using the United States Geological Survey (USGS) Produced Waters Geochemical Database (Blondes et al. 2019), with systematic variation of the concentrations of 14 common ions. A training data set of 1 million rows was constructed, further varying temperatures and pressures using broad ranges (50-400°F and 14.7-20,000 psi). Thermodynamic simulations were used to generate a data set with more than 500 parameters, including speciation; physicochemical properties such as density, thermal conductivity, heat capacity, and salinity; and notably, the scaling potential for 11 common oilfield scale-forming minerals. More than 20 machine-learning algorithms were screened using cross-validation, and boosted decision trees were found to provide the best accuracy. The CatBoost algorithm (Prokhorenkova et al. 2018) was selected and further optimized. Model validation using unseen data showed relative errors of less than 1% for the majority of predicted properties, which is remarkable for such a complex multicomponent and multiphase system. Simulation details, modeling, and validation results are discussed.\u0000 Trained and optimized ROMs can be incorporated in any workflow that depends on water property predictions. As a demonstration, a web application, Water Digital Avatar, was built from these ROMs to quickly and accurately process predictions of water properties and scaling potential on the basis of the entered water composition and desired conditions. The streamlined workflow provides users with model predictions in tabulated and graphical forms for analysis within the web application or offline by means of a downloaded spreadsheet.\u0000 The developed ROMs that predict water properties enable automated decision making and improve water management workflows. The presented approach can be further extended to other oilfield, chemical, and chemical engineering applications.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"126 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":"123154507","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":"Improved Scale Prediction for High Calcium Containing Produced Brine at High Temperature and High Pressure Conditions","authors":"Yuxin Shen, Guannan Deng, Xin Wang, A. Kan, M. Tomson","doi":"10.2118/213827-ms","DOIUrl":"https://doi.org/10.2118/213827-ms","url":null,"abstract":"\u0000 Scale prevention is one of the most important problems in the oil and gas industry. Due to the more aggressive production behavior recently, there are more chances to encounter high temperature, high pressure, and high TDS conditions. This study focuses on improving the scale prediction in the condition of high temperature (up to 210°C), and TDS (total dissolved solids, over 300,000 mg/L) with calcium concentration up to 2.0 molality (m). A hydrothermal autoclave reactor was developed for solubility measurement. The solubility of anhydrite was measured in the CaCl2-NaCl-H2O solution with constant ionic strength of 4 m. Results shows that the ionic strength effect and the Ca-SO4 association would increase the anhydrite solubility while the common ion effect decreased the anhydrite solubility. The measured solubility data can develop the virial coefficient for the ion interaction of Ca2+ and SO42. This virial coefficient can then be applied in Pitzer models to improve the calculation for the saturation index of scale. Quantifying the Ca-SO4 interaction parameters can make a better prediction of mineral solubility with high calcium concentration. The results can also improve not only anhydrite but all of the sulfate scale predictions at high temperature with high TDS conditions. This study offers a reliable and efficient method to obtain solubility under high temperature conditions and expands the scale prediction of the production brine with high calcium concentration at higher temperature and pressure limits.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"75 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":"124799063","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":"Micro-Heterogeneous Solvent Mixtures for Removal of Organic Deposits from Various Surfaces","authors":"R. Varadaraj, Kristina Fontenot","doi":"10.2118/213794-ms","DOIUrl":"https://doi.org/10.2118/213794-ms","url":null,"abstract":"\u0000 The technical feasibility of using oxygenated solvent mixtures as an environmental and ecological friendly alternative to aromatic hydrocarbon and terpene solvents for removal of organic deposits from surfaces has been demonstrated. Micro-heterogeneous solvents were prepared using mixtures of di-alkyl ethers and 2-alkyl alkanols. These micro-heterogeneous solvents exhibit unique properties and are effective in solubilizing and removing organic asphaltenic hydrocarbon deposits from surfaces. The main applications of micro-heterogeneous solvents are in organic deposits removal from wellbores and near wellbore regions, heavy oil recovery from oil sands and oily sludges, and heavy oil processing equipment cleaning.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"30 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":"116919423","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 Diversion Fluid for Chelate-Based Acid Systems","authors":"R. Nazari Moghaddam, M. Van Doorn, H. Oskarsson, P. Ferm","doi":"10.2118/213832-ms","DOIUrl":"https://doi.org/10.2118/213832-ms","url":null,"abstract":"\u0000 Chelating agents have been used in the upstream oil and gas industry as a scale remover, iron control agent and acidizing fluid. Despite several studies on diversion techniques for conventional acid systems (i.e., HCl or organic acid), the application of diverting systems has rarely been studied during acidizing jobs using chelating agents. In this study, a new diverting system is introduced and experimentally evaluated during the stimulation of carbonate cores by a chelate-based acid.\u0000 The diverting system introduced in this study is a unique blend of viscoelastic surfactants based on sulfobataine and amine oxide chemistries. The new diverting system was examined during carbonate acidizing by Glutamic acid N, N-diacetic acid (GLDA). The diverting system, which is specially designed for high temperature applications, was used during dual coreflooding experiments at 130°C. In these evaluations, Indiana limestone cores with various permeability contrasts were used. The pressure behavior, permeability improvement/reduction, and the production flow rates from each core plug were measured. Finally, to visualize the wormhole propagation inside each core, CT scanning was conducted after the treatments.\u0000 From the results, it was found that the diverting system can block the formation for a certain period of time (<2 hours). During this period, the diverting system shows the highest viscosity and can temporarily block the high permeability cores (>100 mD) which diverts the injected acid to the lower permeability core. It was found that the acid diversion lasts for a longer time when the system has a higher permeability contrast. From the CT-scan images, it was found that the wormholes were propagated up to 50% across the low permeability core when 0.3 PV of the diversion fluid was injected. With enough volume of the diversion fluid, the acid system was fully diverted, and the treatment fluid achieved full-length wormholes in both high permeability (HP) and low permeability (LP) cores. It was also shown that required volume of the diverting fluid is a function of permeability contrast. It was demonstrated this pre-flush diversion technique can be successfully applied and it needs less VES volume compared to the continuous VES injection with acid.\u0000 The novel formulation introduced in this study is a cost-effective solution specially designed for the chelate-based acid systems. The proposed formulation can also be optimized to resolve diversion challenges in other applications at high temperature.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"116 40","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113944644","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":"Supercritical Carbon Dioxide Foam Performance for Enhanced Oil Recovery: Challenges and Solutions","authors":"Ahmed Abdelaal, Ahmed Alsabaa, R. Gajbhiye, M. Mahmoud, Dhafer Al-Shehri, S. Patil","doi":"10.2118/213798-ms","DOIUrl":"https://doi.org/10.2118/213798-ms","url":null,"abstract":"\u0000 Foam enhanced oil recovery (EOR) techniques commonly use N2 and CO2 gases. Previous studies have compared the foam generated by these two gases, and it has been found that CO2 becomes weaker and less stable at its supercritical conditions, reducing its effectiveness in creating stable foam. In contrast, N2 forms stronger foam at these conditions. Limited research has investigated the use of a CO2/N2 mixture foam in bulk media. It was found that adding N2 to CO2 has shown potential in producing more stable foam in oil-free porous media. This article reviews the advantages and disadvantages of CO2 foam and potential methods of improving its use in oil production. In addition, the performance of mixed CO2/N2 foam in crude oil-saturated sandstone cores was studied and compared to pure CO2 foam, with optimization of total injection rate, CO2/N2 ratio, and foam quality to achieve maximum oil recovery and stable foam. Results showed that the mixed foam gave a higher recovery than the CO2 foam. The addition of N2 to CO2 improved foam stability and enhanced oil recovery up to a 20 % by volume N2, but beyond this range, oil recovery was adversely affected. Increasing foam quality up to 80% produced a finer-textured foam, improving stability and recovery, but beyond 90%, the foam becomes coarser and less stable, likely due to the formation of dry foam. Increasing the injection rate affected stability of foam and recovery of oil, as higher rates of injection produced high shearing rates that may cause collapse of foam. The study suggested useful outcomes for addressing supercritical CO2 foam instability in sandstone reservoirs and advancing understanding in the developing area of foam behavior research.","PeriodicalId":241953,"journal":{"name":"Day 1 Wed, June 28, 2023","volume":"54 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":"116141461","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}