Enhanced Oil Recovery Research Papers (original) (raw)

2025, All Days

Chemical enhanced oil recovery (EOR), including polymer and surfactant-based processes, is a method that operators consider to maximize oil recovery from onshore and offshore reservoirs. Due to the logistical, operational and environmental differences and the footprint and required weight needed for additional injection and production equipment, offshore chemical EOR processes are challenged by greater complexity and costs as compared to onshore applications of the same technologies. Chemical EOR commonly requires large volumes of injection chemicals, as well as demulsifiers to break produced water/oil emulsions and inhibitors to control scale, resulting in high shipment and storage costs. The use of seawater and/or produced water for injection of the chemicals into offshore fields mandates stringent processing of both streams to allow optimal injectivity, sweep efficiency, and chemical effectiveness in the reservoir. Offshore production of saleable oil and clean water requires spac...

2025, Journal of Petroleum Technology

Summary The analysis of several transient-pressure surveys employing both analytical and numerical simulation techniques is presented. Case histories include examples of the following: partial penetration and spherical flow; flow influenced by various boundary conditions and geometries, including linear flow; variations in transmissibility; and effects from ocean tides. It is shown how these well-test results can be integrated with the geological framework, and their overall impact on oilfield development planning is discussed. Introduction The success of defining an optimum hydrocarbon-field development plan is crucially dependent on the early knowledge of the reservoir drive mechanisms and heterogeneities that may affect fluid flow in the reservoir. For offshore field developments, decisions related to the possible placement of injectors are of particular concern. As shown in the documented case histories, a greater effort to obtain quality data from extensive well testing may be ...

2025

The objectives of the final year project are to study and investigate the forces in the reservoir model and how these forces can be used to design the water flooding performance toward oil recovery enhanced. And to evaluate how the water injection rate can affect the oil recovery for reservoir. It is a beneficial to the gas and oil industries of company to have and test the potential for the techniques of oil recovery, and low cost which are cheap and easy to control like water flooding. The problem in water flooding is that, oil companies still looking for researches on force which available in the reservoir and how it can be designed the water flooding that can lead to be a good oil recovery at lower cost. Precisely, approximately maintenance and design the requires of water flooding to understand the oil viscous can be displaced by the water, and how can optimized the oil recovery. Subsequently, the scope of this project to get the result for water injection into the lab core plug with containing free gas in crude oil at different injection rate of water flooding. The replies for different compared of water floods in ordered to search the mechanisms through which water injection can be recover the crude oil. The evaluation of the parameters is the effect of capillary force, effect of injection water rate, ration of mobility and instability. These researches of this project focus on the effect of evaluating of water injection rate towards recovery of crude oil by water flooding. In respect of obtaining the data, the writer use research and identifying the methodology and understand the notion of water flooding in oil reservoir. This project will find the result for injection of water into laboratory core sample which contains free gas crude oil at different rate of water injection. Therefore, if we have lower injection rate of water flooding is better than higher injection in terms of oil recovery which can lead to increase the profit of oil as well as the company's revenue. Alhamdulilah. Thanks to Allah SWT and all praise is to Allah, the most gracious and the most merciful, who through his grace and mercy, whom with his willing giving me the opportunity to complete this final year project which is title Waterflooding performance in oil reservoir. This project would was prepared for petroleum engineering department. This final year project based on the methods that given by university. Next, I would like to express my deeper thanks to Dr. Muhammad Ayoub who was very helpful and offered me precious assistance, guidance, encouragement and excellent advice during this project. His support, dedication and constant patience have taught me so much about ownership and discipline in completing this final year project. Besides, that I would like to thanks A.P. Dr. Syed Mahmood who always share his information in literature, suggestions, positive comment and invaluable assistance. And deeper thanks to the lab technologists Mr Saiful Bin Ismail who always assist me in conducting the experiments. Their commitment and knowledge to highs stander very helpful in completing all the experiment required. Special thanks and appreciation to my parents, family, special mate of mine, and others for their encouragement, constructive, cooperation, suggestion and full of support for the report completion, from the beginning until the end.

2025

2025, Energy & Fuels

In this study, we analyzed the temperature and pressure measurement data obtained from the production test of methane hydrates in the second offshore production wells of Nankai Trough (2017). Based on the analysis, we derived timeseries information on the vertical profile and the gas and water influxes in the wells via an optimization process. The time-series information revealed variations in the vertical production profiles and behavior between two production wells. Some discrepancies were observed in the petrophysical characteristics, particularly in the permeability between the wells, while comparing the measurement-based profile and simulation results based on geophysical log-based reservoir models. The discrepancies are attributed to the water-producing layers and some near-wellbore phenomena, which also inhibit stable and increasing gas production in the well. Current studies on gas hydrate by the Japanese national gas-hydrate resource development project focus on identifying the causes of these problems and possible countermeasures.

2025, Energy Procedia

A CO 2 monitoring pilot was initiated at the Penn West Energy Trust CO 2 EOR operations within the Cardium formation of the Pembina Field. The Penn West Pembina-Cardium CO 2 EOR Monitoring research program focused on well integrity, local/ regional geology and hydrology, extensive monitoring of CO 2 and short and long predictive modeling. The geochemical modelling program of the Penn West Monitoring Project quantified the chemical reactions that occur between the gas -oil-water -rock within the reservoir prior to, during, and following CO 2 injection. An equilibrium speciation geochemical model was used to examine the field produced water compositions . M any of the produced waters are undersaturated with respect to calcite. This is most easily explained when mixtures of waters o f quite different chemical compositions are produced from a single producing well. This observation has important implications for the interpretation of produced water compositions and demonstrates that flow within the reservoir must be understood to fully interpret the chemistry signatures. A reaction mass transfer model was used to evaluate the chemical processes in the reservoir (short and long term) and to evaluate the thermodyn amic data base. It established that the dominant reaction controlling the short term water composition was ion exchange reactions, coupled with calcite dissolution and CO 2 transfer from the oil phase. It was also used as a predictive tool to estimate the m ineralogical reactions which will ultimately be responsible for the long term trapping of the injected CO 2. GEM -GHG was used to calculate the chemical processes occurring during the various phases of hydrocarbon recovery, including the predicted evolution of produced water compositions, and th e results compared to field measurements. Discrepancies between the modeled and the measured field data can be used to refine the model, improving our understanding of chemical processes in the reservoir. The geochemic al models allow an assessment of the amount of CO 2 trapping in each of the major units in the reservoir. There are large uncertainties in the absolute value of the amounts, but they allow a direct comparison between trapping mechanisms and a direct comparison between the trapping in each reservoir unit . This work represents a first study to demonstrate the potential of using geochemical sampling and measurements and integrating them with reservoir models for secondary and tertiary oil recovery.

2025, Energy Procedia

This study aimed to assess remote sensing methods using open path laser technology as a tool for atmospheric monitoring of CO 2 storage sites. CH 4 and CO 2 open path detection systems were tested at the Penn West Pembina Cardium CO 2 enhanced oil recovery monitoring pilot. The tested CH 4 detection system was found to be very sensitive and small increases in the gas concentration due to controlled releases were easily distinguishable. The detection capability of the CO 2 detection system was impacted by the larger natural background concentration of CO 2 . Where possible, CH 4 should be used as an indicator due to the better detection capabilities and smaller background concentration variations compared to CO 2 .

2025, International Journal of Greenhouse Gas Control

Stable isotope data can assist in successful monitoring of the movement and the fate of injected CO 2 in enhanced oil recovery and geological storage projects. This is demonstrated for the International Energy Agency Greenhouse Gas (IEA-GHG) Weyburn-Midale CO 2 Monitoring and Storage Project (Saskatchewan) where fluid and gas samples from multiple wells were collected and analyzed for geochemical and isotopic compositions for more than a decade. Carbon isotope ratios of the injected CO 2 (-20.4‰) were sufficiently distinct from median ␦ 13 C values of background CO 2 (␦ 13 C = -12.7‰) and HCO 3 -(␦ 13 C = -1.8‰) in the reservoir to reveal the movement and geochemical trapping of injected CO 2 in the reservoir. The presented 10-year data record reveals the movement of injected CO 2 from injectors to producers, dissolution of CO 2 in the reservoir brines, and ionic trapping of injected CO 2 in conjunction with dissolution of carbonate minerals. We conclude that carbon isotope ratios constitute an excellent and cost effective tool for tracing the fate of injected CO 2 at long-term CO 2 storage sites with injection rates exceeding 1 million tons per year.

2025, Journal of Surfactants and Detergents

The viscoelastic surfactants (VES)‐based acid diverters are frequently used to divert acid flow from high‐permeability layers into low‐permeability for enhanced overall productivity of the treated well. In general, an optimum VES‐based system possesses advantages of decrease in absorption loss, damage of reservoir, and improved adaptability of active agents to high salinity. Herein, we report the synthesis of three new zwitterionic gemini surfactants (1–3) and previously known amidosulfobutaine (C18AMP3SB) has been accomplished for the investigation of diverting acid performance. The synthesis of these surfactants was achieved by the amidation of the acid chlorides of commercially available fatty acids with 3‐(dimethylamino)‐1‐propylamine followed by subsequent reactions with appropriate sultone or ethyl 4‐bromobutanoate. The synthesized surfactants were well characterized by spectroscopic methods including IR and NMR spectroscopy. The thermogravimetric analysis (TGA) results sugges...

2025, International Journal of Earth Sciences Knowledge and Applications

This study improved the conclusions provided by Obibuike et al. (2022) by critically
examining the Pressure-Volume-Temperature (PVT) properties, well placement,
establishing hydrocarbon pore volume injected (HDPVI) as the basis of comparison
(instead of time), and conducting the flood simulations at more reasonable pressures.
Furthermore, a sensitivity study of dip was performed on the given reservoir which
concluded that EOR benefits from gas versus water injection are highly sensitive to this
variable, such that a generalized conclusion of water versus gas cannot be made. It also
identifies additional variables that may also affect the relative results for areas of further
study.

2025, Advances in Colloid and Interface Science

Thermodynamic and hydrodynamic properties of foams in porous media are examined Ž . from a unified point of view. We show that interactions between foam films lamellae and wetting films covering the pore walls play an important role in treating experimental data and constructing a general theory of foam residence and motion through porous media. Mechanisms of in situ bubble generation, foam patterning, and rheological peculiarities of foams in pores are discussed in detail. In particular, we clarify the difference between foam lamellae and liquid lenses, focusing on intermolecular forces in thin foam and wetting films. A consistent description of conditions of mechanical equilibrium of curved lamellae, including dynamic effects, is presented for the first time. This microlevel approach enables us to describe the dependence of the capillary pressure in the Plateau border on the current state of the pair 'wetting film᎐foam lamella'. We review a theory of foam patterning under a load. Two driving forces are invoked to explain specific interactions between the solid skeleton and foams. The binding forces caused by bubble compressibility and the pinning forces due to capillarity determine a specific ordering of lamellae in porous media. The microscopic bubble train model predicts asymptotic expressions for the start-up-yield pressure drop. We consider key problems that underlay the understanding of physical mechanisms of anomalous foam resistance. Different micromechanical models of foam friction are

2025

Carbon capture and geological storage is a potential technology to reduce CO2 emissions into the atmosphere from fossil fuel intensive industries. Monitoring of CO2 storage sites is required by many of the emerging regulations with specific interest in accounting of injected CO2 in various target reservoirs including saline aquifers. We have used chemical data and carbon and oxygen isotope ratios of produced water and gases sampled repeatedly from various observation wells to: a) trace the movement of injected CO2, b) assess pore space saturation with CO2 and c) develop an approximate carbon budget for the Pembina Cardium CO2 Monitoring Project in central Alberta, Canada. The distinct carbon isotope ratios of injected CO2 in association with gas compositional and flux data were used to determine the percentage of injected CO2 produced at several observation wells using two endmember mixing calculations. Changes of 18O values of produced water by up to 4 h were caused by oxygen isoto...

2025, ICONIC RESEARCH AND ENGINEERING JOURNALS

The oil and gas industry is a prominent contributor to the global energy value chain but has some significant environmental issues, particularly from its drilling operations. The application of Artificial Intelligence in minimizing drilling waste and avoiding formation damage, which are central issues in upstream oil and gas exploration, is the subject of this paper. Drilling waste in the form of cuttings and spent fluids is an environmental hazard and also an economic cost if not managed effectively. The paper outlines the state of the art of Artificial Intelligence approaches in drilling recognizing significant advances. It also highlights existing literature deficiencies. Of particular concern is that, real-time AI-based decision-making support for formation damage prevention is in its very early stages and needs additional field verification. The paper calls for the creation of adaptive, resilient, and scalable AI models for the improvement of sustainable drilling operations. By bridging these knowledge gaps, the research hopes to contribute to enhancing more efficient and sustainable operations in the oil and gas industry.

2025, Polymers

In this work, we present various evaluations that are key prior field applications. The workflow combines laboratory approaches to optimize the usage of polymers in combination with alkali to improve project economics. We show that the performance of AP floods can be optimized by making use of lower polymer viscosities during injection but increasing polymer viscosities in the reservoir owing to "aging" of the polymers at high pH. Furthermore, AP conditions enable the reduction of polymer retention in the reservoir, decreasing the utility factors (kg polymers injected/incremental bbl. produced). We used aged polymer solutions to mimic the conditions deep in the reservoir and compared the displacement efficiencies and the polymer adsorption of non-aged and aged polymer solutions. The aging experiments showed that polymer hydrolysis increases at high pH, leading to 60% higher viscosity in AP conditions. Micromodel experiments in two-layer chips depicted insights into the displacement, with reproducible recoveries of 80% in the high-permeability zone and 15% in the low-permeability zone. The adsorption for real rock using 8 TH RSB brine was measured to be approximately half of that in the case of Berea: 27 µg/g vs. 48 µg/g, respectively. The IFT values obtained for the AP lead to very low values, reaching 0.006 mN/m, while for the alkali, they reach only 0.44 mN/m. The two-phase experiments confirmed that lower-concentration polymer solutions aged in alkali show the same displacement efficiency as non-aged polymers with higher concentrations. Reducing the polymer concentration leads to a decrease in EqUF by 40%. If alkalipolymer is injected immediately without a prior polymer slug, then the economics are improved by 37% compared with the polymer case. Hence, significant cost savings can be realized capitalizing on the fast aging in the reservoir. Due to the low polymer retention in AP floods, fewer polymers are consumed than in conventional polymer floods, significantly decreasing the utility factor.

2025, Pure (Coventry University)

2025, Energy Sources, Part A: Recovery, Utilization, And Environmental Effects

Steam injection and thermal recovery of oil from the reservoir are increasing day by day. However, the recovery of the heat remained stored in the steam-flooded oil reservoir is nor in practice neither researched previously. A novel concept of steam injection and energy recovery from a light oil reservoir is presented in this paper. Reservoir numerical model of an actual oil field was generated and simulated with steam injection. Different parameters of thermal properties of geologic formations were discussed and adopted as per actual geology of the study area for more realistic simulation of heat storage, dissipation, and losses. After the optimum oil recovery, water was circulated through the same injection well into the reservoir to extract the energy in the form of heat, stored during the steam injection phase. The effects of different completion schemes of injection well were also simulated, discussed and pointed out for optimum oil recovery. Oil recovery factor is the most important parameter from both research and field development point of views. The comparative analysis was also carried out with the oil production without steam injection and found that steam flooding increased oil recovery factor up to more than 15% by decreasing the production time period up to 40% as compared to without steam injection oil production. The transmission of heat through conduction and convection mechanisms in the porous media, and through advective, dispersive and diffusive processes in the fluid was modeled. To fully investigate the feasibility of the concept presented in this paper, the production wellbore modeling was also carried out and temperature profile of recovered heat energy at the wellhead was obtained by acknowledging the thermal losses and found to be very useful for any direct and indirect utilization of heat throughout the energy recovery period of the reservoir.

2025, Thermal Science

Surfactant and polymer flooding are the vital techniques used in petroleum industry to enhance the oil recovery. Development and advancement in such techniques has occurred time by time to overcome the challenges of oil and gas recovery. However, micro fluid chips and its development provide a new way to understand the real time behavior of fluid flow in porous media. The essence of this study has been achieved by collecting the information from literature studies and sorted the useful information to organize the pattern of micromodels chip revolution. In this study, first precise review is conducted by the innovations of micromodel chips into timescale from 1952 till date. Second, advancement in micromodel chip technology is included based on different periods of time where micromodel chips have evolved from chip design to nano scale visualization of chips. Third, some recommendations are proposed based on evolution of micromodel chip technology that it not only requires less time ...

2025, Energy Sources, Part A: Recovery, Utilization, and Environmental Effects

2025, Journal of Petroleum Science and Engineering

We present a microfluidic method to rapidly screen enhanced oil recovery additives based on the deformation of aqueous microdroplets in oil. Conventional methods, such as the pendant drop method, are hindered by large fluid volumes that require several hours to thermally equilibrate between measurements. Here we demonstrate a complementary technology to conventional methods, by which additives can be rapidly screened to select the best candidates for further study. Our glass chip establishes thermal equilibrium (demonstrated at 80 °C) of undiluted, highly viscous, crude oil within seconds, and enables the rapid quantification of water-in-crude oil droplet deformation within minutes, at a reservoir-relevant scale. The influence of two alkaline additives, a surfactant and a salt in the injected water phase were quantified, demonstrating the applicability of our method to a variety of recovery strategies.

2025, Desalination

The application of micellar systems has been growing during the last years because of their importance in various practical situations. Continued development of their application is necessary. If the principal economic interest of microemulsions is for some time enhanced oil recovery, the following also have significant applications such as pharmaceutical preparations, painting, and products for engine lubrication. The effect of variation in composition of anionic surfactants (α oleifin sulfonates) and the presence of a water-soluble charged polymer (Xanthan gum) and an uncharged polymer [poly (ethylene glycol)] on the phase behaviour of pseudo-ternary systems of water-oil surfactants was investigated. Several domains were observed when the composition of surfactants and cosurfactants (e.g., pentanol) in a mixture is varied. The appearance of these domains in the phase diagram has been attributed to the formation of different Winsor systems.

2025, Results in Engineering

Enhanced oil recovery (EOR) techniques play a crucial role in increasing hydrocarbon production from mature reservoirs, particularly in light and heavy oil systems. This study explores the potential of synthesized citric acidcoated magnetite (Fe 3 O 4) nanoparticles (CM NPs) as a novel, cost-effective, and environmentally friendly EOR agent. The synthesized CM NPs were characterized using field emission scanning electron microscopy (FE-SEM), transmission electron microscopy (TEM), X-ray diffraction (XRD), dynamic light scattering (DLS), and Fourier transform infrared spectroscopy (FTIR) to confirm their structure, size distribution, stability, and functional groups. Their EOR performance was then evaluated in both homogeneous and heterogeneous two-dimensional micromodels and compared with conventional low-salinity water flooding (5000 ppm NaCl) and polymer (polyacrylamide) flooding. Image analysis revealed that in the heterogeneous heavy oil micromodel, CM NPassisted flooding achieved a recovery factor (RF) of 66.02 %, which was higher than water flooding (59.04 %) but lower than polymer flooding (83.12 %). In the homogeneous light oil model, CM NPs achieved 80.89 % RF, surpassing water flooding (67.69 %) and approaching polymer flooding (86.36 %) performance. The improved oil recovery using CM NPs is attributed to their ability to reduce interfacial tension, alter wettability, and slightly increase displacing fluid viscosity. Additionally, their magnetic properties allow for easy postrecovery separation, enhancing environmental sustainability and reusability. These findings demonstrate that CM NPs offer a promising alternative to traditional EOR methods, particularly in scenarios where polymer flooding may be less practical or economically viable.

2025, American Journal of Mathematical and Computer Modelling

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

2025, Nafta-Gaz

Crude oil, a major source of energy, is being exploited as a driver of the economy throughout the world. Being a limited resource, the price of crude oil increases constantly and the exploitation of mature reservoirs becomes essential in order to meet the ever-increasing energy demands. As conventional recovery methods are not sufficient to fulfil the growing needs, there is an incessant demand for developing new technologies which can help in efficient tertiary recovery in old reservoirs. Petroleum biotechnology has been emerging as a branch that can provide solutions to major problems in the oil industry, including increasing oil production from marginal oil wells. The enhanced oil recovery (EOR) method comprises four methods – chemical, thermal, miscible, and immiscible gas flooding – as well as microbial interference to increase recovery of the remaining hydrocarbons trapped in reservoir rocks. Biochemically enhanced oil recovery comprises an array of blooming technologies for t...

2025, Rudarsko Geolosko Naftni Zbornik

Analiza testa porasta tlaka za horizontalnu bušotinu temelji se na poznavanju protjecanja fluida u ležištu, koje je matematički opisano jednadžbom difuzije trodimenzionalnog protoka i njenim rješenjima. Prema modelu horizontalne bušotine u neograničenom ležištu za slučaj neustaljenog protoka mogu se pojaviti četiri režima protjecanja: rani radijalni protok, rani linearni, kasni pseudoradijalni i kasni linearni protok. Za svaki od navedenih protoka postoje odgovarajuća rješenja jednadžbe difuzije, koja se primjenjuju u analizi testa porasta tlaka, uz glavnu pretpostavku da je bušotina potpuno horizontalna i smještena u potpuno horizontalnom, homogenom ležištu, jednake debljine. Osim toga, ležište se uzima kao izotropno u horizontalnoj ravnini, ali da postoji vertikalna anizotropija, tj. da je vertikalna propusnost različita od horizontalne. Primjer analize testa porasta tlaka u računalnom programu Saphir prikazan je za horizontalnu bušotinu na plinskom ležištu Okoli. U analizi su korišteni podaci ispitivanja kao temelj za postavljanje odgovarajućeg modela bušotine. Primjena mjerenih podataka u modeliranju bušotine značajna je zbog točnosti i pouzdanosti, koju takvi modeli mogu dati u određivanju ključnih podataka za prognoziranje budućih promjena proizvodnog sustava, kao što su propusnost, skin faktor, početni ležišni tlak i sl.

2025, Rudarsko Geolosko Naftni Zbornik

2025

The oil and gas industry has over 40 years of continuously developing experience in recovering of the huge residual oil left in the reservoir, after primary and secondary oil recovery procedures have been exhaustively harnessed, by the use of Carbon Dioxide (CO 2 ) flooding Enhance Oil recovery (EOR) methods. Clearly, the technology and operational practices used by the oil and gas industry in handling and injecting CO 2 cannot be over emphasized, of which pivotal to this process is the screening criteria used in diagnosing a reservoir's potential for CO 2 flooding. The prevailing screening criteria, due to its non-robust nature possess an inherent capacity of passively qualifying reservoirs as successful or poor candidates for CO 2 EOR sequel to its vague parameters. This study uses reservoir simulation to investigate the performance of different reservoirs to CO 2 injection. Fully compositional and pseudo-miscible black oil fluid models were tested in an inverted fivespot pattern. Detailed reservoir characterization was performed to represent the complex characteristics of the reservoir using PETREL ® preprocessor. IPM-PVTp and ECLIPSE ® compositional simulation model were used to evaluate the effects of various reservoir fluids and reservoir characteristics' combinations in reservoir fluids production as a function of carbon dioxide flooding. The results obtained from different permutations and combinations of 28 reservoir and fluid properties were investigated using the Design of Experiment (DOE) and Response Surface Methodology (RSM) to analyze the "key players" to the overall performance of CO 2 in EOR operations. A Meta Model for predicting the performance of using CO 2 flooding was generated using the Design Expert 5.0 software based on statistical principles and the governing pattern of occurrence recorded from the investigations.

2025, petroleum and coal

For matrix acidizing operations an appropriate acid implementation requires careful planning to minimize well damage while preventing acid overconsumption. Machine learning algorithms allow realtime stimulation result assessments to accomplish this objective. This research seeks to establish advanced machine learning models which provide precise real-time readings for skin factor together with bottom-hole pressure at the coiled tubing nozzle during foamed acid treatments. This research built nine advanced machine learning models which used standard matrix acidizing operational parameters. Real bottom-hole pressure measurements obtained from deployed pressure gauges formed the basis for training the developed models. The predicted bottom-hole pressure enabled the determination of real-time skin factor measurements. The development of machine learning algorithms took place through analysis of an extensive dataset obtained from 31 wells. Through comparison of predictive bottom-hole pressure models with actual field measurements the most efficient machine learning methods demonstrated exceptionally low root mean square error. The Neural Network, AdaBoost, Random Forest and K-Nearest Neighbor algorithms produced root mean square error values of 0.047, 0.048, 0.054 and 0.058 respectively. This study introduces novel methods of using advanced machine learning models as predictive tools to track bottom-hole pressure and skin factor throughout matrix acidizing procedures with foamed acid. These predictive models act as accurate and swift replacements for the traditional pre-and post-stimulation well testing, conventional empirical multiphase flow correlations as well as mechanistic models and unified models. The proposed models function as an economical replacement for downhole pressure gauges as well because they eliminate both cost and duration issues.

2025, Petroleum Science and Technology

 Surfactant flooding consists of the injection of a chemical added to water to reduce the interfacial tension of oil/water and alter the wettability of reservoir rock, producing larger quantities of residual oil. The aim of this study is to verify the sensitivity of oil recovery factor and oil breakthrough time to surfactants flooding parameters, such as surfactant concentration, initial water saturation, oil viscosity and injection rate. For this, we used the UTCHEM software, seeking to obtain a sensitivity analysis of these variables. Oil breakthrough time is the time at which the oil-water bank arrives at the producing well. From the obtained results it is noticed that for a lower initial water saturation, a higher recovery factor is generated. It has been demonstrated the existence of a critical water saturation, from which the oil breakthrough time begins to increase.

2025

The straightforward molecular modelling of an aqueous surfactant system at concentrations below the critical micelle concentration (pre-cmc) conditions is unviable in terms of the presently available computational power. Considering a typical nonionic surfactant, a fully atomistic simulation that includes several micelles will require in excess of O(10) atom sites and several nanoseconds of real time. Here, we present an alternative that combines experimental information with simulations of a more modest size to understand the surface tension changes with composition and the structural behaviour of surfactants at the water-air interface. The crux of the matter is to express the surface tension as a function of the surfactant surface excess both in the experiments and in the simulations, allowing direct comparisons to be made. As a proof of concept a coarse-grained model of tetraethylene glycol monodecyl ether is considered at the air-

2025, Macromolecular Symposia

Polymer flooding is one of the chemical processes used to enhance the petroleum recovery. The injection of a polymer dissolved in water into a reservoir aims to increase the water viscosity, leading to an improvement of areal and vertical sweep efficiency of the oil that is located inside the pores of the rock formation. The polysaccharides (mainly xanthan gum) and polyacrylamides have been used extensively for this purpose by the oil industry, and several papers were published. However, it is not clear yet how to choose the best polymer for a specific rock formation. In this paper, four polyacrylamides with different structures were evaluated for polymer flooding and the results were correlated to the permeability of the sandstone's core employed. The polyacrylamides of higher average molar mass and higher radius of gyration were more effective in the enhancement of pressure inside the pore rock, especially with the decrease of rock permeability. Even in this case, no evidence of damage by polymer retention or adsorption on the pore rock was shown, indicating that the high polymers selected are good candidates to EOR.

2025

During reservoir engineering analysis, the assessment of the possibility of asphaltene precipitation and corresponding heavy oil recovery with economic losses is carried out before any thermal operation. To investigate this phenomenon, three steam injection experiments using only steam, steam-CO2, and steamn-C4H10 at 1:1.29 volumetric ratios were carried out in naturally fractured limestone cores saturated with a 12.4° API heavy crude oil. After each experiment, the produced oil's asphaltene content was measured. Further, to determine the asphaltene effect on the fracture apertures and permeability, an improved cubic law (ICL) equation was used to determine the equivalent fracture aperture (EFA) change during the experiments. EFAs were calculated analytically. An initial observation made for only the steam injection experiment was a decline in asphaltene levels present in the producing oil. Asphaltene levels gradually increased as the effects of steam progressed. When CO2 was added to the steam, the asphaltene content of the produced oil increased. Nevertheless, the asphaltene content increased in the produced oil did not change the fracture permeability and EFA considerably. In contrast, when n-C4H10 was injected with steam concurrently, the asphaltene levels gradually increased above the starting value. However, in the further injection period, the asphaltene content in the produced oil was lower than the starting value as the injection progressed. This indicated that a partial upgrading of the asphaltene in the rock matrix caused an improvement in the EFA.

2025

Water saturation is an important parameter in hydrocarbons in a place calculation. The equilibrium nature of water saturation in reservoir will needs accurate determination of the free water level (FWL), transition height, and irreducible water saturation. The transition zone is influential reservoir volume modeling over a big area. Sometimes, SCAL capillary pressure data show the water saturation to be inaccurate because the plugs were not de-saturated to irreducible water saturation and capillary pressure equilibrium may not have been reached. This study focused on a basin with interbedded shale and a sand clastic sedimentary resevoir. Water saturation was calculated as being above the FWL using Cuddy's method to ignore the value of the capillary pressure on the SCAL data.

2025, International Journal of Greenhouse Gas Control

Residual Oil Zones (ROZ) form when oil has leaked or migrated from a reservoir trap through geological time, leaving a zone of immobile oil. Here we assess the feasibility of ROZ production with CO2 flooding, in a North Sea oil field for the first time. We identify a hydrodynamically produced ROZ, with an oil saturation of 26%, in the Pierce Oil Field of the Central North Sea and adapt established recovery factors for Carbon Dioxide Enhanced Oil Recovery (CO2 EOR) from onshore fields, to estimate oil resource and CO2 storage potential. Our mid case results show that CO2 utilisation increases commercial reserves by 5-20% while storing 15Mt CO2. Based on our calculations CO2 EOR can produce low carbon intensity crude oil from a mature basin and could store more CO2 than is released from the production, transport, refining and final combustion of oil.

2025, Journal of Clinical Virology

of our study was to test the possible evolution of different genetic variants of HBV in the CNS of HIV/HBV co-infected patients. Material and Methods: In 24 adolescents, mean age 16.9±1.8 years, with long-lasting, parenterally acquired HIV-infection and coinfection with HBV, we evaluated the viral load of HIV and HBV in paired CSF-plasma samples and the development of lamivudine-resistant mutations. Results: DNA HBV was positive in 17 plasma samples (mean 5.8±1.9 log10 UI/ml) and in 10 of their paired CSF samples (mean 3.9±1.1 log10 UI/ml). HBV DNA values from CSF were significantly lower compared to plasma (p<0.0001). In a subgroup of 5 patients undergoing lamivudine treatment for a mean of 26.5 months, we found 3 with distinct plasma-CSF profiles. While 2 had the rtM204V mutation associated with the replication-compensatory rtL180M mutation in both plasma and CSF, and the A181T mutation -relevant for lamivudine and adefovir only in CSF; a 3rd patient had all these HBV mutations only in CSF. The N236T mutation, relevant for adefovir resistance was not present. The presence of different mutations in plasma and CSF suggests the possibility of compartmentalisation of HBV infection. The clinical significance of the possible independent replication of an HBV variant in CSF remains an interesting feature to be investigated.

2025, Geofluids

Deep low permeability extra heavy oil reservoir has the characteristics of high formation pressure, high crude oil viscosity, and low permeability. Conventional steam injection thermal recovery has poor viscosity reduction performance and low productivity of a single well, which makes it difficult to develop this type of heavy oil reservoir. In this paper, core flooding experiment and microvisualization equipment were used to study the mechanism of improving the recovery of deep extra heavy oil by using water-soluble viscosity reducer; the realization of water-soluble viscosity reducer in numerical simulation was achieved by using nonlinear mixing rule; the reservoir numerical simulation model of water-soluble viscosity reducer displacement in test well group was established to optimize the development technical parameter of water-soluble viscosity reducer. The results show that compared with waterflooding, the oil displacement efficiency of water-soluble viscosity reducer is increased by 12.7%; watersoluble viscosity reducer can effectively reduce the viscosity of extra heavy oil, under the same temperature and permeability, the higher the concentration of viscosity reducer, the better the viscosity reduction effect, and the smaller the pressure gradient required at the same injection rate; the main mechanism of water-soluble viscosity reducer for enhancing oil recovery is to form oil in water emulsion, which can reduce the viscosity and interfacial tension of crude oil and reduce the residual oil saturation; in the pilot well group, the optimized injection concentration of water-soluble viscosity reducer is 3%, and the optimal injection amount of water-soluble viscosity reducer solution is 50 t/d; water-soluble viscosity reducer displacement was implemented in the pilot well group, the average daily oil of well group was increased from 1.8 t/d to 7.34 t/d, and the pilot well group has achieved good development performance.

2025, Journal of Dispersion Science and Technology

A typical anionic surface active ionic liquid (SAIL), 1-butyl-3-methyl-imidazolium dioctylsulfosuccinate (BMOT), was introduced to chemical enhanced oil recovery. The ability of BMOT to reduce the interfacial tension (IFT) of water/crude oil was evaluated for its potential application in surfactant flooding. Compared with the traditional anionic surfactant AOT and another anionic SAIL 1butyl-3-methylimidazolium dodecyl sulfate used in the control experiments, the effects of intramolecular electrostatic attraction and size match were employed to interpret the high interfacial activity of BMOT. The effects of salt and temperature on the water/crude oil IFT further verified the proposed mechanisms. Moreover, BMOT exhibited a satisfactory displacement performance to greatly improve the crude oil recovery (12.5% of the initial oil in place) in core flooding tests.

2025, Colloids and Surfaces A: Physicochemical and Engineering Aspects

A mixed cationic surface-active ionic liquid/anionic surfactant system consisting of N-dodecyl-N-methylpyrrolidinium bromide (L12) and sodium dodecyl sulfate (SDS) was used for chemical enhanced oil recovery (EOR). The mixed L12/SDS surfactant system could cause remarkable effects on the interfacial tension (IFT) between water and a model oil (toluene and n-decane, v:v = 1:1), and the strength of the effect depended on the L12/SDS molar ratio. The effects of temperature and salinity on the IFT were systematically investigated to verify the mechanism of the mixed surfactants at the interface. Moreover, the mixed L12/SDS surfactant system showed the desired ability to reduce the IFT of water/crude oil, greatly improving oil recovery with the assistance of a polymer in core flooding tests.

2025, Geofluids

2025, Journal of Dispersion Science and Technology

2025, Colloids and Surfaces A: Physicochemical and Engineering Aspects

2025, Proceedings of SPE/DOE Improved Oil Recovery Symposium

Relative permeability and capillary pressure functions define how much oil can be recovered and at what rate. These functions, in turn, depend critically on the geometry and topology of the pore space, on the physical characteristics of the rock grains and the fluids, and on the conditions imposed by the recovery process. Therefore, imaging and characterizing the rock samples and the fluids can add crucial insight into the mechanisms that control field-scale oil recovery. The fundamental equations of immiscible flow in the imaged samples are solved, and one can elucidate how relative permeability and capillary pressure functions depend on wettability, interfacial tension and the interplay among viscous, capillary and gravitational forces. This knowledge enables one to answer questions such as: Can a change of injected brine salinity increase oil recovery and by how much? How much more oil would be recovered if advancing contact angles could be modified? Does water injection help to recover sufficiently more oil or is it just for pressure maintenance? How can water imbibition be enhanced and oil trapping limited? Can relative permeabilities be modified with a polymer or with a chemical agent, such as an electrolyte or surfactant? Can one rely on gravity drainage of oil films to increase recovery? These and many other questions may be answered through a combination of imaging and calculations presented here. This paper summarizes the development of a complete quasi-static pore network simulator of two-phase flow, "ANetSim," and its validation against Statoil's state-of-the-art proprietary simulator. ANetSim has been implemented in MATLAB® and it can run on any platform. Three-dimensional, disordered networks with complex pore geometry have been used to calculate primary drainage and secondary imbibition capillary pressures and relative permeabilities. The results presented here agree well with the Statoil simulations and experiments.

2025, Energy Procedia

The oil and gas industry has a long history of evaluating the adequacy of subsurface traps for containing buoyant fluids and has developed methods for weighing the geologic probability of trap leakage when limited data are available. We have adapted these methods for evaluating the adequacy of sub-surface saline formation traps for CO 2 storage. A principal difference in the evaluation for gas and oil exploration versus CO 2 storage is that the probability of leakage is viewed differently. The oil and gas industry tolerates substantial leak probabilities in exploration if the potential gas or oil accumulation is sufficiently large, but the tolerance for CO 2 leakage (i.e. the probability of injected CO 2 returning to the surface) will likely be much lower, and that low tolerance has the potential to limit the amount of CO 2 injected into a subsurface trap. We consider three types of saline formation traps: x Depleted gas or oil fields x Drilled trap structures that failed to discover commercial gas or oil volumes x Undrilled trap structures Each of these types has some probability of CO 2 leakage, but the geologic probability is smaller and better constrained in depleted gas or oil fields and greater and more uncertain in untested structures. However, each of these trap types still possess some geologic probability of leakage. We evaluate the overall probability by considering for each trap element (e.g., capillary seal capacity) the likelihood that each element is adequately developed and the quality and quantity of data available to make that judgment. By following procedures applied to gas and oil trap evaluation, we arrive at probability distributions for a range of CO 2 fill limits. What this analysis reveals, however, is that if we fill traps with CO 2 to levels with minimal probability of CO 2 leakage, the volume of CO 2 that could be stored in subsurface traps is small. Moreover, all traps will, on average, have huge remaining pore volumes that could accommodate additional CO 2 storage and could go unfilled (i.e. pore volumes with a higher probability of leakage). We propose an evaluation method based on a series of redundant traps in a fill-leak sequence. The purpose of secondary and tertiary traps arranged in series is that they allow for filling the primary trap to its uncertain fill limit while minimizing the chance of leakage to the surface.

2025

Brazilian Atlas of CO2 Capture and Geological Storage : Atlas Brazileiro de Captura e Armazenamento Geologico de CO2

2025

Resumen Se presenta la evaluación de una placa de acero cuerpo humano, la cual corresponde a una lá mina ortopédica que estuvo en funcionamiento durante doce meses. utilización fue utilizada como material de referencia. Se evaluaron las propie-dades morfológicas y electroquímicas. se realizó mediante microscopía óptica para observar el deterioro generado por la exposición al medio agresivo. El desempeño electroquímico de los aceros se evaluó mediante la técnica de espectroscopía de impedancia electro-química (EIS) y curvas de polarización anódica, los resultados de las curvas de polarización y los diagramas de Nyquist indican que la placa retirada presenta un valor de corriente y velocidad de corrosión mayor con respecto al sistema de referencia. Evaluación mecánica y electroquímica de una placa de acero 316-LVM previamente utilizada en el organismo humano 52 Introducción La utilización de biomateriales metálicos en implantes precisa de dos características im-portantes: la primera, ...

2025

The first Polish installation for the reinjection of acid gases started to run on the Borzęcin gas reservoir operated by Polish Oil & Gas Company. The installation was designed based on the results of an Oil & Gas Institute (INiG) research. The gas injected into the Borzęcin structure contains approximately 60% of CO2 and 15% of H2S. It should be emphasized that the Borzęcin injection program was the first full scale acid gas reinjection process of practical value carried out on a running production object as early as 1996. In 2004 a similar process on a larger scale was realized in the Krechba field in Algeria by BP and Statoil [1]. Borzęcin is considered to be a unique experimental plant which allows us to investigate the acid gas sequestration process. Contrary to other large reservoirs – the small bulk volume of the onshore Borzęcin structure enables us to analyze the sequestration process in a short time scale.

2025, Frontiers in Chemistry

Surfactants have a great number of applications. Among these chemicals, petroleum sulfonates have been widely used due to their effectiveness in reducing interfacial tension. This is the case of sodium octylnaphthalene sulfonate which is a solid with a very low solubility in water. To overcome these drawbacks, this work aimed to synthesize new surface active ionic liquids based on a naphthalene sulfonate anion and traditional cations of these salts (imidazolium, pyrrolidinium, and pyridinium). The new chemicals showed high thermal stability, ionic liquid nature, and a stronger surfactant character than the original naphthalene. Moreover, they were found to be water soluble which greatly facilitates their application in the form of aqueous formulations. 1-Hexyl-3-methylimidazolium 4-(n-octyl)naphthalene-1-sulfonate showed the best capacity to reduce water-air and water-oil interfacial tension.

2025, ChemPhysChem

Ionic liquids derived from prolinium esters, previously described as fully green and stable, were found to decompose in the presence of water by ester hydrolysis. To avoid this problem, a new family of these biodegradable salts incorporating an alcohol instead of the ester group is proposed. From this family, two novel ionic liquids that incorporate the prolinolium cation [HOPro] and the [DS] or [DBS] anion were selected (DS=dodecylsulfate; DBS=dodecylbenzenesulfonate). Both salts are liquid at room temperature, a property not usually found in ionic surfactants, and are also chemically and thermally stable. Moreover, they are more effective in reducing the surface tension of water than the corresponding traditional surfactants in the form of sodium salts, being useful for applications related to their aggregation capacity. They were tested for surfactant enhanced oil recovery and an optimal formulation for reservoirs at high salinity and temperature, able to produce ultra‐low interf...