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Channeling between injectors and producers leads to bypassed oil left in the reservoir, which is one of most common reasons that wells in mature oil fields experience high water cut after long-term waterflooding. Identification and evaluation of the higher permeable channels (thief zones) are the key to effectively plug these thief zones and improve the conformance of water flood. This study applies three different methods to identify and evaluate the thief zones of a water injection project in North Buzazi Oilfield, a thick-bedded unconsolidated sandstone heavy oil reservoir in Manghestau, Kazakhstan. The thief zones, which evolve as a result of formation erosion and sand production, are identified and classified with respect to four different levels of significance using fuzzy comprehensive evaluation, production/injection profile method and pressure index (PI) methods. Good consistency is observed among the identification results using these methods. Finally, we present two ways to quantitatively evaluate the characteristics of the thief zones using water–oil-ratio as the input, which can be readily applied for future field development design. [ABSTRACT FROM AUTHOR]

Carbon corrosion in catalysts is one of the main limitations of proton exchange membrane fuel cell (PEMFC) lifetime. Water flooding can accelerate the carbon corrosion rate in PEMFCs, especially at high current densities. Increasing the operation temperature can effectively mitigate water flooding and improve the water management performance of PEMFCs. However, elevated temperatures also increase the carbon corrosion reaction kinetics, accelerating the degradation of PEMFCs lifetime. To study the effects of temperature on carbon corrosion at high current densities, PEMFCs operating for 100 h at 65 °C and 90 °C under 1600 mA·cm−2 were investigated. The results showed that the electrochemical active surface area (ECSA) of the cathode catalyst layer decreased by 9.16% and 13.92% at 65 °C and 90 °C, respectively. The reduction rate of the catalyst layer in the nonflooding area increased as the operating temperature increased. However, the reduction rate decreased by 69.82% and 54.04% at 65 °C and 90 °C, respectively, at the outlet of the PEMFC. Therefore, water flooding is the key issue causing lifetime degradation, and water management is essential for PEMFCs that operate at high current densities, especially at the outlet of PEMFCs.

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Many studies have been carried out to investigate the cyclic water injection (CWI) in enhancing oil recovery, while most of the target reservoirs are conventional, and the study for CWI in application to ultralow permeability reservoir is limited. In this study, a combination of experiment and numerical simulation was used to evaluate the performances of CWI in ultralow permeability reservoir. The results indicate that short pressurizing period but long depressurizing period gives the low possibility of water breakthrough and sufficient time for oil/water exchanging and redistribution, which achieves better oil recovery efficiency. In addition, high pressurizing pressure is a good compensation to the reservoir energy, and pushes the water into the far region to displace more oil. The optimized operation parameters for the core-scale experiments are further evaluated with numerical simulation of a realistic ultralow permeability reservoir located in Ordos basin, China, and consistent results between experiment and simulation are found. In the simulation, the optimal injection period and injection pressure during the pressurizing cycle are 20 days and 14 MPa, respectively; the optimal injection period and injection pressure during the depressurizing cycle are 60 days and 2 MPa, respectively. Good field response has been achieved after the implementation of the optimized parameters. This work, for the first time, systematically studies the performances of CWI technique in application to ultralow permeability reservoirs both at core scale and reservoir scale, and it provides theoretical and practical implications for enhancing oil recovery in similar types of ultralow permeability oil reservoirs. [ABSTRACT FROM AUTHOR]

This work has assessed the comparative performance of four salts (NaCl, K2SO4, CaCl2, and MgSO4) in the optimized salinity water flooding mode. This was done by carrying out core flooding tests using crude oil, brines and cores sourced from a Niger Delta field. Inter-facial Tension tests were also performed on each crude brine system to understand the specific role of fluid-fluid interaction. The results obtained from the study are quite interesting as additional recovery ranging from 5-26% were obtained in the secondary and tertiary mode. [ABSTRACT FROM AUTHOR]

• A 1D two-phase multi-physics model is developed for a water-cooled PEMFC. • Two dimensionless indices are defined to represent the distribution features in MEA. • Porosity, permeability, and hydrophobicity are the main degradation parameters. • Component decay increases the chance of water flooding in the cathode electrode. • Water flooding increases the non-uniform distribution of physical fields in MEA. At present, a small number of studies aim at the influence of degraded components on the distribution characteristics in water-cooled proton exchange membrane fuel cells (PEMFCs). This study develops a one-dimensional (1D) two-phase multi-physics model for a water-cooled PEMFC and investigates the parameter distributions along the through-plane direction. The model is accomplished by self-written codes and validated by the experimental data. Two dimensionless indices (TUI, WUI) are defined to present the distribution uniformity in membrane electrode assembly (MEA). The current intensity and gaseous relative humidity (RH) are the primary factors affecting MEA temperature and membrane water. However, with the anode RH increasing from 0.2 to 1.0, the WUI value decreases from 0.123 to 0.104 despite the water content increasing from 8.9 to 14.4. The results through comparison indicate that, in case 2, severe degradation in porosity, hydrophobicity, and thickness of component materials leads to a high liquid saturation of 0.82 on CCL, which increases the hence of water flooding. In return, the water flooding further reduces voltage performance by 0.1 V compared with the normal cell, even accelerating the component degradation. [ABSTRACT FROM AUTHOR]

Abstract Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), and a series of house-made deep eutectic solvents (DES3–7, 9, 11, and 14). The interfacial tensions (IFT) between oil phase and some chemical solutions are also determined. Experimental results indicate that both the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands, even though cationic surfactant significantly decreases the oil–water IFT while ionic liquid does not. The high pH NaBO2 solution does not demonstrate significant effect on oil recovery improvement and IFT reduction. The anionic surfactants (O242 and O342) are effective in enhancing oil recovery from tight sands through oil–water IFT reduction and emulsification effects. The DESs drive the rock surface to be more water-wet, and a specific formulation (DES9) leads to much improvement on oil recovery under counter-current imbibition condition. This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs.

Practically in all oil fields water injection is performed to maintain formation pressure. At bottom holes of injection wells pressures are created which significantly exceed formation pressure. In case of significant layer to layer heterogeneity water from injection wells will start flowing through low filtration resistance channels to productive wells. In the most intense way movement of injection water from injection well to productive well manifests itself in high viscosity oil reservoirs. In case of productive well water flooding works on water shutoff and equalizing input profiles are performed. To evaluate time of water breakthrough from productive well to injection well using software suite TempestMore a series of mathematic experiments was made to forecast displacement front movement in formation with different formation oil viscosities, reservoir permeability, bottom hole pressures in injection and productive well. Information on fluid properties and relative permeability at fields of Nozhovskaya group (Perm territory) was used. According to results of generalization of simulation data an equation for evaluation of time of displacement front movement in reservoir is obtained. Analyzing calculation results, it is possible to conclude that time of displacement front movement for certain distance is influenced by mobility coefficient according to exponential dependency. In reservoirs with mobility over 2 μm2/Pa*sec water-oil front moves with velocity of around 1 m/day. Comparison of forecasted values of production wells water flooding time for high viscosity oil reservoir obtained by hydrodynamic simulation and equation developed demonstrates high enough results reproducibility. Usage of the equation will permit to plan in advance measures on well water shutoff and equalizing input profiles.

Abstract All the time the flow of fluids happens below the surface of the earth. These flow processes can only be imagined, but not be fully visualised on how fluid flow behaviour occurs though the porous medium of the rocks. Hence comes the play of microfluidic micromodels. These are a transparent version of slices (2 dimensional) porous structure of rocks such as sandstone duplicated onto materials such as glass, polymers and silicon wafers. Fluids such as crude oil, surfactant and polymer solutions and gases such as carbon dioxide (CO2) are injected through special pumps into these transparent micromodels. The flow patterns and behaviours hence developed inside the micromodels are studied and analysed. Micromodels have helped in different branches of science such as medicine, genetics, liquid channelling and enhanced oil recovery (EOR). The concern of this paper is to study the flow behaviour and EOR in micromodels. Micromodels can be made to represent a micro version of a partially saturated rock with crude oil. The various chemical EOR processes such as surfactant flooding, polymer flooding, gas flooding injected into crude oil filled micromodels with water saturation is studied. The advancement of front developed between displacing and displaced fluids, the fingering effect, the presence of high permeability streaks is observed. Also the breakthrough of the flood front is analysed from the various experiments reviewed. This review paper is undertaken so as to help researchers find a consolidated and concise literature of the trends and developments in microfluidics especially in EOR.

This paper presents the viscosifying and oil recovery efficiencies of a novel high-molecular-weight ternary polyampholyte (TPA), composed of 80 mol.% acrylamide (AAm) (a nonionic monomer), 10 mol.% 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS) (an anionic monomer), and 10 mol.% (3-acrylamidopropyl) trimethylammonium chloride (APTAC) (a cationic monomer), in various high-salinity brines as compared to the efficiency of hydrolyzed poly(acrylamide) (HPAM), which is the most commonly used polymer in oil production. The results show that, in a range of salinity from 200 to 300 g∙L−1, the viscosity of the TPA solution is rather high and relatively stable, whereas that of HPAM severely decreases. The ability of TPA to increase its viscosity in extremely high salinity brines is explained by the antipolyelectrolyte effect, resulting in the unfolding of macromolecular chains of charge-balanced polyampholytes at a quasi-neutral state, which occurs due to the screening of the electrostatic attraction between oppositely charged moieties. The novelty of this research is that, in high-salinity reservoirs, the amphoteric terpolymer Aam-AMPS-APTAC may surpass HPAM in oil displacement capability.

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Copyright of Special Oil & Gas Reservoirs is the property of Special Oil & Gas Reservoirs Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

This paper presents an assessment of infill drilling opportunities in a complex multi-layered heterogeneous carbonate formation located in Abu Dhabi offshore. The subject field was developed last century and is currently undergoing further development with line drive horizontal wells. The field is being redeveloped for improved oil recovery at higher production rates with long horizontal wells. An infill assessment process is defined using sector model reservoir simulations for the specific reservoir. Reservoir simulations are performed on pattern sector models to establish the optimum grid for infill evaluation. Also, the models with an appropriate grid size are used to optimize infill placement (vertical and lateral well placement) and infill drilling timing for a couple of geologically similar areas. In the second step, the sector model results are applied to test the full-field infill development plan. The relatively homogeneous geological area shows very uniform displacement with 1-km spaced wells and gives no considerable benefit of incremental recovery through infill drilling. However, in a comparatively heterogeneous geological area, considerable incremental oil recovery is quantified. In brief, this paper presents a detailed infill drilling and well placement assessment process workflow for the re-development of a multi-layered heterogeneous reservoir. [ABSTRACT FROM AUTHOR]

Water flooding is one of widely used technique to improve oil recovery from conventional reservoirs, but its performance in low-permeability reservoirs is barely satisfactory. Besides adding chemical agents, ultrasonic wave is an effective and environmental-friendly strategy to assist in water flooding for enhanced oil recovery (EOR) in unconventional reservoirs. The acoustic frequency plays a dominating role in the EOR performance of ultrasonic wave and is usually optimized through a series of time-consuming laboratory experiments. Hence, this study proposes an unsupervised learning method to group low-permeability cores in terms of permeability, porosity and wettability. This grouping algorithm succeeds to classify the 100 natural cores adopted in this study into five categories and the water flooding experiment certificates the accuracy and reliability of the clustering results. It is proved that ultrasonic waves can further improve the oil recovery yielded by water-flooding, especially in the oil-wet and weakly water-wet low-permeability cores. Furthermore, we investigated the EOR mechanism of ultrasonic waves in the low-permeability reservoir via scanning electron microscope observation, infrared characterization, interfacial tension and oil viscosity measurement. Although ultrasonic waves cannot ameliorate the components of light oil as dramatically as those of heavy oil, such compound changes still contribute to the oil viscosity and oil-water interfacial tension reductions. More importantly, ultrasonic waves may modify the micromorphology of low-permeability cores and improve the pore connectivity.

The need for energy, especially the petroleum-based one, is steadily increasing along with population growth and technological advancement. Meanwhile, oil exploitation from oil reservoirs using primary and secondary techniques can only obtain about 30%-50 % out of the original oil in place. Enhanced Oil Recovery (EOR) is a method for increasing oil recovery from a reservoir by injecting materials that are not found in the reservoir, such as surfactant, polymer, etc. This research aims to develop a mathematical model representing two-phase flow through porous media in the EOR process. This model was extended from mass balance and fluid flow in porous media equations. The reliability of the model was then validated by water flooding and polymer flooding experiment. A porous media, constituted by a silica sand pack, was saturated with 2 % brine and sequentially flooded with HPAM polymer solution at various concentrations (5,000-15,000 ppm). The volume of the oil coming out from the media at any time intervals was measured. Validation of the model was carried out by optimizing the model parameters to obtain the best curve-fitting on the plot of the percentage of cumulative recovered oil against time. The results showed that the proposed mathematical model was reliable enough to express both water and polymer-flooding processes. [ABSTRACT FROM AUTHOR]

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The adjustment and control of the water injection rate is a commonly used method for increasing the cumulative oil production of waterflooded reservoirs. This article studies the production optimization problem under the condition of a fixed total water injection rate. The production process is divided into several segments. Considering the correlation between the segment's time intervals and the well's injection rate distribution, a simultaneous optimization of both segmented time and injection rate is proposed for enhancing net present value. Both empirical simulations and field application demonstrate that the suggested methods produce the highest increase in net present value – of approximately 13% and 10%, respectively – and significantly improve water flooding efficiency compared to other conventional schemes, such as segmented oil production optimization, cumulative oil production optimization and Bang-Bang control. The proposed methods under a 2-segment division increase oil production efficiency and greatly reduce adjustment costs. [ABSTRACT FROM AUTHOR]

Oil production from oil reservoirs containing oil in water (O/W) and water in oil (W/O) emulsions has always been accompanied by some problems. The increase in apparent viscosity of the oil, pore throats blockage, and consequently, the increased rate of pressure drop are among these problems. Investigating the behavior of this type of oil in the porous medium can help to understand the problem. Although metal oxide nanoparticles can increase the oil recovery and therefore improve the performance of reservoirs, they can result in the formation of W/O emulsions, due to their potential properties. In this study, the formation and stability of the emulsion were first evaluated and then the nanofluids were injected into a carbonate sand pack. Tests were conducted in the ambient condition. The amount of produced oil in the presence of three nanoparticles consist of TiO2, SiO2, and Fe3O4 has been investigated. Moreover, the effect of water injection on the system containing emulsions created by both different ions present in the seawater and iron oxide nanoparticles has been investigated. The results show that the iron oxide nanoparticles cause high-pressure oscillations by forming more stable emulsions in the porous media.

Abstract This paper presents an improved procedure for generating pseudorelative permeability curves for stratified water flooding using either constant pressures or constant flux at the reservoir/grid block boundaries. The concept of pseudorelative permeability reflects the generation of a relative permeability curve that can be used to represent the entire reservoir thickness, rather than a specific layer during reservoir simulation, thus saving computational time. In this paper, fractional flow theory is applied to the generation of pseudorelative permeability curves for (1) constant flow rate and (2) constant pressure boundary conditions. Previously, pseudorelative permeability curves were generated for constant flow rate only, since the analytical solutions for constant pressure boundaries were non-existant. In this paper, this restriction has been removed based on novel analytical solutions for constant pressure boundaries. The method within this paper also differs from previous methodologies and studies, which are all based on an approximation using piston-like displacement for water flooding. Instead, this new model uses fractional flow theory to its fullest extent to generate pseudorelative permeability curves that are physically more realistic. The solution is extended to generate pseudorelative permeability curves for waterflooding of a reservoir under the assumption of constant pressure boundaries which is an equally realistic assumption in comparison to constant flow rate. The generated pseudorelative permeability curves are used in a 2D areal reservoir model in a standard reservoir simulator to predict the behavior of the fully layered 3D reservoir model. It is found that there is considerably better agreement between the results obtained with this new method and the fully layered reservoir model compared to previous methods.

Abstract The study of two-phase immiscible flow in porous media using electrokinetics is important in different fields including the remediation of hydrocarbon contaminated soils and enhanced oil recovery. While electrokinetic technology has been traditionally used for treatment and decontamination of hydrocarbon polluted sites, electrically enhanced oil recovery (EEOR) is relatively new. Although a few laboratory and field experiments have investigated the potential promise of the EEOR method, further investigation is necessary to better understand the fundamentals and the importance of different parameters/processes that affect the oil production in this method. This study presents a numerical investigation of two-phase flow in EEOR method in an attempt to provide insight into the feasibility of, and the important parameters involved in this method. A sensitivity analysis is performed on important parameters involved in EEOR combined with water flooding. Most of the investigated reservoir and operational parameters were found to be significant and critical to the transport phenomena controlling the oil production. In addition, the results showed that the applied electrical gradient involved in EEOR combined with water flooding contributes to a small increase in oil production.

Water flooding technology is an important measure to enhance oil recovery in oilfields. Understanding the pore-scale flow mechanism in the water flooding process is of great significance for the optimization of water flooding development schemes. Viscous action and capillarity are crucial factors in the determination of the oil recovery rate of water flooding. In this paper, a direct numerical simulation (DNS) method based on a Navier–Stokes equation and a volume of fluid (VOF) method is employed to investigate the dynamic behavior of the oil–water flow in the pore structure of a low-permeability sandstone reservoir in depth, and the influencing mechanism of viscous action and capillarity on the oil–water flow is explored. The results show that the inhomogeneity variation of viscous action resulted from the viscosity difference of oil and water, and the complex pore-scale oil–water two-phase flow dynamic behaviors exhibited by capillarity play a decisive role in determining the spatial sweep region and the final oil recovery rate. The larger the viscosity ratio is, the stronger the dynamic inhomogeneity will be as the displacement process proceeds, and the greater the difference in distribution of the volumetric flow rate in different channels, which will lead to the formation of a growing viscous fingering phenomenon, thus lowering the oil recovery rate. Under the same viscosity ratio, the absolute viscosity of the oil and water will also have an essential impact on the oil recovery rate by adjusting the relative importance between viscous action and capillarity. Capillarity is the direct cause of the rapid change of the flow velocity, the flow path diversion, and the formation of residual oil in the pore space. Furthermore, influenced by the wettability of the channel and the pore structure’s characteristics, the pore-scale behaviors of capillary force—including the capillary barrier induced by the abrupt change of pore channel positions, the inhibiting effect of capillary imbibition on the flow of parallel channels, and the blockage effect induced by the newly formed oil–water interface—play a vital role in determining the pore-scale oil–water flow dynamics, and influence the final oil recovery rate of the water flooding.

Based on the characteristics of injection-production units in fractured-vuggy carbonate reservoirs, nine groups of experiments were designed and performed to analyze the interference characteristics and their influencing factors during water flooding. Based on percolation theory, an inversion model for simulating waterflooding interferences was proposed to study the influence laws of different factors on interference characteristics. The results show that well spacing, permeability ratio, cave size, and cave location all affect the interference characteristics of water flooding. When the cave is located in high permeability fractures, or in the small well spacing direction, or close to the producer in an injection-production unit, the effects of water flooding are much better. When the large cave is located in the high-permeability or small well spacing direction, the well in the direction with lower permeability or smaller well spacing will see water breakthrough earlier. When the cave is in the higher permeability direction and the reserves between the water injector and producer differ greatly, the conductivity differences in different injection-production directions are favorable for water flooding. When the injection-production well pattern is constructed or recombined, it's better to make the reserves of caves in different injection-production directions proportional to permeability, and inversely proportional to the well spacing. The well close to the cave should be a producer, and the well far from the cave should be an injector. Different ratios of cave reserves to fracture reserves correspond to different optimal well spacings and optimal permeability ratios. Moreover, both optimal well spacing and optimal permeability ratio increase as the ratio of cave reserves to fracture reserves increases. [ABSTRACT FROM AUTHOR]

This study aims to develop a grid-based smart proxy model (G-SPM) for water flooding enhancement under different injection/production scenarios. The contribution of this work is combining experimental design and data mining techniques to prepare a high-quality database and introducing a hyper-feature to incorporate flow physics into database. The proxy was constructed by training a sequential neural network model. Validating G-SPM on three blind cases showed that oil saturation in grid blocks is accurately predicted in shorter time compared to numerical simulator. This study also revealed that data from one previous time step is enough to be used in G-SPM training. [ABSTRACT FROM AUTHOR]

Copyright of China Sciencepaper is the property of China Sciencepaper and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The fractured-vuggy reservoir is one important carbonate reservoir in the world. Compared with the sandstone reservoir, the carbonate fractured-vuggy reservoir has some significant characteristics such as the strong reservoir dispersion and the single interwell connectivity. Currently, the evaluation indexes, the evaluation standards and evaluation methods for water-flooding development effect in the fractured-vuggy reservoir are not uniform. To solve the issues include large uncertainty in evaluation and a big difference in evaluation results caused by the different indexes in the fractured-vuggy reservoir, we choice five typical evaluation indexes to estimate waterflooding development effect in fractured-vuggy reservoir. The indexes include increase in recovery rate, energy keeping rate, annual comprehensive oil production natural decline rate, water/oil exchange rate and water content rise rate. Meanwhile, a new evaluation method of evaluating fractured-vuggy reservoir water-flooding development effect is established based on the uncertain measure. The field application shows that the newly established waterflooding development effect evaluation method has a good match with reservoir dynamic analysis results, and our method can be used for the waterflooding development effect evaluation in fractured reservoir. [ABSTRACT FROM AUTHOR]

During the long-term water flooding development of the reservoir, the fluid (oil, water, and oilwater mixture) that percolates in the underground reservoir affects the reservoir's skeleton (mineral particles, matrix and cement) and the pore throat network due to a combination of factors such as physical/chemistry weathering, mechanical/chemical denudation, mechanical/chemical handling, mechanical/chemical deposition, etc. In this paper, the reservoir physical properties during different water injection periods in the X oilfield were studied through multiple tests. Experimental results show that as the degree of water injection increases, the physical properties of the reservoir change. The contact pattern between the particles changes from the original line contact to point contact. The physical properties of the reservoir become better, the pore shape becomes more regular and smooth, the average shape factor increases, the average specific surface decreases, the average pore radius increases, and the face rate increases. In addition, the connectivity of pores increases. The changes in the reservoir structure of the X oilfield are mainly caused by the weathering of the reservoir development fluid, the erosion of the reservoir development fluid, the transportation of the reservoir development fluid, and the deposition of the reservoir development fluid. [ABSTRACT FROM AUTHOR]

Low Salinity Water Flooding (LSWF) is an improved water flooding technique that enhances the oil recovery with a relatively cheaper cost. Such technique becomes vital as the oil price keeps falling significantly at the global scale. Although plenty of research work has been devoted towards LSWF in conventional sandstone reservoirs, the research on LSWF in fractured reservoirs is still at its beginning stage and a lot needs to be explored in this direction. In this context, an attempt has been made in order to deduce the conceptual model that will describe the mechanism of LSWF in a fractured aquifer using dual-porosity approach. Unlike the conventional sandstone reservoirs, which are based on singlecontinuum concept, the fractured reservoirs are associated with a multi-continuum based concept and hence, the mechanism of LSWF still becomes complex. Two different types of conceptual models have been proposed in the work. The mechanism of LSWF technique takes place only within the lowpermeable rock-matrix, while the high-permeable fracture just acts as a conduit and carries the released oil towards the production well in Model 1. However, in Model 2, the mechanism of LSWF technique takes place both within the low-permeable rock-matrix as well as on walls of the high-permeable fracture. In this context, a detailed list of possible queries that may arise during the experimental/field investigations of LSWF in a fractured reservoir has been discussed in detail. This work is expected to provide further insights for carrying out the LSWF in a complex fractured reservoir. [ABSTRACT FROM AUTHOR]

This paper presents a multi-level procedure for production and injection scheduling through a numerical model-based optimization of well control variables. To calculate the net present value (NPV), the objective function of optimization, this procedure uses a number of discretized systems for a reservoir model with different degrees of up-scaling prepared according to a multi-resolution wavelet technique. These up-scaled models were incorporated into optimization based on a probability function. In early optimization iterations, due to the necessity to explore the search space quickly, the coarsest grid model has a higher chance for selection than the others; however, by a selection (with a low probability) of the finest up-scaled grid model in these iterations, solutions and objective function were tuned. In the later iterations of optimization, the finest up-scaled grid model probability was the highest in order to ensure the reliability of the final solution. The optimization algorithm is an adaptive simulated annealing algorithm coupled with a polytope. This procedure was evaluated in two case studies. The first case study was a horizontal 2D oil model with water flooding. The second case study was a vertical 2D oil model with gas injection. The results show that the proposed optimization procedure provides approximately the same accuracy compared to the situation in which the fine grid model is used for all the optimization iterations. Also, the run-time for the proposed optimization procedure is comparable to the run-time of the optimization in which only the coarsest grid model is used to calculate objective function. Moreover, the superiority of the wavelet-based up-scaling over an analogous multiple grid system optimization using uniformly up-scaled models is presented. [ABSTRACT FROM AUTHOR]

Considering the maturity and reaching to half-life production in many petroleum reservoirs, development of methods for maintenance and enhanced oil recovery are becoming crucial. One of the most common methods for the mentioned purposes is water flooding. However, there is a drawback to this method that is scaling in reservoirs due to the mixing of injection water with formation water, which would cause formation damage and reduction in production. Before the water flooding begins, it is necessary to simulate the compatibility of brine and injection water. For this purpose, in this study simulations with ion association modeling (ion pairing methods) have been undertaken. To verify the simulations results, X-Ray powder Diffraction (XRD) and Scanning Electron Microscope (SEM) tests have been performed. Acquired data have been compared with XRD and SEM, which show that the simulations are correct. Also, SEM test determined the crystal's structure of scale. Results show that carbonate scale is the major precipitation in this study. [ABSTRACT FROM AUTHOR]

Brines containing surface-active divalent ions such as Ca2+, Mg2+ and SO42− impact the stiffness, strength and time-dependent deformation of water wet Mons outcrop chalk. This study documents how stiffness and strength of wettability-altered oil and water-saturated (mixed wet) Mons chalk compare to water-saturated and water wet samples during hydrostatic loading and creep. During hydrostatic creep, the strain rate response to magnesium chloride (MgCl2) brine injection is compared for water wet and mixed wet samples. For the mixed wet samples, the oil production was estimated during compaction and non-equilibrium MgCl2 flow. The results presented here were then compared to a similar test series on Kansas outcrop chalk. The differences were interpreted in terms of difference in physical parameters such as porosity and pore size. Two Mons samples were wettability-altered and tested in parallel to two completely water wet samples from the same chalk block at hydrostatic conditions and 130 °C. It was found that beyond the experimental uncertainty, the stiffness and yield strength measurements showed insignificant differences for water wet and mixed wet Mons samples. This is contrary to Kansas chalk where mixed wet samples were systematically stronger and stiffer than water wet samples. In the following creep phase, both water wet and wettability-altered Mons chalk samples gave trends comparable to each other during a stagnant phase and a following MgCl2 injection phase at varying flow rates. Similar observations were reported for water wet and wettability-altered Kansas chalks as well. Further, the same chemical reactions were observed for Kansas and Mons chalks and were found to be insensitive to the initial wettability and oil/water saturations. The oil production observations from Mons chalk showed that 43% of the total oil was recovered during early-stage compaction with no flow, whereas Kansas chalk did not produce any oil at no-flow conditions. After the oil recovery from the first 2–3 pore volumes of brine flow, no further oil production was observed due to compaction or non-equilibrium brine flow in any of the two chalk types. [ABSTRACT FROM AUTHOR]

Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity. As such, spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing. The chemical agents added to the injected water can alter the interfacial properties, which could help further enhance the oil recovery by spontaneous imbibition. This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition. We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition, including a cationic surfactant (C12TAB), two anionic surfactants (O242 and O342), an ionic liquid (BMMIM BF4), a high pH solution (NaBO2), and a series of house-made deep eutectic solvents (DES3–7, 9, 11, and 14). The interfacial tensions (IFT) between oil phase and some chemical solutions are also determined. Experimental results indicate that both the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands, even though cationic surfactant significantly decreases the oil–water IFT while ionic liquid does not. The high pH NaBO2 solution does not demonstrate significant effect on oil recovery improvement and IFT reduction. The anionic surfactants (O242 and O342) are effective in enhancing oil recovery from tight sands through oil–water IFT reduction and emulsification effects. The DESs drive the rock surface to be more water-wet, and a specific formulation (DES9) leads to much improvement on oil recovery under counter-current imbibition condition. This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs. [ABSTRACT FROM AUTHOR]

As the conventional prediction methods for production of waterflooding reservoirs have some drawbacks, a production forecasting model based on artificial neural network was proposed, the simulation process by this method was presented, and some examples were illustrated. A workflow that involves a physics-based extraction of features was proposed for fluid production forecasting to improve the prediction effect. The Bayesian regularization algorithm was selected as the training algorithm of the model. This algorithm, although taking longer time, can better generalize oil, gas and water production data sets. The model was evaluated by calculating mean square error and determination coefficient, drawing error distribution histogram and the cross-plot between simulation data and verification data etc. The model structure was trained, validated and tested with 90% of the historical data, and blindly evaluated using the remaining. The predictive model consumes minimal information and computational cost and is capable of predicting fluid production rate with a coefficient of determination of more than 0.9, which has the simulation results consistent with the practical data. [ABSTRACT FROM AUTHOR]

Water flooding aids in the recovery of a large volume of oil that would have been dissipated in a depleted oil reservoir. In this paper, the production and economic potentials of Niger delta Reservoir OD-48 have been used to depict it. Reservoir OD-48 had oil originally in place as 9.7457 MMSTB. The oil remaining in the reservoir as at the period that the reservoir innate energy was not sufficient enough to produce oil was 3.51 MMSTB. The reservoir is currently considered as an abandoned reservoir with the left-over oil inside. From the current investigation, it is observed that if a second oil recovery activity is carried out on the reservoir, part of the left over oil will be retrieved. Following the conditions given, about 1.77 MMSTB of the 3.51 MMSTB of oil in Reservoir OD-48 would be produced during the breakthrough time of 760 days. Furthermore, acknowledging the economical facet of the project, Reservoir OD-48 is acceptable for investment. The NPV analysis carried out showed that the NPV of Reservoir OD-48 at an interest rate of 10% is $10.52 million. Considering that the NPV at a breakthrough time is greater than zero, the project is economically beneficial. [ABSTRACT FROM AUTHOR]

An intervention of radiotracer technology in the EOR program has been initiated using commercial core-flood set up. A commercial type of Berea core is used throughout the experiment. 99mTc is chosen as a radioactive tracer for this experiment, which has a half-life of 6 hours and emits gamma rays' energy of 0.104MeV. It is a liquid radiotracer with the activity of 10GBq (270mCi), eluted and prepared by Institute Cancer of Malaysia (IKN) before transporting it to the laboratory at Centre of Research in Enhanced Oil Recovery (COREOR), Universiti Teknologi Petronas. The experiment was conducted after 3.5 half-lives. Thus the activity has reduced to approximately (1.48GBq) 40mCi during injection inside the system. The results can be used to assist the reservoir engineer in determining the exact water-tracer breakthrough, localize the location of water-tracer concerning time, and determine the residence time distribution and mean residence time of the core flood where the hydrodynamics of the flow can be predicted. Moreover, the introduction of radiotracer inside the core flood rig can be translated as secondary oil recovery. The idea is to integrate radiotracer technology into the existing commercial core flood set up (FES350) to track the movement of fluid during waterflooding operation. Besides, it can be considered as the first interaction of radiotracer in the enhanced oil recovery application studies in Malaysia. [ABSTRACT FROM AUTHOR]

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Even though numerical simulators that use the finite difference approach to model the oil and gas fields and to forecast the field performance are popular in the petroleum industry, they suffer from a very long central processing unit (CPU) time in the complex reservoirs with large number of grids. This issue could be resolved by streamline simulation and it could significantly decrease the runtime. This work explains the the streamline simulation concept and then a real oil field is studied using this technique, the streamline simulation is conducted by a commercial simulator, i.e., FrontSim streamline simulator and then the model was analyzed to find the optimum location of infill wells. In this work, 34 different cases were studied using Streamline simulation method and FrontSim software by considering different arrangement of infill wells. It was concluded that a significant enhancement in the ultimate recovery factor of the oil reservoir could be attained by considering different arrangement of the infill horizontal and vertical wells. It was highlighted that the ultimate recovery factor could be increased significantly, i.e., 13%. Additionally the water cut of the field could be reduced significantly. The novelty of this work is to capture the impact of both vertical and horizontal wells on the ultimate recovery enhancement simultaneously using the concept of streamline simulation and optimization of the field performance using streamline simulation concept. [ABSTRACT FROM AUTHOR]

This paper introduces an effective production optimization and a water injection allocation method for oil reservoirs with water injection. In this method, a two-stage adaptive simulated annealing (ASA) is used. A coarse-grid model is made based on average horizon permeability at the beginning iterations of the optimization to search quickly. In the second stage, the fine-grid model is used to provide the accuracy of the final solution. A constrained optimization problem to maximize an objective function based on net present value is implemented. Allocation factors from the streamline simulation are used to help for the appropriate estimation of initial water injection rates. The proposed optimization scheme is used for a field sector simulation model. The results show that the optimized rates confirm the increment of total oil production. Optimized oil production and total water injection rates lead to an increase in the total oil production from 385.983 (initial guess) to 440.656 Msm3. This means a recovery factor increment by 14.16%, while the initial rates were much higher than the optimized rates. Moreover, the recovery factor of optimized production schedule with an optimized total injection rate is 2.20% higher than the initial production schedule with an optimized total water injection rate. The allocation of the water injection rates and the revision of allocation rates result in 446.383 and 450.164 Msm3. The revision of the water rates allocation provides a reduction of water cut during production.

The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities. The results of scanning electron microscopy, X diffraction of clay minerals, nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin, China. A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively, and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water. The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity. The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration. By increasing the content of cations (especially K+ and Mg2+) in the injected water, the water-sensitive damage of the reservoir can be effectively inhibited. The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region. [ABSTRACT FROM AUTHOR]

Doped carbon structures have been developed as non-precious metal catalysts for oxygen reduction reactions (ORR) in polymer electrolyte membrane fuel cells (PEMFCs). Among doped carbon structures, Fe- and N-doped carbon (Fe/N/C) nanostructured catalysts have received attention due to their catalytic activity, comparable to that of Pt, avoiding the use of critical raw materials. However, obviously, its durability is not yet neither fully understood nor comparable to that of traditional catalysts. In this study, we synthesized mesoporous F-doped Fe/N/C, which is a tri-doped carbon nanostructure, as a cathode catalyst for ORR. Tri-doped carbon catalysts with different amounts (x) of F (Fx-Fe/N/C) were prepared using Fe-5,10,15,20-tetrakis(4-methoxyphenyl)-21H,23H-porphine iron(III) chloride and NH 4 F as the Fe/N- and F- doping sources, respectively, and Santa Barbara amorphous-15 as the template. Fx-Fe/N/C with an optimal F content exhibited excellent electrocatalytic performance for ORRs i.e. a high half-wave potential of 809 mV in 0.1 M HClO 4 solution, a maximum power density of 280 mW cm−2, and a high stability for 4000 min at 0.5 V, owing to the high proportion of FeN x and pyridinic N as active sites, strong C–F bonds, and hydrophobic surfaces. We synthesized mesoporous F-doped Fe/N/C, which is a tri-doped carbon nanostructure, as a cathode catalyst for ORR. Fx-Fe/N/C with an optimal F content exhibited excellent electrocatalytic activity and durability for ORRs owing to the high proportion of FeNx and pyridinic N as active sites, strong C–F bonds, and hydrophobic surfaces. [Display omitted] [ABSTRACT FROM AUTHOR]

The hydrogen ejector has been extensively researched due to its cost-effectiveness, durability, and energy efficiency. This study investigates the impact of hydrogen ejectors on the performance and water distribution of different types of flow field proton exchange membrane fuel cells (PEMFCs). The search results demonstrate that hydrogen ejectors can enhance performances and reduce the extent of water flooding in PEMFCs with various flow field designs. Moreover, it has been observed that the performance of PEMFCs with the hydrogen ejector is significantly enhanced as the operating voltage decreases. In addition, the performance and water distribution of serpentine flow field PEMFCs with hydrogen ejectors were investigated under different operating parameters, and the corresponding sensitivity of these parameters was quantitatively determined. Based on the simulation results, it was found that maintaining the anode relative humidity at 60 % and the cathode relative humidity at 20 % can achieve higher performances and reduce the extent of water flooding in PEMFCs with hydrogen ejectors. Through sensitivity analysis of each operating parameter, it is found that the operating pressure and cathode relative humidity have the greatest and least impact, respectively, on the performance of PEMFCs with a hydrogen ejector. • 3D simulation to study water distribution in PEMFCs with hydrogen ejectors. • Hydrogen ejector affects performances of PEMFC with different flow fields. • Hydrogen ejector mitigates water flooding and enhances PEMFC performances. • Sensitivity analysis of operating parameters for PEMFCs with hydrogen ejectors. [ABSTRACT FROM AUTHOR]

This study is aimed at using bio-catalyst (enzymes) for enhanced oil recovery in Niger Delta. Three different enzymes produced from microbial isolates with code ID; LPE1, LPE2 and AME were use in analyzing enzymes effect on the rock-fluid and fluid-fluid interaction test to simulate the conditions in the reservoir. The tests carried out include; wettability, interfacial tension (IFT) and adhesion test. The results from these tests show that addition of enzymes to rock-fluid interface has the potential of enhancing recovery of crude oil. From the result, the use of enzyme caused an alteration in the wettability of the rock from oil-wet to water-wet with a 33° difference. The selected enzyme LPE1 showed a significant difference in reduction of interfacial tension by a factor of 4, while LPE2 and AME did not show any significant difference. In conclusion, the wettability and IFT tests results were the basis for choosing LPE1 for core flooding process. Enzyme (LPE1) flooding after waterflood was able to give an additional 11.5 % oil recovery. From the results, the percentage recovery is a pointer to the fact that when the primary and secondary oil recovery methods are no longer viable in terms of economics, the Enyme enhanced oil recovery is the best method of mobilizing trapped crude oil in the Secondly, there is no negative effect on the crude oil quality using the enzyme-EOR because the enzymes only increase the rate of the chemical reaction on the rock media without undergoing any permanent chemical change., Competing Interests: The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (© 2024 The Authors.)

• Improvement of cement kiln dust by iron slag and nanosilica. • Flooding of the cement kiln dust modified by slag and nanosilica. • Freeze-thaw durability of the cement kiln dust modified by slag and nanosilica. • Chemical stability of the cement kiln dust-slag-nanosilica composite immobilized radioactive waste. Cement production and its wide applications in construction and stabilization are among the oldest technologies. Cement kiln dust is a by-product generated by cement industry with unpleasant features. Its weak integrity can be improved by mixing it with 20% of iron slag, another industrial waste generated during steel production, and a small amount of nano-additive, namely 0.1% nanosilica. This way, modified cementitious composites of improved characteristic were developed, which performed suitable for construction and waste stabilization applications. In the present study, the novel composite material has been thoroughly examined to critically assess its performance and resistance under drastic environmental conditions that are likely to occur especially in areas exposed to severe climatic variability. The impact of flooding in water of various compositions and in strongly acidic and alkaline media was investigated. Leachability of the new composite specimens in these aqueous media and when subjected towards freezing/thawing cycles was evaluated during 90 days; especially the mechanical and chemical stability of the new composite as safe containment for radioactive 137Cs waste was studied. Compressive strength, porosity, mass change and spectroscopic investigations are the tools used in this study to check the performance of the modified cementitious composite at each condition. Although prone to deterioration after drastic freezing-thawing cycles, the new composite material displayed excellent stability under excessive flooding, and holds promise as future material of choice to immobilize and finally dispose radioactive waste in a safe and sustainable fashion. [ABSTRACT FROM AUTHOR]

All the time the flow of fluids happens below the surface of the earth. These flow processes can only be imagined, but not be fully visualised on how fluid flow behaviour occurs though the porous medium of the rocks. Hence comes the play of microfluidic micromodels. These are a transparent version of slices (2 dimensional) porous structure of rocks such as sandstone duplicated onto materials such as glass, polymers and silicon wafers. Fluids such as crude oil, surfactant and polymer solutions and gases such as carbon dioxide (CO2) are injected through special pumps into these transparent micromodels. The flow patterns and behaviours hence developed inside the micromodels are studied and analysed. Micromodels have helped in different branches of science such as medicine, genetics, liquid channelling and enhanced oil recovery (EOR). The concern of this paper is to study the flow behaviour and EOR in micromodels. Micromodels can be made to represent a micro version of a partially saturated rock with crude oil. The various chemical EOR processes such as surfactant flooding, polymer flooding, gas flooding injected into crude oil filled micromodels with water saturation is studied. The advancement of front developed between displacing and displaced fluids, the fingering effect, the presence of high permeability streaks is observed. Also the breakthrough of the flood front is analysed from the various experiments reviewed. This review paper is undertaken so as to help researchers find a consolidated and concise literature of the trends and developments in microfluidics especially in EOR. [ABSTRACT FROM AUTHOR]