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Understanding the interactions of surfactants and wettability alteration of surfaces is important for many fields, including oil and gas recovery. This work utilizes the quartz crystal microbalance with dissipation to study the interaction of stabilized linear and branched alkylbenzene sulfonates (ABSs), among the most cost-efficient industrial surfactants, with water- and oil-wet calcite surfaces under high-salinity and high-temperature conditions. Confocal laser scanning microscopy is also used to study the effect of the type of ABS on their interaction with oil-wet calcite surfaces. Experiments demonstrate that vesicles made of linear and branched ABSs interact differently with both water- and oil-wet surfaces. Therefore, surfactant formulations made of ABSs for high-salinity applications can further be improved for advantageous wettability properties by varying the hydrophobic chain of the surfactants. When interacting with a water-wet surface, both types of vesicles adsorb onto the surface as is. Upon dilution, however, vesicles made of linear ABS stay adsorbed as is, and vesicles made of branched ABSs disassemble and produce a layered structure with altered wettability. Linear ABSs show greater efficiency in desorbing oil from the oil-wet calcite. The results of this study demonstrate an improved method for studying and understanding the interaction of surfactant formulations with water- and oil-wet surfaces. This approach could significantly benefit applications in which wettability alteration of surfaces is of great interest and facilitate the implementation of low-cost surfactants based on petroleum sulfonates.

The role of emulsions should be an important factor in additional oil recovery during low-salinity water flooding (LSWF); however, it has been rarely discussed in previous studies. In this study, t...

Water blockage is a type of formation damage that occurs because of capillary discontinuity at the interface between high-capillarity matrix and low-capillarity fracture. This water blockage causes a reduction in oil relative permeability and the need for higher drawdown to allow flowback after hydraulic fracturing. To remove this blockage, shut-in is believed to be effective because it dissipates the water blockage from the matrix-fracture interface deeper into the matrix through capillary imbibition. However, field data demonstrates mixed results – Some field data report shut-in as beneficial, whereas others detrimental. This paper investigates desiccation as one of the main reasons for the mixed shut-in implications. From the perspective of multiphase flow in porous media, our history-matched core-scale model reveals that shut-in can offer some benefits in desiccated water-wet cores but cause further damage in non-desiccated ones. Regardless of the desiccation, our simulation results show that immediate flowback can help ensure high oil relative permeability and remove the trapped water at the matrix-fracture interface more quickly. In a desiccated core, both immediate flowback and shut-in result in the same maximum regained oil relative permeability; however, in a non-desiccated core, immediate flowback results in a higher maximum regained oil relative permeability than shut-in.

This paper presents a mathematical model to study forced imbibition and examine the correlation between spontaneous and forced imbibition in a water-wet heterogeneous porous media. An explicit approximate analytical method with its convergence analysis is proposed here to obtain an analytic expression for the saturation profile of the wetting phase along with its case study to discuss the potential effects and reliability of the viscosity ratio, wettability state of the medium, capillary pressure and relative permeability of the phases on forced imbibition phenomenon. Finally, the simulation results investigate the impact of all parameters on the hydrocarbon reservoir’s saturation rate and recovery rate during the forced imbibition process.

In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.

Advances in the field of nanoscience and nanotechnology have resulted in the development of engineered nanoparticles, with unique physico-chemical properties, and their applications to all the sectors of industry, including the petroleum industry. This presentation will discuss several advances and applications of silica-based nanofluids in chemical enhanced oil recovery (EOR) processes related to interfacial phenomena in multiphase systems and physics of multiphase flow in porous media, and in particular the oil recovery characteristics resulting from nanofluids based low-salinity water flooding and chemical EOR processes. Laboratory experiments were carried out using homogeneous sandpack columns simulating oil-wet and water-wet reservoirs. To simulate oil-wet reservoirs, the sandpack columns were saturated with a light crude oil (West Texas Intermediate) at first. While in the case of the simulated water-wet reservoirs, these reservoirs were made by saturating the sandpack columns initially with a 1.0 wt% brine (NaCl) and then followed by an injection of the light crude oil. The subsequent oil-saturated (oil-wet system) and oil-brine mixture (water-wet system) within the sandpack columns were then subject to water flooding (non-sequenced recovery) or EOR processes (sequenced recovery) utilizing brine and/or surfactant as controls as well as low (0.01 wt%) and high (0.1 wt%) silica-based nanofluids. When compared with the high concentration of silica-based nanofluid, the low silica-based nanofluid concentration produced low fractional and cumulative oil recovery results in the water flooding process of oil recovery for both oil-wet and water-wet reservoir systems; however, the low silica-based nanofluid concentration was found to be the most effective with EOR process for both oil-wet and water-wet reservoir systems. Our findings permit to choose optimal concentrations of silica nanoparticles to be employed for either water flooding or EOR processes in order to increase the oil extraction efficiency.

Recent studies have shown that low salinity waterflood can recover additional oil from oil-wet carbonate reservoirs by altering their wettability. Further studies have investigated key mechanisms for wettability alteration, such as, interaction of sulfate ions with organic acids, importance of divalent cations, role of oil acid/base content. The progress, however, has been limited in terms of modeling the wettability alteration process. A few recent studies have reported mechanistic models based on surface-complexation reactions. However, these models have their limitations when applied to oil-wet reservoirs because the injected brine is assumed to interact with the entire rock surface. In reality, the surface reactions occurs in the water-wet regions and the water-wet regions increase as a result of wettability alteration. In this study, a multiphase multicomponent finite-difference reservoir simulator was developed, incorporating the change in oil-wet/water-wet rock fractions, for modeling low salinity waterflood in carbonates. The wettability alteration process was modeled by incorporating key surface-complexation reactions. Single-phase and oil recovery coreflood simulations were performed in which modified brines, such as seawater and diluted seawater, were injected. The simulation results show that the extent of reactions of low salinity brines is much less when these reactions are assumed to take place only in the water-wet regions of oil-wet rocks. Single-phase simulation results agreed well with sulfate delay and dolomitization reactions observed experimentally. Oil recovery simulation results showed reasonable agreement with coreflood results of low salinity water injection reported in the literature. In these simulations, the water-wet rock fraction evolved as a result of wettability alteration on injecting diluted seawater. Simulating geochemical reactions only on the water-wet regions is critical for modeling low salinity waterfloods. In this study, we developed an improved model with this feature and found it to be effective for modeling low salinity waterfloods.

The majority of enhanced oil recovery mechanisms purposefully alter the wettability of the reservoir rock from oil-wet to water-wet; to increase the amount of oil recovered from it. Wettability is the ability of a fluid to stick to a solid surface in the presence of other immiscible fluids. Wettability alteration is crucial as it affects the amount of oil recovered from a given reservoir. It was concluded that the Nano silicate and aluminum were the best Nano concentration from 1.0 to 4.0 g/L and Nano scale 28-32 nm to change the rock wettability form oil wet to water wet .By doing so these will be reflect on the amount of producing oil. So it can be increased oil productivity by wettability change from oil wet to water wet which was the target of our research.

In this work, nanosilica fluid flooding for tertiary oil recovery was investigated for Bentheimer sandstone. With use of a core flooding setup, brine imbibition was followed by nanosilica fluid flo...

Several recent studies have shown that some skeletal limestone reservoirs are far more oil-wet than the typical, water wet, biogenic, limestone reservoirs, such as chalk. It is challenging, even wi...

Wettability alteration of carbonate rocks from an oil-wet state to a water wet or mixed-wet state during water flooding is known to enhance the recovery of oil from the reservoirs. Previously, the ...

The significant reduction in heavy oil viscosity when mixed with $$\hbox {CO}_{2}$$ is well documented. However, for $$\hbox {CO}_{2}$$ injection to be an efficient method for improving heavy oil recovery, other mechanisms are required to improve the mobility ratio between the $$\hbox {CO}_{2}$$ front and the resident heavy oil. In situ generation of $$\hbox {CO}_{2}$$ -foam can improve $$\hbox {CO}_{2}$$ injection performance by (a) increasing the effective viscosity of $$\hbox {CO}_{2}$$ in the reservoir and (b) increasing the contact area between the heavy oil and injected $$\hbox {CO}_{2}$$ and hence improving $$\hbox {CO}_{2}$$ dissolution rate. However, in situ generation of stable $$\hbox {CO}_{2}$$ -foam capable of travelling from the injection well to the production well is hard to achieve. We have previously published the results of a series of foam stability experiments using alkali and in the presence of heavy crude oil (Farzaneh and Sohrabi 2015). The results showed that stability of $$\hbox {CO}_{2}$$ -foam decreased by addition of NaOH, while it increased by addition of $$\hbox {Na}_{2}\hbox {CO}_{3}$$ . However, the highest increase in $$\hbox {CO}_{2}$$ -foam stability was achieved by adding borate to the surfactant solution. Borate is a mild alkaline with an excellent pH buffering ability. The previous study was performed in a foam column in the absence of a porous medium. In this paper, we present the results of a new series of experiments carried out in a high-pressure glass micromodel to visually investigate the performance of borate–surfactant $$\hbox {CO}_{2}$$ -foam injection in an extra-heavy crude oil in a transparent porous medium. In the first part of the paper, the pore-scale interactions of $$\hbox {CO}_{2}$$ -foam and extra-heavy oil and the mechanisms of oil displacement and hence oil recovery are presented through image analysis of micromodel images. The results show that very high oil recovery was achieved by co-injection of the borate–surfactant solution with $$\hbox {CO}_{2}$$ , due to in-situ formation of stable foam. Dissolution of $$\hbox {CO}_{2}$$ in heavy oil resulted in significant reduction in its viscosity. $$\hbox {CO}_{2}$$ -foam significantly increased the contact area between the oil and $$\hbox {CO}_{2}$$ significantly and thus the efficiency of the process. The synergy effect between the borate and surfactant resulted in (1) alteration of the wettability of the porous medium towards water wet and (2) significant reduction of the oil–water IFT. As a result, a bank of oil-in-water (O/W) emulsion was formed in the porous medium and moved ahead of the $$\hbox {CO}_{2}$$ -foam front. The in-situ generated O/W emulsion has a much lower viscosity than the original oil and plays a major role in the observed additional oil recovery in the range of performed experiments. Borate also made $$\hbox {CO}_{2}$$ -foam more stable by changing the system to non-spreading oil and reducing coalescence of the foam bubbles. The results of these visual experiments suggest that borate can be a useful additive for improving heavy oil recovery in the range of the performed tests, by increasing $$\hbox {CO}_{2}$$ -foam stability and producing O/W emulsions.

Sewage sludge is a significant by-product from wastewater treatment plants but is potentially hazardous due to its pathogenic or harmful contents, such as toxic metals. Subcritical water wet oxidation (SCWO) is one method of hydrothermal processing which has recently been used in research and industry for treating sludge. This study investigated the effect of SCWO on metals such as Al, Cu, Fe, and Zn in sludge, including the content of metals in the liquid or solid phase after SCWO and their stability distributions according to Tessier’s method. During SCWO, most metals were significantly accumulated and stabilised in the solid phase with very limited leaching. The temperature was found to be the most significant factor for metals immobilisation, followed by reaction time, while pH had negligible effect. The optimal conditions of SCWO on metals were found at 240 °C, 60 min, pH 5 in this study.

With the aid of CT scanning and image processing techniques, water displacing oil experiments were performed to analyze six natural water-wet sandstone cores of different permeability and porosity visually and quantitatively. Microscopic remaining oil was categorized on the basis of quantitative characterization parameters, such as shape factor, contact ratio, Euler number etc. The remaining oil characteristics with different flow types were presented in different water displacement stages. Experimental results show that the remaining oil can be divided into five categories. They are, respectively membranous flow, droplet flow, columnar flow, multi-porous flow and clustered flow from hard-to-produce to easy-to-produce. The relative permeability of oil phase is represented by the macro-average relative permeability of all the above five flow regimes. Among them, clustered flow possesses strong producing capacity and high relative permeability, and the other four flow regimes have weaker producing capacity and lower relative permeability. Variation of number and average volume of five types remaining oil and several measurements of the ganglion size distribution have been performed in the literature. The nonlinear knee point on the relative permeability ratio curve is intrinsically caused by the decreasing of volume and quantity fraction of clustered flow when water saturation increases. This paper has studied the flowing law of microscopic remaining oil, explained the intrinsic mechanism for the appearance of an inflection point on the relative permeability ratio curve and microscopic sweep phenomena, and also presented a new effective way of upscaling to a certain extent.

In this study, synthesized SiO2/ZnO hybrid nanoparticles were used to change the wettability of carbonate rock from highly oil-wet to strongly water-wet state. The SiO2/ZnO nanoparticles were synthesized by modified sol-gel method. In this method, TEOS was used to increase the functional groups on the surface of the ZnO nanoparticles to produce highly hydrophilic nanoparticles. The contact angle measurements were conducted on the rock surface before and after nano-treatment. The contact angle of oil droplet with the rock changed from 0° to 150°, 161°, 164° and 170° after impregnation the rock with 0.01, 0.033, 0.07 and 0.33 wt.% nanofluids.

Isolated fractures usually exist in fractured media systems, where the capillary pressure in the fracture is lower than that of the matrix, causing the discrepancy in oil recoveries between fractured and non-fractured porous media. Experiments, analytical solutions and conventional simulation methods based on the continuum model approach are incompetent or insufficient in describing media containing isolated fractures. In this paper, the simulation of the counter-current imbibition in fractured media is based on the discrete-fracture model (DFM). The interlocking or arrangement of matrix and fracture system within the model resembles the traditional discrete fracture network model and the hybrid-mixed-finite-element method is employed to solve the associated equations. The Behbahani experimental data validates our simulation solution for consistency. The simulation results of the fractured media show that the isolated-fractures affect the imbibition in the matrix block. Moreover, the isolated fracture parameters such as fracture length and fracture location influence the trend of the recovery curves. Thus, the counter-current imbibition behavior of media with isolated fractures can be predicted using this method based on the discrete-fracture model.

Visualization of NAPLs in multiphase systems in porous media is important for determining contaminant transport in the environment. In this study, magnetic resonance imaging (MRI) was used to confirm the recent observations of mobilisation of a light non aqueous phase liquid (LNAPL) trapped in wet sand under natural drying conditions of the wet porous medium. Visualization of LNAPL (motor oil) and water mobility during the drying of wet glass beads (0.5 mm) in a cylindrical glass column (15 mm ID, 45 mm long) was obtained using spin echo-based NMR microimaging performed at 500 MHz, corresponding to a field of ca. 11.75 T. Sagittal and axial images of LNAPL and water in the porous medium were obtained at a spatial resolution of 59 μm/pixel at different time intervals. A rise of 15–20 mm was observed in the presence of evaporation of water as compared to a 2–3 mm rise in the absence of evaporation in a time span of about 1400 min. The spatio-temporal MRI scans of the water and LNAPL in the glass column reveals that LNAPL rise occurs when the water evaporation front reaches the LNAPL layer. This implied that the enhanced LNAPL rise was strongly linked to the process of water evaporation. A linear correlation of the MRI signal intensities of LNAPL and water with reference to different saturation levels of LNAPL and water in the porous media was obtained. This calibration information was used to quantify the saturation levels of the LNAPL and water during the drying process. These findings show the application of non-invasive techniques such as MRI in quantifying and understanding the mechanism of fate and transport of LNAPLs in porous media, towards effective environmental quality assessment.

Two-phase immiscible drainage experiments are performed on strongly water-wet sandstone sample to assess and illustrate capillary end effects at different rates on relative permeability. All the experiments were done under unsteady state conditions with oil displacing brine in fully brine saturated cores. First, relative permeability curves are calculated using the Johnson–Bossler–Naumann (JBN) method (Johnson et al. 1959). Then, modified JBN model is defined to account for capillary pressure. Lastly, numerical simulator is used to generate relative permeability curves based on history matching. Results of the experiments show that as the rate increases (higher capillary number), the water relative permeability increases while the irreducible water saturation decreases. With high rate, less water saturation is being accumulated at the outlet hence less irreducible water and higher relative permeability. Moreover, the oil relative permeability curves are getting higher with higher rates confirming CEE impact on the tests. The calculated irreducible water saturation based on the core weights re-affirms the JBN calculation and decreases with higher rates. This paper proves capillary end effects on relative permeability curves at low rates which have low capillary numbers on water-wet sandstone cores.

A Water-alternating-gas (WAG) injection is a broadly practised technique in oil fields. Gas viscosity is a significant parameter that can affect the efficiency of gas and WAG injections. By conducting the current coreflood experiments at reservoir conditions, we aimed to investigate the effect of gas viscosity on gas and WAG injection performance in terms of oil recovery and differential pressure. Both WAG injection experiments were performed on the same Clashach sandstone core, under weakly water-wet and near miscible (gas/oil IFT = 0.04 mN.m-1) conditions, using two different hydrocarbon systems (C1-nC4 and C1-nC10). To eliminate the impact of the experimental artifact, a long and large core (2ft x 2 in) was employed. In addition, after each initial water injection, water was pumped through the core at multi-rates, for further investigation of the impact of capillary end effects on our experimental results. To facilitate the interpretation of the data and the comparison, the same injection strategy and methodology were followed in both coreflood experiments. In each injection scenario, four water slugs, starting with primary water flooding, were injected in an alternating manner with four gas cycles. The results of these WAG experiments showed that the cyclic oil recovery performance during different water and gas injection cycles increased as the number of WAG slugs increased. Investigating the effect of gas viscosity on the performance of oil recovery during gas and WAG injections revealed higher oil recovery performance during the tertiary (three-phase displacement) water injection cycles that were subsequent to the preliminary water flood periods, in WAG injection with C1-nC4 than that in C1-nC10. In contrast, the efficiency of oil recovery during the successive gas injection cycles (under three-phase conditions) was lower in C1-nC4 than that in C1-nC10. The ultimate oil recovery achieved by WAG injection under weakly water-wet and near miscible conditions reached 93 % and 94.5 % (IOIP %) in C1-nC4 and C1-nC10 respectively. On the other hand, the results showed also an extra oil quantity of 3.7 % (Sor%) recovered during the alternation of water and gas injections post-waterflood, by C1-nC10 compared with that in C1-nC4. Studying the impact of the gas viscosity on the injectivity showed a significant drop in the periodic gas injectivity, during different gas injection cycles in WAG injection for C1-nC10 compared with its values for C1-nC4. A comprehensive series of data sets, generated for two WAG injection experiments with different hydrocarbon fluids (C1-nC4 and C1-nC10) will be reported in this paper. WAG injection is a special case that involves complex multi-phase and multi-physics processes, which are well-known to be difficult to reliably predict by the current existing reservoir simulators. Therefore, representative and reliable experimental data are needed to improve our understanding of the complex underlying mechanisms of oil recovery by WAG injection and to develop improved models and methodologies for reliable predictions of the performance of WAG injection under reservoir conditions.

Low salinity waterflooding (LSW) is a promising enhanced oil recovery process. The LSW advantage has been associated to changes in rock wettability toward a more water wet state. This study evaluated the effect of different flooding schemes on the performance of LSW in terms of production rate and incremental oil recovery from sand-pack systems. This work also investigated the main mechanism prompting sand wettability changes during LSW. Flooding Scheme-1 consisted of high salinity waterflooding, low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-2 consisted of low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-3 consisted of alkali aided low salinity flooding and low salinity waterflooding. The main mechanism causing wettability reversal was verified employing contact angle analysis, inductively coupled plasma spectrometry, and scanning electron microscopy. This new study reveals in a straightforward manner the effect of low salinity waterflooding schemes on both production rate and incremental oil recovery. LSW in secondary mode, as conducted in FS-2, expedited the oil production rate by 15% and increased the overall oil recovery by 20% relative to flooding schemes FS-1 and FS-3. Furthermore, this study determined that multi-component ionic exchange was the dominant mechanism for the reversal of sand wettability to a more water wet state. This paper provides new insights for heavy oil producers on the relevance of the flooding schemes during LSW and on the dominant mechanism for wettability alteration during the recovery of heavy oil from unconsolidated sands.

Counter-current imbibition is a process whereby a wetting phase spontaneously imbibes into a porous media, displacing the non-wetting phase. This process is considered an important oil recovery mechanism during water flooding in fractured oil reservoirs. In this study, the dynamic process of counter-current imbibition for a natural reservoir sandstone core with an all-face-open boundary condition was monitored using magnetic resonance imaging (MRI). A series of images and relaxation time T1 spectra were acquired. The movement of water spontaneously entering the core sample while oil escapes, the spatial distribution of oil and water, and the in situ saturation change of oil and water in porous media can be accurately detected using MRI. MRI assists the direct evaluation of the basic mechanisms of imbibitions. Experimental results suggest the remaining oil was trapped in some large pores because of the capillary pressure, and the oil recovery in some large-pore regions is lower than that in some small-pore regions at the end of imbibition. Experimental findings show a close agreement between conventional material balance and oil recovery determined from MRI. The in situ oil recovery data agree well with the empirical models. The observations from MRI images could provide test cases to enable the development of mathematical models and to facilitate the evaluation of the proposed imbibition mechanisms. Copyright © 2016 John Wiley & Sons, Ltd.

We perform co-current spontaneous imbibition ambient-condition experiments in three carbonates with a wide range of permeability under strongly water-wet conditions. We measure water saturation profiles as a function of distance and time in air-filled rocks with no initial water saturation using X-ray CT scanning. We demonstrate that the saturation profiles are functions of distance divided by the square root of time. We also demonstrate that the profiles are consistent with analytical solutions for imbibition in one dimension, and using reasonable estimates of relative permeability and capillary pressure, we can match the experimental results. We discuss how, in combination with conventional measurements of relative permeability (steady-state or using Buckley–Leverett theory in an unsteady-state experiment), the capillary pressure can be determined, or how the relative permeability can be determined from the spontaneous imbibition experiment and the capillary pressure.

Shale gas wells with high production rates usually have large amounts of hydraulic liquid retention, which can cause aqueous phase trapping (APT). However, the APT can be auto-relieved after a well shut-in for a certain period. To clarify its mechanism, the experiments of shale permeability during liquid imbibition and diffusion were conducted. Then, theoretical analysis was interpreted. Samples include the Longmaxi Formation (LMX Fm) from Sichuan province and the Niutitang Formations (NTT Fm) from Sichuan and Guizhou provinces. Permeability during imbibition in Sichuan LMX Fm has decreasing and increasing stages. Increase in permeability is caused by new cracks induced by clay-swelling. Only the decreasing stage of permeability occurs during imbibition in NTT Fm, tight sand, and tight volcanic rock because imbibed liquid reduces the gas-flow channel. The relative permeability of gas recovers during liquid diffusion among all samples. The permeability recovers quickly initially, which is caused by liquid migrating from large pores and cracks into small pores. The large pores and cracks have more contribution to permeability than the small pores. Subsequently, permeability nearly keeps constant because liquid migrates among the small pores, which have less influence on permeability. Sichuan LMX Fm has induced cracks, and its gas relative permeability can exceed 1 after liquid diffusion. In theoretical analysis, four types of gas-flow channels are considered, namely, organic pores, inorganic pores, organic cracks, and inorganic cracks. Initial cracks are mainly water wet. Induced cracks include both organic cracks and inorganic cracks. The ratio between inorganic induced cracks and total induced cracks influences permeability. The lower the ratio is, the more evident the permeability increase is during imbibition. The denser the cracks are, the higher the permeability recovery is during liquid diffusion. Overall, the induced cracks can contribute to the relief of APT in shale gas reservoirs.

In this paper, we consider a time-fractional porous medium equation in the imbibition phenomenon in a water-wet porous medium. The Homotopy analysis method, along with its stability analysis via fixed point theory, is used to solve the fractional-order porous medium equation and to study the behavior of different fractional orders on the saturation rate of the medium with the consideration of some parametric effects.

Flowback after hydraulic fracturing shows a poor recovery of the fracturing fluid. The unrecovered fluid is believed to invade the matrix and creates a formation damage called water blockage, which affects the optimum oil production from the reservoir. Surfactant is often added into the fracturing fluid, because it can improve the recovery of the fracturing fluid, and hence minimum water blockage. This objective is achieved by the surfactant's interfacial tension (IFT) reduction and wettability alteration capabilities. This study investigates the optimum surfactant criteria, in terms of the IFT and wettability, to minimize the water blockage. From the perspective of regained oil relative permeability, our history-matched core-scale model reveals that the optimum criteria depend on the matrix capillarity. In conventional reservoirs, the optimum criteria are to select surfactants which offer ultralow IFT (even as low as 0.001 mN/m) and maintain the water-wetness of the rock. However, in tight reservoirs, the optimum criteria are surfactants which strongly alter the rock wettability to oil-wet, while the IFT requirement is more flexible (i.e., from 15 down to 0.001 mN/m). The contradicting optimum criteria can be explained by the relative dominance between relative permeability and capillary pressure. This study emphasizes that the optimum surfactant criteria for conventional reservoirs are not necessarily the same as those for tight reservoirs.

One of the major problems arising in the Oil Industry is those associated with oil extraction. The ideal conditions on the rock surface should be water wet conditions, to facilitate the easy extraction of oil. Contact angle measurements are key to determine surface tension between solids and various fluids. If the rock wettability is oil wet, the oil company may need to change the rock wettability. We will determine wettability (water wet or oil wet), analyze how the effect of different brine concentrations on wettability and contact angle measurements using the Dynamic Contact Angle Analyzer (DCA 315).

The main focus of the paper is to introduce a new approach at studying and modelling the relationship of initial water saturation profile and capillarity in water-wet hydrocarbon reservoirs, and describe the available measurement methods and possible applications. As a side track it aims to highlight a set of derivable parameters of mercury capillary curves using the Thomeer-method. Since the widely used mercury capillary pressure curves themselves can lead to over-, or underestimations regarding in-place and technical volumes and misinterpreted reservoir behaviour, the need for a proper capillary curve is reasonable. Combining the results of mercury and centrifuge capillary curves could yield a capillary curve preserving the strengths of both methods, while overcoming their weaknesses. Mercury injection capillary curves were normalized by using the irreducible water saturations derived from centrifuge capillary pressure measurements of the same core plug, and this new, combined capillary curve was applied for engineering calculations in order to make comparisons with other approaches. The most significant benefit of this approach is, that all of the measured data needed for a valid drainage capillary pressure curve represents the very same sample piece.

Structural trapping, the most important CO2 geostorage mechanism during the first decades of a sequestration project, hinges on the traditional assumption that the caprock is strongly water wet. However, this assumption has not yet been verified; and it is indeed not generally true as we demonstrate here. Instead, caprock can be weakly water wet or intermediate wet at typical storage conditions; and water wettability decreases with increasing pressure or temperature. Consequently, a lower storage capacity can be inferred for structural trapping in such cases.

The recent literature identified that certain types of smooth floors and flooring materials showed good slip-resistance performance under moderately contaminated situations such as water wet and soapsuds-covered conditions. However, topographic structures of such flat floor/walkway surfaces are significantly changed by wear and tear developments with continuous ambulation. A number of reasons seem to be involved in flooring wear developments, but such changes may result in substantial losses of slip resistance (or traction) functions. Even though the importance of this issue is wide, it is scarce to find any systematic investigations on tribophysical characteristics of smooth floors (µm in Ra roughness) and their wear impacts on traction performance. Moreover, it is difficult to find studies on wear progress of floors and its impacts on pedestrian fall safety assessments. This study focuses on exploring wear activities of smooth resilient floors and disclosing wear consequences on traction properties. To measure slip-resistance features and investigate wear advances of smooth resilient floors, dynamic friction tests were carried out amongst purposely arranged 4 flat specimens (polymethyl methacrylate: PMMA) and 3 shoes. Wear formations and progressions of the PMMA surfaces were methodically evaluated by observing surface profiles during the tests. The test outcomes evidently presented that initial surface features of the PMMA specimens were significantly modified by primary-, secondary-, and shared-wear mechanisms and significantly influenced traction performance. This study may have design applications for the safety enhancements of smooth floors/footpaths to preclude pedestrian fall incidents.

Summary A laboratory study on microsphere injection in a large volume (1 pore volume) was conducted to explore its oil recovery capacity as a flooding agent. This work aims to a Middle-East reservoir with oil-wet high-permeable carbonate in nature. An etched micromodel was made based on the pore network of natural core plugs and the pore network treated to oil-wet with silicon oil. Water flooding was conducted to displace oil at reservoir temperature (95°C), followed by 1 pore volume microsphere injection. A significant oil recovery was obtained using a microsphere concentration ranged from 0.5% to 5%. As a comparison, microsphere was injected into a water-wet micromodel to recover oil after water flooding, which also shows very positive results. This work proved the concept that microsphere injection can enhance the oil recovery in both oil-wet and water-wet reservoirs, once the treatment is conducted with sufficient amount and over the threshold microsphere concentration.

Summary The potential reservoirs in the Realgrunnen play in the Southwestern Barents Sea are heavily influenced by the complex burial history of the area. A combination of present day shallow reservoirs and formerly buried over 2 km deeper causes challenges when doing a geophysical reservoir characterization. Wells drilled in the area display amplitude anomalies, but majority has been water wet when drilled. By creating rock physics models and combining with AVO parameters Intercept and Gradient running an inverse modelling scheme (IRPM) in the AVO domain we try to link amplitude anomalies in the AVO domain with wireline log results to provide a quantitative seismic interpretation methodology for de-risking exploration in shallow areas of complex tectonic events.

The presence of polymer molecules in an altered wettability core and its possible interactions with the solid phase is the subject of this study. Experiments were carried out in Bentheimer sandstone which wettability is altered by an ageing process. The wettability index after ageing (WI = 0.075) shows an intermediate wettability. After ageing we carried out spontaneous imbibition tests by putting in contact the core with brine or polymer solution (HPAM, C = 2500ppm) or in a sequence (first with brine and then with the polymer solution) For each experiment we measure the volume of oil recovered by spontaneous imbibition, this oil volume gives us an evaluation of the core wettability, the higher the recovered oil volume, the more water wet is the core. The experimental data show that final oil production by spontaneous imbibition is higher when the core was kept for a long time in contact with polymer solution rather than with brine. Moreover if the core is put in contact with polymer after having been immerged in brine, we notice a significant increment of produced oil. All these results confirm that the polymer has an interaction with the solid phase and makes the core more water wet.

The water composition can affect the wettability of oil reservoir sandstone rocks. If several injection water compositions are available, the composition with highest oil recovery potential should be selected. Alteration of wettability to more water-wet conditions has the potential to accelerate the oil production and thereby reduce the water production. The main objective for the presented work was to develop a method for fast screening of the potential for available injection water compositions to alter wettability to more water-wet.The wettability of reservoir rock samples was characterized by using a flotation method which relies on the affinity of minerals to either the brine or crude oil phase. Crushed reservoir rock samples were aged at reservoir temperature using brine and crude oil of different compositions, and the amounts of oil-wet particles in the oil-phase were determined. The experimental results were compared with geochemical simulation of rock-brine interactions.In the flotation study, the potential for the injection water compositions to alter the wettability to more water-wet was shown to depend on the crude oil compositions. By geochemical simulations including both ion-exchange and solubility of carbonate minerals, the amounts of divalent cations onto clay surfaces (M2+) were found to vary with the brine composition. Some of the possible injection water compositions were found to reduce M2+ and thereby reduce the potential for cation-bridging. The main trend was decreasing concentration of oil-wet particles (more water-wet conditions) in flotation experiments with decreasing M2+ estimated by simulations. The dominating wetting mechanism for the studied rock-brine-oil systems appeared to be cation-bridging.The study has shown that screening of the potential for available injection water compositions to alter the wettability to more water-wet can be carried out by combining flotation experiments and geochemical simulations. This screening is much less time consuming than standard experiments, and only small amounts of rock samples are required. The potential for the most promising injection water compositions can then be further evaluated by core flooding experiments.

Recent experiments show the strong water uptake of gas shales which are strongly oil-wet based on contact angle measurements.1,2 Clay hydration, microfracture induction, lamination, and osmotic effect are collectively responsible for the excess water uptake. However, the previous measurements are not sufficient to isolate the above factors nor to explain why the bulk of shale samples can hardly imbibe the oil which completely spreads on their surface. To answer the remaining questions, we measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar shales. In contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil-wet. This argument is backed by complete spreading of oil on fresh surfaces of the rock. In contrast to the artificial pores of crushed rock, the existing pore...

Background: Composite resins have hydrophobic properties so it cannot attach to dentine. Moist dentin is a normal condition caused by the presence of fluid in dentinal tubules. Therefore bonding material is required to bond dentine with composite. Water-wet technique is a technique in which dentine surface is rinsed after etching by using water and allowing it to be moist and prevent the collapse of dentine collagen fibrils. This technique is commonly used today, but excess water disturbs the effectiveness of dentine and bonding material attachment. Ethanol-wet technique is a technique in which ethanol is used to replace water before bonding to reduce excess water in dentine surface. This technique will initiate monomer penetration into interfibrillar space of dentine. It will affect the result of tensile strength test. Purpose: The purpose of this study was to compare tensile strength of bonding material to dentine using water-wet and ethanol-wet techniques. Method: 12 samples of bovine incisors teeth were randomly divided into 2 group. Each group consists of six samples. Group 1 was treated with water-wet technique and group 2 was treated with ethanol-wet technique. Autograph was used as a tensile strength test instrument. Result : The average of tensile strength using water-wet technique was 2,16067 MPa and ethanol-wet technique was 4,21900 MPa. Conclusion: E thanol-wet technique have higher value of tensile strength than water-wet technique.

Widespread stress on global water supplies compels the need for low-cost and sustainable desalination processes. In this regard, desalination through membrane distillation (MD) can harness waste-grade heat or renewable energy. So far, the membranes for MD have been exclusively derived from intrinsically water-repellant materials - mostly perfluorocarbons. However, perfluorocarbons are limiting in terms of operational conditions, and they also introduce economic and environmental concerns. The development of perfluorocarbon-free MD membranes would likely address those challenges. Here, we report on the proof-of-concept for biomimetic gas-entrapping membranes (GEMs) for MD derived from silica and poly(methyl methacrylate) (PMMA) that are water-wet materials. We drew inspiration for our GEM design from the cuticles of springtails and hairs of Halobates germanus, both of which exhibit mushroom-shaped (or reentrant) features. Accordingly, our GEMs comprise arrays of microscale cylindrical pores with reentrant inlets and outlets that can robustly entrap air on submersion in water. Our PMMA-GEMs yielded a vapor flux of J ≈ 1 L-m−2-h−1 while separating a solution of ∼0.6 M NaCl at 333 K from deionized water at 288 K under a cross-flow configuration. To our knowledge, this is the first-ever demonstration of MD membranes derived from intrinsically water-wet materials, and these findings suggest that the rational design of membranes towards greener and cheaper desalination processes is possible.

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

Residual trapping of CO2 has been identified as a reliable and rapid way to dispose large CO2 quantities. Several experimental investigations have been completed where residual trapping in sandstone was measured; these programmes identified that initial CO2 saturation and rock porosity are significant parameters which influence the residual saturation and thereby residual trapping capacity and effectiveness. In order to further improve fundamental understanding a computational tool need to be developed with which residual CO2 saturations can be predicted. Pore-scale two-phase fluid flow simulation is performed based on the integration of x-ray micro-tomography images (which provide a detailed description of the rock's pore space) and Navier-Stokes equations. X-ray micro-tomography (approximately (6µm)3 voxel size) images of F42 sand pack were used. The extracted pore morphology of each medium was obtained by segmenting the images based on their greyscale contrast using image processing software AVIZO Fire. These binary images were converted initially into surface and volume meshes which were then fed into a commercially available computational fluid dynamics code (ANSYS-CFX). Three dimensional transient, laminar flow fields were obtained by solving the continuity and Navier-Stokes equations using an Eulerian-Eulerian multi-phase flow approach. To incorporate the effect of capillary forces, free surface model was used which solved the pressure gradient at the interface correctly. The model assumes isothermal condition with no mass transfer between the brine and CO2. The inlet and outlet boundary conditions include CO2 flow rate and the pressure respectively. We simulated the drainage condition in this paper. Approximately 1.5 million tetrahedral elements were used to generate volume mesh, and the convergence criterion for all variables was set to 10-3. Initially all pore space was filled with brine, and then CO2 was injected from one inlet side at constant flow rate, obtained from the experiments. When the system was at connate water saturation, we stopped our simulation. The residual saturation depends on the flow rate of super critical CO2. The computations described here are a rapid, cost-effective and can reveal vital information for the planning of carbon geo-sequestration projects and associated risk and capacity assessments.

The petroleum industry have been working for decades on various solutions to increase recovery. When petroleum companies abandon an oil well, more than half the reservoir's oil is usually left behind as difficult to recover. Recent investigations have developed a new method is based on adding particles that are considerably smaller than the tunnel diameters. Nanotechnology provides the capability to enhance energy efficiency across all branches of industry and economically renewable energy production through new solutions and optimized technologies. Nanoparticles defined as EOR potential agents for detailed control of benefits such as wettability alternation, interfacial reduction of oil and water and viscosity reduction. This study provides new idea of CuO nanoparticles effects on wettability alteration through spontaneous imbibition, reducing the viscosity and extracting heavy oil involving steam assisted gravity drainage (SAGD) by experimental work. In the first step of this research, the potential of CuO nanoparticles to imbibe and alter the wettability are determined experimentally and numerically. Laboratory tests were conducted in two experiments on two cylindrical core samples taken from Iranian heavy oil reservoir. In the first experiment, core samples were saturated by crude oil and in the second one, nanoparticles were flooded, and then saturated by crude oil, immersed in distilled water and the amount of recovery was monitored during 30 days for all tests. Experimental results show oil recovery for sandstone cores change from 20.74 % of OOIP without nanoparticles to 31.77% of OOIP with CuO nanoparticles, respectively. The oil recovery for carbonate core vary from zero without nanoparticles to 6.92% of OOIP with CuO nanoparticles, respectively. By investigation of relative permeability curve, the crossover-point is shifted to the right by adding CuO nanoparticles which means nanoparticles succeeds in altering the wettability to more water- wet for sandstone and even carbonate cores. In the second step, the effect of vertical spacing between two horizontal wells on oil recovery and the ability of low CuO nanoparticles concentration to reduce viscosity are clarified in SAGD process. Laboratory tests were conducted in three experiments through the use of 2 dimensional scaled SAGD cell from an Iranian heavy oil reservoir. In the first and second experiments, the SAGD cell were saturated by heavy oil and in the third one, the cell was flooded by CuO nanoparticles before oil saturation. The amount of recoveries were monitored during 12h. The experimental results explore that by adding nanoparticles, the ultimate oil recovery increases from 52.43 to 80.027%. Viscosity reduction, increasing oil recovery, decreasing residual oil saturation (SOR) and water cut (WCUT%) are the main purposes of this investigation.

Spontaneous imbibition is of special importance in oil recovery from fractured reservoirs. Laboratory measurements of volume of liquid imbibed versus time are often used in the prediction of oil recovery. Laboratory results of oil recovery through spontaneous imbibition are commonly scaled-up to forecast oil recovery at the reservoir scale. Numerous questions arise with respect to the theory of spontaneous imbibition and the valid scaling of laboratory imbibition data. The factors involved in the scaling equation are rock properties, liquids viscosities, interfacial tensions, core geometry and wettability. Some previous developments in scaling were based on oil recovery from very strongly water-wet rocks. In this paper, sequential developments in the mathematical analysis of scaling equations for imbibition recovery are reviewed to the latest one. Previous scaling equations do not fit the imbibition data with different wettabilities in cores. To show this fact, two series of experiments are done on water wet and oil wet cores. Oil wet cores are obtained by means of aging process. The effect of interfacial tension is considered using a new type of surfactant. Imbibition data is compared with different scaling equations that are available in the literature for providing a physical explanation of the new index. The results reveal the inconsistency between scaling equations. Previous methods did not consider the effects of all parameters on determining the Wettability Index. A new procedure is introduced in order to obtain the Normalization Index from the imbibition data using all the parameters affecting the imbibition rate, including wettability. This index, which could be considered as a substitute for the Wettability Index, is then used to modify previous scaling equations and called the Normalization Index. The improved correlation is shown to perform better than the existing equations available in the literature as it gives the closest fit to the experimental data.

1,3-Dibromo-5,5-diphenylimidazolidine-2,4-dione (N,N’-dibromo phenytoin) was efficiently used for the rapid conversion of thiobenzamides to the corresponding 3,5-diaryl-1,2,4-thiadiazoles in water–wet paste conditions. Supplemental materials are available for this article. Go to the publisher's online edition of Synthetic Communications® to view the free supplemental file.

Through unconfined compressive strength tests and triaxial compression tests made by sea water wet fly ash, fly ash solidified by cement, and the analysis with water wet strength of the material solidified fly ash formation mechanism, getting their basic mechanical properties and index. The results showed that curing water wet fly ash cement has good stability and durability, mixing curing mixture strength with age of stable growth, increased strength by adding cement content. The pilot research on the retaining structure, embankment reinforcement and ground improvement has important engineering applications such as theory and practice of value.