Oil-wet Cores Research Articles

Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks

Of recent, there has been research and development in the technologies/techniques required to meet the ever-growing energy demand in the world. Oil is a major source of energy which is contained in over 50% of carbonate reservoirs. The oil/mixed wettability of carbonate rocks makes it technically challenging to recover the needed oil. The process of crude oil recovery has three different stages primary, secondary and tertiary recovery. Tertiary recovery is also known as enhanced oil recovery or EOR. EOR includes the use of surfactants to reduce the interfacial tension between a hydrocarbon and brine, thus suspending them both in a microemulsion. Surfactant performance can be affected by multiple variables, including brine salinity, surfactant concentration, and type of hydrocarbon. A petroleum engineer must take all variables into consideration when selecting a surfactant to make sure that its efficiency is as high as possible, especially because the use of surfactants is costly.
 In this work, a chembetaine zwitter ionic surfactant of two different concentrations are evaluated at various synthetic formation brine salinities for their favourable wettability alteration and interfacial tension reduction in oil-wet carbonate- Silurian Dolomite. For the evaluation, fluid-fluid and rock-fluid analysis are carried out to select the optimal surfactant concentration and brine salinity with the greatest improved oil recovery potential.
 Results are indicative that the surfactant at the two concentrations studied is compatible at the ranges of salinities evaluated. However, from the fluid-fluid analysis, there was no ultra-low interfacial tension that is needed for oil mobilization. More so, the rock-fluid analysis shows that the surfactant is not able to alter the wettability of oil-wet rocks favourably. The optimal surfactant slug for the greatest oil recovery, in this case, would be expected at 0.5% surfactant concentration in 10,000 ppm synthetic formation brine salinity. This study, therefore, serves as a guide for the design of optimal surfactant slug in oil-wet carbonate cores requires to reduce non-productive time, prevent reservoir damage and therefore improve recovery.

Ultralow-Interfacial-Tension Foam-Injection Strategy in High-Temperature Ultrahigh-Salinity Fractured Oil-Wet Carbonate Reservoirs

Summary Oil recovery in many carbonate reservoirs is challenging because of unfavorable conditions, such as oil–wet surface wettability, high reservoir heterogeneity, and high brine salinity. We present the feasibility and injection–strategy investigation of ultralow–interfacial–tension (IFT) foam in a high–temperature (greater than 80°C), ultrahigh–formation–salinity [greater than 23% total dissolved solids (TDS)] fractured oil–wet carbonate reservoir. Because a salinity gradient is generated between injection seawater (SW) (4.2% TDS) and formation brine (FB) (23% TDS), a frontal–dilution map was created to simulate frontal–displacement processes and thereafter it was used to optimize surfactant formulations. IFT measurements and bulk–foam tests were also conducted to study the salinity–gradient effect on the performance of ultralow–IFT foam. Ultralow–IFT foam–injection strategies were investigated through a series of coreflood experiments in both homogeneous and fractured oil–wet core systems with initial oil/brine two–phase saturation. The representative fractured system included a well–defined fracture by splitting the core sample lengthwise. A controllable initial oil/brine saturation in the matrix can be achieved by closing the fracture with a rubber sheet at high confining pressure. The surfactant formulation achieved ultralow IFT (magnitude of 10−2 to 10−3 mN/m) with the crude oil at the displacement front and good foamability at underoptimal conditions. Both ultralow–IFT and foamability properties were found to be sensitive to the salinity gradient. Ultralow–IFT foam flooding achieved more than 50% incremental oil recovery compared with waterflooding in fractured oil–wet systems because of the selective diversion of ultralow–IFT foam. This effect resulted in a crossflow near the foam front, with surfactant solution (or weak foam) primarily diverted from the fracture into the matrix before the foam front, and oil/high–salinity brine flowing back to the fracture ahead of the front. The crossflow of oil/high–salinity brine from the matrix to the fracture was found to create challenges for foam propagation in the fractured system by forming Winsor II conditions near the foam front and hence killing the existing foam. It is important to note that Winsor II conditions should be avoided in the ultralow–IFT foam process to ensure good foam propagation and high oil–recovery efficiency. Results in this work contributed to demonstrating the technical feasibility of ultralow–IFT foam in high–temperature, ultrahigh–salinity fractured oil–wet carbonate reservoirs and investigated the injection strategy to enhance the low–IFT foam performance. The ultralow–IFT formulation helped to mobilize the residual oil for better displacement efficiency and reduce the unfavorable capillary entry pressure for better sweep efficiency. The selective diversion of foam makes it a good candidate for a mobility–control agent in a fractured system for better sweep efficiency.

Exploring Low-IFT Foam EOR in Fractured Carbonates: Success and Particular Challenges of Sub-10-md Limestone

SummaryThe high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-md formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.The low-IFT foam process was investigated through coreflood experiments in homogeneous and fractured oil-wet cores with sub-10-md matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer [alpha olefin sulfonate (AOS) C14-16] were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the coreflood experiments.Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-md matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-md matrix permeability achieved 64% incremental oil recovery compared to waterflooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, the foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluid flow in the matrix. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of the low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids—such as mineral dissolution and the exchange of calcium and magnesium—were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It, therefore, may cause injectivity and phase-trapping issues especially in the homogeneous limestone.Results in this work demonstrated that despite the challenges associated with limestone dissolution, the low-IFT foam process can remarkably extend chemical enhanced oil recovery (EOR) in fractured oil-wet tight reservoirs with matrix permeability as low as 5 md.

Laboratory study heterogeneity impact on microscopic residual oil distribution in tight sandstone cores during CO2 immiscible flooding

ABSTRACTWe use physical simulation experiment and nuclear magnetic resonance methods to investigate crude oil distribution after immiscible CO2 flooding schemes in tight sandstone cores. Experimental results indicate that water-wet cores lead to the highest final recovery factor in comparison with intermediate wet cores and weak oil-wet cores, and the recovery oil difference in clay micropore is mainly because of the heterogeneity, and the difference in medium pore and large pore is affected by asphaltene precipitation phenomenon. Therefore, it is important to enhance the recovery in the clay micropores and reduce the impact of cores permeability reduction caused by asphaltene precipitation. Based on this investigation on the residual oil saturation in pore throats, immiscible CO2 flooding can be a potential method to improve recovery efficiency in tight oil reservoir.

Effect of Network Parameters of Preformed Particle Gel on Structural Strength for Water Management

Summary Preformed particle gel (PPG) is an appropriate solution for conformance control and water management in low permeability reservoirs. In this paper, the network parameters of PPGs are evaluated through swelling tests and rheology and by determining their role in maintaining structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and chromium triacetate [Cr(OAc)3] as copolymer and crosslinker, respectively, using a central composite design. The characterization of these hydrogels was performed using a scanning electron microscope (SEM), electron dispersion X-ray (EDX), and environmental scanning electron microscope (ESEM). The correlation between reaction conditions and the network parameters of polymer networks, such as the molecular weight of the polymer chain between two neighboring crosslinks (Mc¯), the crosslink density, and the size fraction, have been determined. In addition, swelling of the hydrogels took place through the Fickian diffusion mechanism. Structural states of Laponite dispersions strongly depend on concentration and ionic strength. Based on the rheological tests, the dynamic modulus of the PPG was strongly dependent on the initial concentration and resulting network parameters of the hydrogel. The results showed an effective interaction between Mc¯ and the elastic modulus of the gel network. Through the optimization of the network parameters, the appropriate composition was presented on the basis of the factors of strength (complex modulus of 4×104 Pa in the plateau region), the formation of a 3D network, and the preservation of the viscoelastic structure in the presence of Na+, Ca2+, and Mg2+, at a salt sensitivity of 0.5. In addition, the optimum sample structure was confirmed on the basis of microscopic images. Based on the coreflooding data, the optimal PPG showed a disproportionate permeability reduction (DPR) index of 17.01 and indicated the dual performance of these materials against water and oil. Also, the permeability diagrams of the core showed wettability of the oil-wet core could shift to more water-wet after PPG injection. To summarize this research, we present the determination and analyses of the network parameters as a novel technique for predicting the performance of hydrogels in porous media, and for investigating their strength under harsh reservoir conditions. In other words, determination of the network parameters can be used to ensure the success of the gel performance in porous media.

Laboratory research of wettability and heterogeneity effect on microscopic residual oil distribution in tight sandstone cores during CO2 flooding

Based on physical simulation experiment and nuclear magnetic resonance (NMR) measurements, the effect of wettability and pore throat heterogeneity upon oil recovery efficiency during CO2 flooding, were conducted to investigate how crude oil residing in different sized pore are produced by immiscible CO2 flooding schemes in tight sandstone cores. Experimental results indicate that water wet cores lead to the highest final recovery factor in comparison with intermediate wet cores and weak oil wet cores. The recovery factor difference in clay micro pore is mainly because of the heterogeneity, while the difference in medium pore and large pore is affected by asphaltene precipitation phenomenon. Therefore, it is important to enhance the recovery in the clay micro pores, and focus on the cores permeability reduction caused by asphaltene precipitation. Based on this investigation on the residual oil saturation in pore throats subjected to immiscible CO2 flooding, it is possible to design an optimum flood scheme which suits for the microscope pore throat characteristics for a given tight oil reservoir.

Investigations on spontaneous imbibition and the influencing factors in tight oil reservoirs

Spontaneous imbibition has become a role on the development of tight oil reservoirs. Many oilfield cases have confirmed the validity of soaking to produce oil depending on imbibition. Considerable yield has been recovered from soaking for a period of time after hydraulic fracturing by fracturing fluid. In order to study the spontaneous imbibition and its influencing factors in tight oil reservoir with stimulated reservoir volume (SRV), we first conducted wettability and imbibition experiments with/without surfactant treatment using different tight cores. Then, we established a mechanism model of imbibition including the influencing factors in tight oil reservoirs based on the experiments. The model was also validated using the published results. After that, numerical simulation was employed to study the impacts of some essential factors on the effects of spontaneous imbibition. The results indicate that no matter mixed-wet or water-wet tight cores, water can be spontaneously imbibed into the tight cores, and consequently expel the oil. The wettability alteration agent has slight influence on contact angle and imbibition recovery for the water-wet core, but it has a distinct influence on those of the mixed-wet or oil-wet core. Natural fractures in tight rock can promote the imbibition. The size of the tight rock after hydraulic fracturing is a significant factor of imbibition recovery. Interfacial tension is crucial to imbibition in tight reservoir because capillary force becomes more significant in tight rocks than that in conventional reservoirs. Wettability intensely decides the imbibition recovery, and it is indispensable to add modifying agents to enhance imbibition for mix-wet or oil-wet rocks. The reduction of temperature in tight oil reservoir due to fracturing and huff-n-puff may decrease the recovery by more than 1% after 5–6 cycles.

The Relationship Equation Between the Properties of Imbibition Agent and Imbibition Efficiency

Based on a large number of physics simulation experiment data, mathematics relationship problems of the correlation of imbibition efficiency influence factors have been solved, and the correlation equation have been established. Field ML and field YT was chosen to represent the extra-low permeability field, Field JY and field QX was chosen to represent the ultra-low permeability field. The impact trend of imbibition efficiency with interfacial tension, emulsion stability, penetration force and viscosity has been found. A result has been found through the R factor analysis by common factor variance and coefficient of variation method, the impact order on imbibition efficiency of oil-wet core or oil sand is interfacial tension, emulsion stability, viscosity ratio and penetration force ratio. The four factors and three factors structural equation models have been established, and passed the model test. The impact of cross term is considered. This study has great significance in analyzing the factors affecting the imbibition efficiency.

A new experimental method for measuring the three-phase relative permeability of oil, gas, and water

For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.

Effect of the rock dimension on surfactant imbibition rate in the Middle Member of Bakken: Creating a model for frac design

As an unconventional energy resource, the Bakken Formation has long been considered an important source rock for oil in the Williston Basin. The naturally fractured Bakken Formation consists of thin shale and silty carbonate sequences, capable of producing oil at economic rates when completed using hydraulically fractured horizontal wells. However, because of its low permeability and oil-wet characters, the primary recovery values are still low.As part of our effort to assess the potential for imbibition to recover oil from tight rocks, we performed spontaneous imbibition experiments using brine and surfactant for different dimensions of cores from the Middle Member of the Bakken Formation in North Dakota. The effect of length of the core on imbibition rate in the cores was measured for brine and surfactants. The purpose of this study is to create a model which can be basis for development of design of hydraulic fracturing of the formation. These cores from Bakken were silt stone, limestone, and shale interlayers in lithology. To the point of scaling the dimension of the core from laboratory to a field application, the large area of fluid contact will promote higher imbibition rate and faster oil recovery from the rock.Although oil recovery was low during brine imbibition into the oil-wet cores, alkali/surfactant solution recovered approximately 30–45% of the oil based on the laboratory results. We found higher oil recovery factor was achieved from surfactant imbibition more than just used brine. As would be expected, a given level oil recovery was reached faster in shorter cores than in longer cores in same diameters. The shorter core has a larger ratio of surface area to volume. A model which describes the relationship between Peak Oil recovery and surface areas for cores was derived.

Investigation effect of wettability and heterogeneity in water flooding and on microscopic residual oil distribution in tight sandstone cores with NMR technique

Abstract In order to explore the effect of wettability and pore throat heterogeneity on oil recovery efficiency in porous media, physical simulation experiment and nuclear magnetic resonance (NMR) measurements were conducted to investigate how crude oil residing in different sized pores are recovered by water flooding. Experimental results indicate that the recovery factor of water flooding is governed by spontaneous imbibition and also pore throat heterogeneity. It is found that intermediate wetting cores lead to the highest final recovery factor in comparison with water wet cores and weak oil wet cores, and the recovery oil difference in clay micro pore is mainly because of the wettability, the difference in medium pore and large pore is affected by pore throat heterogeneity. Water wet core has a lower recovery factor in medium and large pore due to its poor heterogeneity, in spite of the spontaneous imbibition effect is very satisfying. Intermediate wetting cores has significant result in different sized pore and throat, the difference in medium pore and large pore is affected by pore throat heterogeneity.

Evaluation of combined low-salinity water and microgel treatments to improve oil recovery using partial fractured carbonate models

Combining two methods in one process to enhance oil recovery represents a needed cost savings in the oil industry. Microgels are used as conformance control agents to improve oil sweep efficiency and control excess water production. Low-salinity waterflooding (LSWF) is used as a wettability alteration agent in carbonate reservoirs and improves displacement efficiency. This paper offers a comprehensive understanding of the combined technology through laboratory experiments. The focus of this study is to see how microgels and low water salinity perform in porous media by creating flow resistance to injected fluid thereby changing the wettability and enhancing the sweep and displacement efficiency. This study elucidates the influence of swelling ratio, fracture width, microgel-placed pressure, and wettability on the oil recovery factor and water residual resistance factor (Frrw). A set of carbonate cores from Indiana Limestone was used to evaluate the performance of the combined method in partially open fractures. The model was constructed of two acrylic plates, and microgels and brine movements were visible through a transparent side of the model. Result shows that oil recovery factor increases with swelling ratio and microgel placed pressure but decreases with the increase of fracture width. It was shown that oil recovery improved by 10% when the swelling ratio increased from 40% to 160% and improved by 9% when fracture width decreased from 0.8 cm to 0.2 cm. Also, the combined method shows larger effect in the oil-wet core when compared to the water-wet core. Frrw increases with the increase in swelling ratio and microgel-placed pressure but decreases with the increase of fracture width.

Unstable Immiscible Displacements in Oil-Wet Rocks

Displacement of a viscous fluid by a lower viscosity immiscible fluid (such as waterflood of a viscous oil) in a porous medium is unstable. The displacement front generates viscous fingers which lead to low oil recovery efficiency. These fingers are much smaller in width than typical reservoir simulation grid blocks, and capturing their effect in reservoir simulation is important. A dimensionless scaling group (viscous finger number) had been suggested in the past, which has a power-law relationship with the breakthrough recovery and cumulative recovery in unstable core floods. The relative permeability used in large grid block simulations had been modified to so-called pseudo-relative permeability on the basis of the dimensionless group, thus incorporating the effect of fingers in waterflood predictions. However, the previous proposed models were constructed from experiments in only water-wet rocks. This paper extends the recent viscous fingering models to oil-wet systems. Sandstone cores were treated to alter the wettability to oil-wet. Adverse viscosity water floods were performed in oil-wet cores. Viscosity ratio, velocity and diameter were varied. It is shown that the previously developed viscous finger number does not work for the oil-wet experiments. The correlating dimensionless number is modified for oil-wet systems; it is also different from the dimensionless group identified by Peters and Flock (Soc Petroleum Eng, 1981. doi: 10.2118/8371-PA ) for oil-wet cores. A pseudo-relative permeability model has been developed for oil-wet cores. Corefloods have been matched by the new pseudo-relative permeability model to determine the model parameters. This pseudo-relative permeability model can be used in reservoir simulations of water and polymer floods in viscous oil-wet reservoirs.

Polymer Flooding Enhanced Oil Recovery Evaluated with Magnetic Resonance Imaging and Relaxation Time Measurements

Magnetic resonance imaging (MRI) and magnetic resonance (MR) T2 lifetime measurements were employed to monitor oil displacement by waterflooding and polymer flooding in two different rock core plugs. In situ oil saturation profiles were determined from the MRI measurements. Water-wet and oil-wet core plugs saturated with crude oil and mineral oil showed different oil saturation profile changes and T2 relaxation time variations during core flooding. The T2 log mean ratio is proposed to normalize T2 trends from different rock/fluid samples. The polymer stripping mechanism in the oil-wet rock core plugs was consistent with in situ oil saturation profile changes and relaxation time trends observed during oil displacement.

Disproportionate Permeability Reduction of Water-Soluble Silicate Gelants: Importance of Formation Wettability

SummaryDisproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in noncommunicating layered reservoirs. This work evaluates the laboratory-scale DPR effectiveness at different formation-wettability conditions by use of an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature-stable and easy-to-design water-soluble silicate-gelant system is used to conduct DPR treatments in oil- and water-wet cores by use of a newly established steady-state, two-phase chemical-system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement-saturation conditions in the formation. DPR treatments are conducted by use of a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments is evaluated by use of pretreatment and post-treatment two-phase (brine/oil) steady-state and unsteady-state permeability measurements.Strongly water-wet Berea cores are chemically treated to alter their wettability to oil-wet, and measured-phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high water cuts in water-wet cores, two-phase DPR fluid/oil injectivity is good and even better in oil-wet cores regardless of the water cut. At relatively low water cuts in water-wet cores, the injectivity is not as good as in higher water cuts, and the mobility reduction keeps increasing with the coinjection of the DPR fluid/oil.DPR fluid/oil-placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil-residual-resistance factor (RRF) in oil-wet cores is significantly lower than that in water-wet cores. This is mainly because of more-favorable oil-phase continuity and distribution in oil-wet media compared with the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous-medium-conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped-oil saturation compared with the water-wet formation.In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment-imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel “erosion” during the post-treatment two- and single-phase (water) injection; gel “erosion” ceased during oil injection. DPR treatments conducted at high WOR caused an increase in RRF of both water and oil phases regardless of the core's wetting conditions; the DPR effectiveness was more pronounced in oil-wet cores than in water-wet ones.

Interactions between Formation Rock and Petroleum Fluids during Microemulsion Flooding and Alteration of Heavy Oil Recovery Performance

In situ emulsification/solubilization is an oil recovery technique routinely used to mobilize residual oil after the secondary oil production (waterflooding). The oil is produced after a subsequent reduction of interfacial tension between stranded crude oil and water in the reservoir. Herein, a recovery method is presented for heavy crude oils whose scheme consists of injection of a fully solubilized (or emulsified) oil. Theoretically, the fully solubilized oil, referred hereinafter as microemulsion formulation, reduces the viscous forces that keep residual oil stranded. Different microemulsion formulations were prepared ex situ from two heavy oils (API 11.5 and 16.6), micellar slugs (formulated from cationic Gemini surfactant), and low-saline water (0.1 wt % NaCl). Tertiary heavy oil recovery consisted of displacing residual oil from a waterflooded core by a specific microemulsion formulation followed by low-saline water, which acted as buffer solution. Thirty-one percent of initial oil-in-place (IOIP) was recovered from the waterflooded core by microemulsion followed by an incremental oil recovery of about 20% of IOIP with chase water. The oil recovery efficiency by microemulsion and chase water floodings was lowered to 15 and 28%, respectively, in a strong oil-wet core (i.e., non waterflooded core). Despite the promising results presented herein, the performance of the microemulsion formulations and thus the oil recovery efficiency were found to be strongly dependent on (1) the nature of the core, i.e., its mineralogy, (2) the wetting state of plug, and (3) the chemical composition advancing fluid. The microemulsion formulations prompted a series of chemical reactions which subsequently altered their performance as a displacing agent. Ion tracking analysis of the effluent fractions showed that the pH and concentration in divalent and/or monovalent ions were also altered at each stage of production. When the plug was not waterflooded, the oil was produced along with a deposit of sludge and a high emulsion cut. However, the use of preflush enriched with an alkali (Na2CO3) was found to abate both effects. Furthermore, the spectral analysis of effluent fractions revealed the formation of calcium bridges which are thought to alter the efficiency of microemulsion formulations. Also, a series of chemical schemes are proposed in this investigation to support these results. Lastly, this investigation proposes a simplified electrostatic model that explains further the formation of clusters which were promoted by propagation of displacing fluids.

Polymer flow through water- and oil-wet porous media

The effect of wettability on polymer behavior in porous media is investigated through a series of synthetic polymer floods conducted in water- and oil-wet Bentheim and Berea sandstone cores. A new experimental setup is used in which the core effluent polymer concentrations are not measured during polymer flooding, but instead are passed through a capillary tube that is connected to the core outlet. Using the notion of intrinsic viscosity, an approximate expression is presented that can be used to determine the breakthrough time of the injected polymer solution. In addition, polymer adsorption, inaccessible pore volume, and apparent viscosities are evaluated for all cores and wetting conditions. In general, in the presence of residual oil, the oil-wet cores display the lowest degree of polymer retention (Berea) and the lowest inaccessible pore volume-IPV (Bentheim). The largest wettability impact on the polymer behavior in porous media appears to be for the Berea formation; polymer retention in oil-wet cores decreases 90% and IPV 52% compared to the corresponding amounts for the water-wet ones. On the other hand, the estimated polymer retention and IPV values appear to be similar for the oil- and water-wet Bentheim cores, this is attributed to questionable wettability alteration.

The Wettability Alteration and the Effect of Initial Rock Wettability on Oil Recovery in Surfactant-based Enhanced Oil Recovery Processes

Wettablity alteration of rock surface is an important mechanism for surfactant-based enhanced oil recovery (EOR) processes. Two salt and temperature-tolerant surfactant formulations were developed based on the conditions of high temperature (97–120°C) and high salinity (20 × 104 mg/L) reservoirs where a surfactant-based EOR process is attempted. Both the two sufactant formulations can achieve ultralow interfacial tension level (≤10−3 mN/m) with crude oil after aging for 125 days at reservoir conditions. Wettability alteration of core slices induced by the two surfactant formulations was evalutated by measuring contact angles. Core flooding experiments were carried out to study the influence of initial rock wettabilities on oil recovery in the crude oil/surfactant/formation water/rock system. The results indicated that the two formulations could turn oil-wet core slices into water-wet at 90–120°C and 20 × 104 mg/L salinity, while the water-wet core slices retained their hydrophilic nature. The core flooding experiments showed that the water-wet cores could yield higher oil recovery compared with the oil-wet cores in water flooding, surfactant, and subsequent water flooding process. The two surfactant formulations could successfully yield additional oil recovery in both oil-wet and water-wet cores.

Analysis on Capillary Pressure Curves by Wettability Modification through Surfactants

Wettability of a reservoir rock is closely related to capillary pressure curves. The status of wettability is an important factor for oil recovery, can be clearly seen through the variations in capillary pressure curves. The aim is to analyze the changes in capillary pressure curves and saturations by altering wettability. An oil wet core sample was tested to alter wettability. During alteration process it is difficult to analyze the status of wettability. Surfactants were applied to modify wettability. Additionally, parameters like connate water saturation, spontaneous oil and water saturations, residual oil saturation and type of wettability can be analyzed. The concentration of surfactants was selected by conductivity test. The changes in saturations with variations in capillary pressure curves were stated.

Experimental investigation of SiO2 nanoparticles on enhanced oil recovery of carbonate reservoirs

Wettability alteration is an important method to increase oil recovery from oil-wet carbonate reservoirs. Chemical agents are used as wettability modifiers in carbonate systems; however, the role of Nanoparticles in this field is still in its infancy and consequently has attracted the attention of many researchers in the last decade. In this work, the impact of SiO2 Nanoparticles on the wettability of a carbonate reservoir rock was experimentally studied. The impact of these Nanoparticles on the wettability of carbonate systems is still in its infancy. For this purpose, the effect of Nanofluid’s concentration on wettability and interfacial tension were investigated to determine the optimum concentration of Nanofluid for injection into core samples. The result suggests that a concentration of 4 g/L of Nanofluid could significantly alter the wettability of the rock from a strongly oil-wet to a strongly water-wet condition. Moreover, we studied the Nanofluids’ potential in enhanced oil recovery of oil-wet core plugs. The results show that a considerable amount of oil can be recovered right after start of water injection to the aged core plug with Nano fluid.