Chemical Compositions in Salinity Waterflooding of Carbonate Reservoirs: Theory

Higher oil recovery after waterflood in carbonate reservoirs is attributed to increasing water wettability of the rock that in turn relies on complicated surface chemistry. In addition, calcite mineral reacts with aqueous solutions and can alter substantially the composition of injected water by mineral dissolution. Carefully designed chemical and/or brine flood compositions in the laboratory may not remain intact while the injected solutions pass through the reactive reservoir rock. This is especially true for a low-salinity waterflood process, where some finely tuned brine compositions can improve flood performances, whereas others cannot. We present a 1D reactive transport numerical model that captures the changes in injected compositions during water flow through porous carbonate rock. We include highly coupled bulk aqueous and surface carbonate-reaction chemistry, detailed reaction and mass transfer kinetics, 2:1 calcium ion exchange, and axial dispersion. At typical calcite reaction rates, local equilibrium is established immediately upon injection. In SI, we validate the reactive transport model against analytic solutions for rock dissolution, ion exchange, and longitudinal dispersion, each considered separately. Accordingly, using an open-source algorithm (Charlton and Parkhurst in Comput Geosci 37(10):1653–1663, 2011. https://doi.org/10.1016/j.cageo.2011.02.005), we outline a design tool to specify chemical/brine flooding formulations that correct for composition alteration by the carbonate rock. Subsequent works compare proposed theory against experiments on core plugs of Indiana limestone and give examples of how injected salinity compositions deviate from those designed in the laboratory for water-wettability improvement.

     

Wettability Alteration to Intermediate Gas-Wetting in Porous Media at Elevated Temperatures

Wettability alteration to intermediate gas-wetting in porous media by treatment with FC-759, a fluorochemical polymer has been studied experimentally. Berea sandstone was used as the main rock sample in our work, and its wettability before and after chemical treatment was studied at various temperatures from 25 to 93°C. We also studied recovery performance for both gas/oil and oil/water systems for Berea sandstone before and after wettability alteration by chemical treatment. Our experiment shows that chemical treatment with FC-759 can result in: (1) wettability alteration from strong liquid-wetting to stable intermediate gas-wetting at room temperature and at elevated temperatures; (2) neutral wetting for gas, oil, and water phases in two-phase flow; (3) significant increase in oil mobility for gas/oil system; and (4) improved recovery behavior for both gas/oil and oil/water systems. This work reveals a potential for field application for improved gas-well deliverability and well injectivity by altering the rock wettability around wellbore in gas condensate reservoirs from strong liquid-wetting to intermediate gas-wetting.     

Effect of Organosilicon-Acrylic Emulsion Treatment on Wettability of Porous Media

To investigate the influence of the organosilicon-acrylic on wetting properties of porous media, contact angle tests were performed on two different sandstones. In addition, the effectiveness of the emulsion on wettability alteration of porous media was validated by capillary rise and spontaneous imbibition tests. The results of wettability tests showed that the wettability of two sandstones was altered from water-wet to gas-wet after treatment with the emulsion. The principle that the critical radius of pore throats and wettability of porous media affect liquids flow was derived analytically and verified experimentally. Coreflood results demonstrated that the latex resulted in increasing the water permeability through altering the rock wettability to gas-wetting, then decreasing the friction drag between liquids and rocks surface. Thereby, the emulsion treatment could increase the flowback rate of trapped liquids. Experimental results were in good agreement with the theoretical analysis. In conclusion, all results indicated that the emulsion could alter the wettability from water-wet to intermediate gas-wet and enhance water permeability in porous media. It was extrapolated that the emulsion had the tremendous potential to be applied in field conditions, enhancing gas productivity through the cleanup of trapped water in the vicinity of the wellbore.     

Pore-Scale Network Modeling of Three-Phase Flow Based on Thermodynamically Consistent Threshold Capillary Pressures. I. Cusp Formation and Collapse

We present a pore-scale network model of two- and three-phase flow in disordered porous media. The model reads three-dimensional pore networks representing the pore space in different porous materials. It simulates wide range of two- and three-phase pore-scale displacements in porous media with mixed-wet wettability. The networks are composed of pores and throats with circular and angular cross sections. The model allows the presence of multiple phases in each angular pore. It uses Helmholtz free energy balance and Mayer–Stowe–Princen (MSP) method to compute threshold capillary pressures for two- and three-phase displacements (fluid configuration changes) based on pore wettability, pore geometry, interfacial tension, and initial pore fluid occupancy. In particular, it generates thermodynamically consistent threshold capillary pressures for wetting and spreading fluid layers resulting from different displacement events. Threshold capillary pressure equations are presented for various possible fluid configuration changes. By solving the equations for the most favorable displacements, we show how threshold capillary pressures and final fluid configurations may vary with wettability, shape factor, and the maximum capillary pressure reached during preceding displacement processes. A new cusp pore fluid configuration is introduced to handle the connectivity of the intermediate wetting phase at low saturations and to improve model’s predictive capabilities. Based on energy balance and geometric equations, we show that, for instance, a gas-to-oil piston-like displacement in an angular pore can result in a pore fluid configuration with no oil, with oil layers, or with oil cusps. Oil layers can then collapse to form cusps. Cusps can shrink and disappear leaving no oil behind. Different displacement mechanisms for layer and cusp formation and collapse based on the MSP analysis are implemented in the model. We introduce four different layer collapse rules. A selected collapse rule may generate different corner configuration depending on fluid occupancies of the neighboring elements and capillary pressures. A new methodology based on the MSP method is introduced to handle newly created gas/water interfaces that eliminates inconsistencies in relation between capillary pressures and pore fluid occupancies. Minimization of Helmholtz free energy for each relevant displacement enables the model to accurately determine the most favorable displacement, and hence, improve its predictive capabilities for relative permeabilities, capillary pressures, and residual saturations. The results indicate that absence of oil cusps and the previously used geometric criterion for the collapse of oil layers could yield lower residual oil saturations than the experimentally measured values in two- and three-phase systems.     

Analysis of capillary interaction and oil recovery under ultrasonic waves

Although, the effects of ultrasonic irradiation on multiphase flow through porous media have been studied in the past few decades, the physics of the acoustic interaction between fluid and rock is not yet well understood. Various mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to Bjerknes forces, oscillation and excitation of capillary trapped oil drops, forces generated by cavitating bubbles, and sonocapillary effects. Insight into the physical principles governing the mobilization of oil by ultrasonic waves is vital for developing and implementing novel techniques of oil extraction. This paper aims at identifying and analyzing the influence of high-frequency, high-intensity ultrasonic radiation on capillary imbibition. Laboratory experiments were performed using cylindrical Berea sandstone and Indiana limestone samples with all sides (quasi-co-current imbibition), and only one side (counter-current imbibition) contacting with the aqueous phase. The oil saturated cores were placed in an ultrasonic bath, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time. Air–water, mineral oil–brine, mineral oil–surfactant solution and mineral oil-polymer solution experiments were run each exploring a separate physical process governing acoustic stimulation. Water–air imbibition tests isolate the effect of ultrasound on wettability, capillarity and density, while oil–brine imbibition experiments help outline the ultrasonic effect on viscosity and interfacial interaction between oil, rock and aqueous phase. We find that ultrasonic irradiation enhances capillary imbibition recovery of oil for various fluid pairs, and that such process is dependent on the interfacial tension and density of the fluids. Although more evidence is needed, some runs hint that wettability was not altered substantially under ultrasound. Preliminary analysis of the imbibition recoveries also suggests that ultrasound enhances surfactant solubility and reduce surfactant adsorption onto the rock matrix. Additionally, counter-current experiments involving kerosene and brine in epoxy coated Berea sandstone showed a dramatic decline in recovery. Therefore, the effectiveness of any ultrasonic application may strongly depend on the nature of interaction type, i.e., co- or counter-current flow. A modified form of an exponential model was employed to fit the recovery curves in an attempt to quantify the factors causing the incremental recovery by ultrasonic waves for different fluid pairs and rock types.     

A Pore-Scale Investigation of Low-Salinity Waterflooding in Porous Media: Uniformly Wetted Systems

The potential of low-salinity (LS) water injection as an oil recovery technique has been the source of much recent debate within the petroleum industry. Evidence from both laboratory and field-level studies has indicated significant benefits compared to conventional high-salinity (HS) waterflooding, but many conflicting results have also been reported and, to date, the underlying mechanisms remain poorly understood. In this paper, we aim to address this uncertainty by developing a novel, steady-state pore network model in which LS brine displaces oil from a HS-bearing network. The model allows systematic investigation of the crude oil/brine/rock parameter space, with the goal of identifying features that may be critical to the production of incremental oil following LS brine injection. By coupling the displacement model to a salinity-tracking tracer algorithm, and assuming that a reduction of water salinity within the pore network leads to localised wettability alteration, substantial perturbations to standard pore filling sequences are predicted. The results clearly point to two principal effects of dynamic contact angle modification at the pore scale: a “pore sequence” effect, characterised by an alteration to the distribution of displaced pore sizes, and a “sweep efficiency” effect, demonstrated by a change in the overall fraction of pores invaded. Our study indicates that any LS effect will depend on the relative (scenario-dependent) influence of each mechanism, where factors such as the initial wettability state of the system and the pore size distribution of the underlying network are found to play crucial roles. In addition, we highlight the important role played by end-point capillary pressure in determining LS efficacy.     

Flow behaviour in the presence of wettability heterogeneities

The physical processes occurring during fluid flow and displacement within porous media having wettability heterogeneities have been investigated in specially designed heterogeneous visual models. The models were packed with glass beads, areas of which were treated with a water repellent to create wettability variations. Immiscible displacement experiments show visually the effect of wettability heterogeneities on the formation of residual oil and recovery due to capillary trapping. This work demonstrates by experiment the importance of incorporating reservoir heterogeneity into pore displacement analysis, essential for the correct interpretation of core data and for directing the route for scale-up of the processes to reservoir scale.     

Pore-Scale Monitoring of Wettability Alteration by Silica Nanoparticles During Polymer Flooding to Heavy Oil in a Five-Spot Glass Micromodel

It is well known that the oil recovery is affected by wettability of porous medium; however, the role of nanoparticles on wettability alteration of medium surfaces has remained a topic of debate in the literature. Furthermore, there is a little information of the way dispersed silica nanoparticles affect the oil recovery efficiency during polymer flooding, especially, when heavy oil is used. In this study, a series of injection experiments were performed in a five-spot glass micromodel after saturation with the heavy oil. Polyacrylamide solution and dispersed silica nanoparticles in polyacrylamide (DSNP) solution were used as injected fluids. The oil recovery as well as fluid distribution in the pores and throats was measured with analysis of continuously provided pictures during the experiments. Sessile drop method was used for measuring the contact angles of the glass surface at different states of wettability after coating by heavy oil, distilled water, dispersed silica nanoparticles in water (DSNW), polyacrylamide solution, and DSNP solution. The results showed that the silica nanoparticles caused enhanced oil recovery during polymer flooding by a factor of 10%. The distribution of DSNP solution during flooding tests in pores and throats showed strong water-wetting of the medium after flooding with this solution. The results of sessile drop experiments showed that coating with heavy oil, could make an oil-wet surface. Coating with distilled water and polymer solution could partially alter the wettability of surface to water-wet and coating with DSNW and DSNP could make a strongly water-wet surface.     

Study of Microscopic and Macroscopic Displacement Behaviors of Polymer Solution in Water-Wet and Oil-Wet Media

Performance of a polymer flood process requires the knowledge of rheological behavior of the polymer solution and reservoir properties such as rock wettability. To provide a better understanding of effects of polymer chemistry and wettability on the performance of a polymer flood process, a comprehensive experimental study was conducted using a two-dimensional glass micromodel. A series of water and polymer flood processes were carried out at different polymer molecular weights, degrees of polymer hydrolysis, and polymer concentrations in both water-wet and oil-wet systems. Image processing technique was applied to analyze and compare microscopic and macroscopic displacement behaviors of polymer solution in each experiment. From micro-scale observations, the configuration of connate water film, polymer solution trapping, flow of continuous and discontinuous strings of polymer solution, piston-type displacement of oil, snap-off of polymer solution, distorted flow of polymer solution, emulsion formation, and microscopic pore-to-pore sweep of oil phase were observed and analyzed in the strongly oil-wet and water-wet media. Rheological experiments showed that a higher polymer molecular weight, degree of hydrolysis, and concentration result in a higher apparent viscosity for polymer solution and lower oil–polymer viscosity ratio. It is also shown that these parameters have different impacts on the oil recovery in different wettabilities. Moreover, a water-wet medium generally had higher recovery in contrast with an oil-wet medium. This experimental study illustrates the successful application of glass micromodel techniques for studying enhanced oil recovery (EOR) processes in five-spot pattern and provides a useful reference for understanding the displacement behaviors in a typical polymer flood process.     

Displacement mechanisms of enhanced heavy oil recovery by alkaline flooding in a micromodel

Enhanced oil recovery (EOR) by alkaline flooding for conventional oils has been extensively studied. For heavy oils, investigations are very limited due to the unfavorable mobility ratio between the water and oil phases. In this study, the displacement mechanisms of alkaline flooding for heavy oil EOR are investigated by conducting flood tests in a micromodel. Two different displacement mechanisms are observed for enhancing heavy oil recovery. One is in situ water-in-oil (W/O) emulsion formation and partial wettability alteration. The W/O emulsion formed during the injection of alkaline solution plugs high permeability water channels, and pore walls are altered to become partially oil-wetted, leading to an improvement in sweep efficiency and high tertiary oil recovery. The other mechanism is the formation of an oil-in-water (O/W) emulsion. Heavy oil is dispersed into the water phase by injecting an alkaline solution containing a very dilute surfactant. The oil is then entrained in the water phase and flows out of the model with the water phase.     

Pore-Scale Imaging and Analysis of Wettability Order,Trapping and Displacement in Three-Phase Flow in Porous Media with Various Wettabilities

Three-phase flow in porous media is encountered in many applications including subsurface carbon dioxide storage, enhanced oil recovery, groundwater remediation and the design of microfluidic devices. However, the pore-scale physics that controls three-phase flow under capillary dominated conditions is still not fully understood. Recent advances in three-dimensional pore-scale imaging have provided new insights into three-phase flow. Based on these findings, this paper describes the key pore-scale processes that control flow and trapping in a three-phase system, namely wettability order, spreading and wetting layers, and double/multiple displacement events. We show that in a porous medium containing water, oil and gas, the behaviour is controlled by wettability, which can either be water-wet, weakly oil-wet or strongly oil-wet, and by gas–oil miscibility. We provide evidence that, for the same wettability state, the three-phase pore-scale events are different under near-miscible conditions—where the gas–oil interfacial tension is ≤?1 mN/m—compared to immiscible conditions. In a water-wet system, at immiscible conditions, water is the most-wetting phase residing in the corners of the pore space, gas is the most non-wetting phase occupying the centres, while oil is the intermediate-wet phase spreading in layers sandwiched between water and gas. This fluid configuration allows for double capillary trapping, which can result in more gas trapping than for two-phase flow. At near-miscible conditions, oil and gas appear to become neutrally wetting to each other, preventing oil from spreading in layers; instead, gas and oil compete to occupy the centre of the larger pores, while water remains connected in wetting layers in the corners. This allows for the rapid production of oil since it is no longer confined to movement in thin layers. In a weakly oil-wet system, at immiscible conditions, the wettability order is oil–water–gas, from most to least wetting, promoting capillary trapping of gas in the pore centres by oil and water during water-alternating-gas injection. This wettability order is altered under near-miscible conditions as gas becomes the intermediate-wet phase, spreading in layers between water in the centres and oil in the corners. This fluid configuration allows for a high oil recovery factor while restricting gas flow in the reservoir. Moreover, we show evidence of the predicted, but hitherto not reported, wettability order in strongly oil-wet systems at immiscible conditions, oil–gas–water, from most to least wetting. At these conditions, gas progresses through the pore space in disconnected clusters by double and multiple displacements; therefore, the injection of large amounts of water to disconnect the gas phase is unnecessary. We place the analysis in a practical context by discussing implications for carbon dioxide storage combined with enhanced oil recovery before suggesting topics for future work.

     

Wetting Phase Bridges Establish Capillary Continuity Across Open Fractures and Increase Oil Recovery in Mixed-Wet Fractured Chalk

The effect of fractures on oil recovery and in situ saturation development in fractured chalk has been determined at near neutral wettability conditions. Fluid saturation development was monitored both in the matrix and in the fractures and the mechanisms of fracture crossing were determined using high spatial resolution MRI. Capillary continuity across open oil-filled fractures was verified by imaging the water bridges established within the fracture. Despite an alternate escape fracture for the water, separate water bridges were shown to be stable for the entire duration of the experiments. The established capillary contact resulted in oil recovery exceeding the spontaneous imbibition potential in the outlet-isolated cores by ca. 10% PV. This is explained by viscous recovery provided by water bridges across open fractures. The size of the bridges seemed to be controlled by the wettability of the rock and not by the differential pressure applied across the open fracture.     

Oil Recovery by Low Salinity Water Injection into a Reservoir: A New Study of Tertiary Oil Recovery Mechanism

Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones saturated with asphaltic crude oil. Reported data showed that low salinity water injection could provide up to 20% pore volume (PV) of additional oil recovery for core samples and up to 25% PV for reservoirs in near wellbore regions, compared with brine injection at the same Darcy velocity. The question remains as to whether this additional recovery is also attainable in reservoirs. The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation. However, many later reports showed that a higher oil recovery associated with low salinity water injection at the common laboratory flow velocity was neither necessarily accompanied by migration of clay particles, nor necessarily accompanied by emulsion. Moreover, increased water-wetness has been shown to cause the reduction of oil recovery. The present study is based on both experimental and theoretical analyses. Our study reveals that the increased oil recovery is only related to the reduction of water permeability due to physical plugging of the porous network by swelling clay aggregates or migrating clay particles and crystals. At a fixed apparent flow velocity, the value of negative pressure gradient along the flow path increases as the water permeability decreases. Some oil drops and blobs can be mobilized under the increased negative pressure gradient and contribute to the additional oil recovery. Based on the revealed mechanism, we conclude that low salinity water injection cannot be superior to brine injection in any clay-bearing sandstone reservoir at the maximum permitted injection pressure. Through our study of low salinity water injection, the theory of tertiary oil recovery has been notably improved.     

Long-term Petrophysical Investigations on Geothermal Reservoir Rocks at Simulated In Situ Conditions

In the course of stimulation and fluid production, the chemical fluid–rock equilibrium of a geothermal reservoir may become disturbed by either temperature changes and/or an alteration of the fluid chemistry. Consequently, dissolution and precipitation reactions might be induced that result in permeability damage. In connection with the field investigations at a deep geothermal doublet, complementary laboratory-based research is performed to address these effects. The reservoir is located at a depth of 4100 to 4200 m near Groß Schönebeck within the Northeast German Basin, 50 km north of Berlin, Germany. Within the reservoir horizon, an effective pressure of approximately 45 MPa and a temperature of 150°C are encountered. Furthermore, the Lower Permian (Rotliegend) reservoir rock is saturated with a highly saline Ca–Na–Cl type formation fluid (TDS ≈ 255 g/l). Under these conditions we performed two sets of long-term flow-through experiments. The pore fluid used during the first and the second experiment was a 0.1 molar NaCl-solution and a synthetic Ca–Na–Cl type fluid with the specifications as above, respectively. The maximum run duration was 186 days. In detail, we experimentally addressed: (1) the effect of long-term flow on rock permeability in connection with possible changes in fluid chemistry and saturation; (2) the occurrence and consequences of baryte precipitation; and (3) potential precipitations related to oxygen-rich well water invasion during water-frac stimulation. In all substudies petrophysical experiments related to the evolution of rock permeability and electrical conductivity were complemented with microstructural investigations and a chemical fluid analysis. We also report the technical challenges encountered when corrosive fluids are used in long-term in situ petrophysical experiments. After it was assured that experimental artifacts can be excluded, it is demonstrated that the sample permeability remained approximately constant within margins of  ±50 % for nearly six months. Furthermore, an effect of baryte precipitation on the rock permeability was not observed. Finally, the fluid exchange procedure did not alter the rock transport properties. The results of the chemical fluid analysis are in support of these observations. In both experiments the electrical conductivity of the samples remained unchanged for a given fluid composition and constant p-T conditions. This emphasizes its valuable complementary character in determining changes in rock transport properties during long-term flow-through experiments when the risk of experimental artifacts is high.     

Wettability Alteration Mechanism for Oil Recovery from Fractured Carbonate Rocks

Oil can be recovered from fractured, initially oil-wet carbonate reservoirs by wettability alteration with dilute surfactant and electrolyte solutions. The aim of this work is to study the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and identify underlying mechanisms. Contact angles, phase behavior, and interfacial tensions were measured with two oils (a model oil and a field oil) at temperatures up to 90°C. There exists an optimal surfactant concentration for varying salinity and an optimal salinity for varying surfactant concentration at which the wettability alteration on an oil-aged calcite plate is the maximum for anionic surfactants studied. As the salinity increases, the extent of maximum wettability alteration decreases; also the surfactant concentration needed for the maximum wettability alteration decreases. IFT and contact angle were found to have the same optimal salinity for a given concentration of anionic surfactants studied. As the ethoxylation increases in anionic surfactants, the extent of wettability alteration on calcite plates increases. Wettability of oil-aged calcite plates can be altered by divalent ions at a high temperature (90°C and above). Sulfate ions alter wettability to a greater extent in the presence of magnesium and calcium ions than in the absence. A high concentration of calcium ions can alter wettability alone. Magnesium ions alone do not change calcite plate wettability. Wettability alteration increases the oil recovery rate from initially oil-wet Texas Cordova Cream limestone cores by imbibition.     

Empirical Measures of Wettability in Porous Media and the Relationship between Them Derived From Pore-Scale Modelling

The wettability of a crude oil/brine/rock system is of central importance in determining the oil recovery efficiency of water displacement processes in oil reservoirs. Wettability of a rock sample has traditionally been measured using one of two experimental techniques, viz. the United States Bureau of Mines and Amott tests. The former gives the USBM index, I _USBM, and the latter yields the Amott–Harvey index, I _AH. As there is no well-established theoretical basis for either test, any relationship between the two indices remains unclear.Analytical relationships between I _AH and I _USBM for mixed-wet and fractionally-wet media have been based on a number of simplifying assumptions relating to the underlying pore-scale displacement mechanisms. This simple approach provides some guidelines regarding the influence of the distribution of oil-wet surfaces within the porous medium on I _AH and I _USBM. More detailed insight into the relationship between I _AH and I _USBM is provided by modelling the pore-scale displacement processes in a network of interconnected pores. The effects of pore size distribution, interconnectivity, displacement mechanisms, distribution of volume and of oil-wet pores within the pore space have all been investigated by means of the network model.The results of these analytical calculations and network simulations show that I _AH and I _USBM need not be identical. Moreover, the calculated indices and the relationship between them suggest explanations for some of the trends that appear in experimental data when both I _USBM and I _AH have been reported in the literature for tests with comparable fluids and solids. Such calculations should help with the design of more informative wettability tests in the future.     

Effects of Fines Migration on Low-Salinity Waterflooding: Analytical Modelling

We discuss the governing system for oil–water flow with varying water composition. The model accounts for wettability alteration, which affects the relative permeability, and for salinity-variation-induced fines migration, which reduces the relative permeability of water. The overall ionic strength represents the aqueous phase composition in the model. One-dimensional displacement of oil by high-salinity water followed by low-salinity-slug injection and high-salinity water chase drive allows for exact analytical solution. The solution is derived using the splitting method. The analytical model obtained analyses the effects of wettability alteration and fines migration on oil recovery as two distinct physical mechanisms. For typical reservoir conditions, the significant effects of both mechanisms are observed.     

Network Modeling of EOR Processes: A Combined Invasion Percolation and Dynamic Model for Mobilization of Trapped Oil

A novel concept for modeling pore-scale phenomena included in several enhanced oil recovery (EOR) methods is presented. The approach combines a quasi-static invasion percolation model with a single-phase dynamic transport model in order to integrate mechanistic chemical oil mobilization methods. A framework is proposed that incorporates mobilization of capillary trapped oil. We show how double displacement of reservoir fluids can contribute to mobilize oil that are capillary trapped after waterflooding. In particular, we elaborate how the physics of colloidal dispersion gels (CDG) or linked polymer solutions (LPS) is implemented. The linked polymer solutions consist of low concentration partially hydrolyzed polyacrylamide polymer crosslinked with aluminum citrate. Laboratory core floods have shown demonstrated increased oil recovery by injection of linked polymer solution systems. LPS consist of roughly spherical particles with sizes in the nanometer range (50–150 nm). The LPS process involve mechanisms such as change in rheological properties effect, adsorption and entrapment processes that can lead to a microscopic diversion and mobilization of waterflood trapped oil. The purpose is to model the physical processes occurring on pore scale during injection of linked polymer solutions. A sensitivity study has also been performed on trapped oil saturation with respect to wettability status to analyze the efficiency of LPS on different wettability conditions. The network modeling results suggest that weakly wet reservoirs are more suitable candidates for performing linked polymer solution injection.     

Modelling Low-Salinity Oil Recovery Mechanisms Using an Ion Dissociation Model

Experimental evidence shows that injecting low-salinity water during the oil recovery process can lead to an increase in the amount of oil recovered. Numerous mechanisms have been proposed to explain this effect, and, in recent years, two which have gained notable support are multicomponent ionic exchange (MIE) and pH increase. Both mechanisms involve ion exchange reactions within the thin film of water separating the oil in a reservoir from the clay minerals on the surface of the reservoir rock. Since the reactions occur on the molecular scale, an upscaled model is required in order to accurately determine the dominant mechanism using centimetre-scale experiments. In this paper, we develop the first stages of this upscaling process by modelling the pore-scale motion of an oil slug through a clay pore throat. We use a law-of-mass-action approach to model the exchange reactions occurring on the oil–water and clay–water interfaces in order to derive expressions for the surface charges as functions of the salinity. By balancing the disjoining pressure in the water film with the capillary pressure across the oil–water interface, we derive an expression for the salinity-dependent film thickness. We compare the two mechanisms by modifying an existing model for the velocity of an oil slug through a pore throat. Numerical results show that the velocity increases as the salinity decreases. The percentage increase is larger for the MIE mechanism, suggesting that MIE may be the dominant causal mechanism; however, this will vary depending on the particular clay and oil being studied.

     

Preparation of porous silica spheres with self-dispersing properties

A sol-gel procedure in a water/oil emulsion was introduced for the synthesis of porous silica spheres. Tetraethoxysilane was used as the silica source. The specific surface area and total pore volume of the product reached 772.3 m2/g and 0.663 cm3/g, respectively. The electrolyte washing process conferred a surface charge to the product, which displayed self-dispersal properties in water. The porous spheres have potential applications in the fields of drug delivery, controlled release capsules, indoor air pollutant scavengers, and hydrogen storage agents. The oil phase, which accounts for over 8O% of the chemical cost of the procedure, could largely be recycled by filtering, standing, and layering. The whole procedure is suitable for application as an industrial process.