A Critical Review of the Role of Thin Liquid Films for Modified Salinity Brine Recovery Processes

Low salinity water injection (LSWI) is the process of injecting modified salinity brine with controlled ionic composition to achieve increased oil recovery compared to conventional waterflooding. This paper reviews the most recent advances in proposed low salinity mechanisms, but specifically emphasizes the role of thin liquid films in crude oil/brine/rock systems. Importantly, thin water films on rock surfaces affect hydraulic resistance of pore channels as well as phase-trapping mechanisms. As films become thicker, they provide greater lubrication of oil droplets and hence, flow resistance decreases. Consequently, films dictate oil and water distribution in porous media and determine the wettability of crude oil/brine/rock systems under static and dynamic conditions. The stability of the thin water films depends on the interactions between the oil/brine and the calcite/brine interfaces through van der Waals, electrostatic, and structural forces.     

Dynamics of capillary imbibition when surfactant, polymer, and hot water are used as aqueous phase for oil recovery

Capillary imbibition is an oil recovery mechanism in naturally fractured reservoirs if rock matrix is water wet and there is enough water in fractures in contact with matrix. It, however, may not yield an effective recovery under certain circumstances even if these conditions are maintained. Heavy matrix oil, high interfacial tension (IFT), oil-wet matrix sample, and limited contact area of matrix with water in fractures require additional effort to enhance the oil recovery by capillary imbibition. Chemicals and heat can be injected into naturally fractured reservoirs to improve the capillary imbibition recovery performance. With the involvement of low IFT fluid, heat, and polymer solution in the process, capillary imbibition dynamics may change and this entails an identification of the dynamics of the process through laboratory experiments before injection of these expensive fluids into oil reservoirs. In this study, the dynamics of capillary imbibition was studied experimentally. Static imbibition experiments were conducted on oil- and water-wet rock samples under different boundary conditions and saturated with different types of oil. The analyses were conducted using three indicators, namely the capillary imbibition rate, ultimate oil recovery, and shape of the recovery profile. Based on these indicators, the dynamics of capillary imbibition of different aqueous phases were evaluated for different oil types and matrix properties. The conditions that cause weak or strong capillary imbibition were identified.     

Using magnesium oxide nanoparticles in a magnetic field to enhance oil production from oil-wet carbonate reservoirs

Enhanced oil production can maximise yield from depleted reservoirs, and in the face of dwindling global oil reserves can reduce the need for exploratory drilling during the transition away from fossil fuels. A hybrid technique, merging a magnetic field (MF) and magnesium oxide (MgO) nanoparticles (NPs), was investigated as a potential method of enhancing oil production from oil-wet carbonate reservoirs. The impact of this hybrid technique on rock wettability, zeta potential, and interfacial tension was also investigated. Displacement experiments were carried out on oil-wet Austin chalk – a laboratory carbonate rock analogue – using MgO NPs in deionized water (DW) and salt water (SW), in the presence of an MF up to 6000 G in strength. It was found that the addition of MgO NPs to DW before the spontaneous imbibition of the solution into initially oil-wet rock samples increased the recovery factor (RF, defined as the volume of oil recovered divided by the initial oil in place). For 0.005 wt% and 0.0025 wt% MgO NPs mixed in DW, the RF was 12.5% and 15.9% respectively. When DW was replaced with SW as the imbibing fluid, the RF increased by a further 0.7% of initial oil in place for the 0.0025 wt% MgO NPs. This additional increase in oil recovery was attributed to the presence of potential determining ions, which made the rock more water-wet. To avoid pore-clogging and thus the limited ingress of the solution into the rock, the NPs’ concentration was kept low. This hybrid technique is a cleaner alternative to conventional enhanced oil recovery techniques and will enable oil industries to produce oil more efficiently from existing reservoirs: when used in conjunction with Carbon Capture and Storage (CCS), this provides a useful short to medium-term option to support energy production during the transition to net zero.     

Graded regulation technology for enhanced oil recovery and water shutoff in pore-cavity-fracture carbonate reservoirs

Although a single type of chemical agent (eg, gels, microspheres, surfactants, etc.) has achieved some effects in enhanced oil recovery of carbonate reservoirs, for pore-cavity-fracture carbonate reservoirs, the use of a single type of chemical agent does not perform well. The main objective of this study is to study the effect of different types of chemical agents in enhanced oil recovery of complex carbonate reservoirs. In order to determine the screening principle of chemical agents, the types of water channeling in the North Troyes reservoir were analyzed. For complex fractures, step by step plugging, multi-agent and multi-slug comprehensive intervention is carried out to ensure the plugging of high-permeability channels and inhibit the seepage of large channels. It can plug channeling fracture channel, adjust secondary dominant channel and reduce matrix flow resistance, so as to expand macroscopic swept volume and improve microscopic water flooding efficiency. The results show that it is difficult to comprehensively control water channeling in pore-cave-fracture carbonate reservoir, and the reservoir heterogeneity in the test area can be improved by mixing different types of control and flooding agents and carrying out deep profile control. The plugging rate of gel is 97.18 %, and the oil–water selection ratio is 0.45 in fractured core; the expansion rate of nano - microspheres is more than 3 times; the wetting modifier can improve the imbibition oil displacement efficiency by 14.76%, and the test result shown that nano - microspheres and wetting modifier have good synergistic oil displacement effect. The field application result shown that daily oil production of oil well in the test area increased by 5.0 m³/d and the daily water rate decreased by 19.0% compared with that before the control flooding. The findings of this study can help for better understanding of enhanced oil recovery in pore-cave-fracture carbonate reservoir.     

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.     

Study on Influencing Factors of Chemical Flooding for Heavy Oil

Alkali and alkali/surfactant displacing agents are designed for two kinds of heavy oil. Results of emulsifying capacity, dynamic interfacial tension (IFT) and water-wet core flooding tests show that, although alkaline/surfactant systems exhibit better capacity in emulsification and IFT reduction, oil recovery values of alkaline/surfactant flooding are lower than those of alkaline flooding. Glass-etched micromodel tests further demonstrate that, when alkaline solution penetrates into the oil phase, water streams break into ganglia coating oil film. Water ganglia may be entrapped by narrow throats, consequently presenting a water-oil alternating slug flow. Similar water ganglia also appears in alkaline/surfactant flooding, however, water channeling along the pore surface occurs subsequently, resulting in its relatively lower oil recovery.     

Study on Oil Recovery Mechanism of Polymer-Surfactant Flooding Using X-ray Microtomography and Integral Geometry

Understanding pore-scale morphology and distribution of remaining oil in pore space are of great importance to carry out in-depth tapping of oil potential. Taking two water-wet cores from a typical clastic reservoir in China as an example, X-ray CT imaging is conducted at different experimental stages of water flooding and polymer-surfactant (P-S) flooding by using a high-resolution X-ray microtomography. Based on X-ray micro-CT image processing, 3D visualization of rock microstructure and fluid distribution at the pore scale is achieved. The integral geometry newly developed is further introduced to characterize pore-scale morphology and distribution of remaining oil in pore space. The underlying mechanism of oil recovery by P-S flooding is further explored. The results show that the average diameter of oil droplets gradually decreases, and the topological connectivity becomes worse after water flooding and P-S flooding. Due to the synergistic effect of “1 + 1 > 2” between the strong sweep efficiency of surfactant and the enlarged swept volume of the polymer, oil droplets with a diameter larger than 124.58 μm can be gradually stripped out by the polymer-surfactant system, causing a more scattered distribution of oil droplets in pore spaces of the cores. The network-like oil clusters are still dominant when water flooding is continued to 98% of water cut, but the dominant pore-scale oil morphology has evolved from network-like to porous-type and isolated-type after P-S flooding, which can provide strong support for further oil recovery in the later stage of chemical flooding.     

Flow behaviors of a viscoelastic polymer solution at 3D micro pore-throat structure

Polymers are abundantly used in oil production industry, especially in enhanced oil recovery process. The underground oil reservoir is a kind of porous media where complex microscopic geometries lead to strong shearing and extensional components. This research focuses on a novel method used to investigate the flow behaviors of hydrolyzed polyacrylamide solution at a micro pore-throat structure with a comparison with Newtonian flow of water. For polymer solution, the flow velocimetry revealed the viscoelastic flow has two main characters compared with Newtonian fluid. First, the instability or non-linearity of polymer flows led to bending and distorted streamlines. The instability of the flow is mainly caused by the growth of high stress generated in the viscoelastic polymer fluid as it accelerates and decelerates into and out from the narrow throat, respectively speaking. The second character is the back-streams at the outlet of the throat.     

Biosorption of Heavy Metal Ions to A Marine Microalga, Heterosigma akashiwo (Hada) Hada

Alkaline flooding is a method of enhanced oil recovery that relies on the formation of surface-active substances in situ by a chemical reaction between acidic components in the oil and an alkaline reagent. As the injected alkali advances through the porous medium, it keeps contacting fresh oil. At some moment dependent on the alkali/acid concentrations and the velocity, the alkali at the advancing front may become depleted and the flood becomes interfacially nonreactive. The present study is aimed at investigating the above-mentioned phenomena. Displacement studies were conducted in radial cells containing sintered glass beads as a porous medium. Light paraffin oil acidified with 10 mmol/L of linoleic acid served as the displaced (oil) phase while the displacing aqueous solution contained 0-25 mmol/L of sodium hydroxide. The highest oil recovery was obtained under the conditions of low flow rate and high alkali concentration. Increasing the flow rate at high NaOH concentration resulted in decreasing oil recovery up to a certain threshold flow rate. Conversely, the amount of oil recovered by waterflooding only (no alkali) initially increased with increasing flow rate up to the same threshold flow rate beyond which there was no difference between the alkaline flood and a waterflood. Copyright 2000 Academic Press.     

A Modified Contact Angle Measurement Process to Suppress Oil Drop Spreading and Improve Precision

Static contact angle measurement is a widely applied method for wettability assessment. Despite its convenience, it suffers from errors induced by contact angle hysteresis, material heterogeneity, and other factors. This paper discusses the oil drop spreading phenomenon that was frequently observed during contact angle measurements. Experimental tests showed that this phenomenon is closely related to surfactants in the surrounding phase, the remaining oil on the rock surface, and oil inside the surrounding phase. A modified contact angle measurement process was proposed. In the modified method, deionized water was used as the surrounding phase, and a rock surface cleaning step was added. Subsequent measurements showed a very low chance of oil drop spreading and improved precision. A further comparison study showed that, when the surrounding phase was deionized water, the measured contact angle values tended to be closer to intermediate-wet conditions compared to the values measured in clean surfactant solutions. This difference became more significant when the surface was strongly water-wet or strongly oil-wet. As a result, the developed process has two prerequisites: that the in-situ contact angle values inside surfactant solutions are not required, and that the wettability alteration induced by the surfactant solution is irreversible.     

Wettability alteration of carbonate rocks from strongly liquid-wetting to strongly gas-wetting by fluorine-doped silica coated by fluorosilane

Wettability alteration is an important mechanism to increase recovery from oil and gas reservoirs. In this study, effect of fluorine-doped silica coated by fluorosilane nanofluid on wettability alteration of carbonate rock was investigated. The nanoparticle synthesized by sol-gel method was characterized using XRD, FTIR, SEM, and DLS. Adsorption of nanoparticle on rock was characterized by FESEM, and composition of rock after treatment was determined by EDXA. Effect of nanofluid on wettability was investigated by measuring static, advancing, and receding contact angle and surface free energy, imbibition of water, crude oil, and condensate of untreated and treated carbonate rock. Also, stability of contact angle and thermal stability of nanofluid were studied. ?Results show that contact angles for water, condensate, and crude oil were altered from 37.95°, 0°, ?and 0° to 146.47°, 145.59°, and 138.24°. In addition, water, condensate, and oil imbibition ?decreased more than 87, 88, and 80%, indicating that wettability was altered from strongly oil wet, ?condensate wet, and water wet to strongly gas wet. The ultraoleophobic and ultrahydrophobic stability were >48 hours and 120 minutes. Surface free energy of treated rock for water, crude oil, and condensate was ?2.24, 1.17, and 1.47mN/m. Thermal stability of nanofluids and adsorbed nanoparticle was up to 150°C.     

用聚丙烯酰胺水溶液驱替油溶液的粘性指进现象的研究(Ⅰ)

流度比;驱油溶液;用聚丙烯酰胺水溶液驱替油溶液的粘性指进现象的研究(Ⅰ)     

Parametric analysis of surfactant-aided imbibition in fractured carbonates

Many carbonate oil reservoirs are oil-wet and fractured; waterflood recovery is very low. Dilute surfactant solution injection into the fractures can improve oil production from the matrix by altering the wettability of the rock to a water-wetting state. A 2D, two-phase, multicomponent, finite-volume, fully-implicit numerical simulator calibrated with our laboratory results is used to assess the sensitivity of the process to wettability alteration, IFT reduction, oil viscosity, surfactant diffusivity, matrix block dimensions, and permeability heterogeneity. Capillarity drives the oil production at the early stage, but gravity is the major driving force afterwards. Surfactants which alter the wettability to a water-wet regime give higher recovery rates for higher IFT systems. Surfactants which cannot alter wettability give higher recovery for lower IFT systems. As the wettability alteration increases the rate of oil recovery increases. Recovery rate decreases with permeability significantly for a low tension system, but only mildly for high tension systems. Increasing the block dimensions and increasing oil viscosity decreases the rate of oil recovery and is in accordance with the scaling group for a gravity driven process. Heterogeneous layers in a porous medium can increase or decrease the rate of oil recovery depending on the permeability and the aspect ratio of the matrix block.     

Polymers for Enhanced Oil Recovery Technology

Recently enhance oil recovery (EOR) technology is getting more attention by many countries since energy crises are getting worse and frightened. One of the reasons for this is due to the shortage of current oil resources and difficulties in finding a new oil field. Indonesia is one of the examples, before 2004 Indonesia is a net oil exporting country but after that Indonesia is a net oil importing country. The oil demand in the country is increasing while the oil production capacity is decreasing. In fact, when a new oil reservoir is drilled, the oil amount obtained from it is about 20-40% of the potential and hence there is still 60-80% oil left in the reservoir. Application of EOR technology gives an additional chance to get out more oil from the reservoir, possibly about another 20%. Polymer is the material that plays an important role in the application of EOR technology, especially surfactant and hydrogel polymers. In the technology, surfactant polymer is injected to the reservoir to reduce an interfacial tension between oil and water and is able to wipe out the trapped oil from the reservoir rock and hence increase the oil production. While an injection of hydrogel polymer to the reservoir is to increase a viscosity of fluid containing water so that the fluid is more difficult to flow than the oil, and as a result, the oil production increases. The most common polymer used for this application is polyacrylamide group.     

Oil recovery performances of surfactant solutions by capillary imbibition

Critical parameters playing a role in oil recovery by capillary imbibition of surfactant solutions were studied. Experiments conducted on sandstone and carbonate samples using different oil and surfactant types were evaluated for surfactant selection. In this evaluation interfacial tension (IFT), surfactant type, solubility characteristics of surfactants, rock type, initial water (pre-wet rock), and surfactant concentration were considered. In addition to these, a new technique was adopted to facilitate the surfactant screening process. This technique is based on assigning inorganic and organic property values and plotting organic conception diagrams (OCD) for surfactants. OCD defines the property of a compound in terms of physical chemistry in such a way that the property that depends much on the van der Waals force is called "organic" and the one that depends much on electric affinity is called "inorganic." Correlations between the capillary imbibition recovery performance and the properties of surfactant and oil (organic value (OV), inorganic value (IV), and IFT of surfactant solutions, oil viscosity, and surfactant type) were obtained. These correlations are expected to be useful in selecting the proper surfactant for improved oil recovery as well as identifying the effects of surfactant properties on the capillary imbibition performance.     

Thermal and rheological study of polysaccharides for enhanced oil recovery

Enhanced oil recovery process is based on the injection of chemical products (e.g. polymers, surfactants, gases) or thermal energy (originating from the injection of e.g. steam, hot water, in situ combustion) to recover crude oil. One of these processes use polymer solution to mobilize the oil in the reservoir. In this work the thermal decomposition kinetic of xanthan gum, guar gum and a blend (50/50 mass/mass%) was studied according to Ozawa–Flynn–Wall method. According to the kinetic analysis, the studied systems were copmpatible. The rheological behavior of the samples was studied in distilled water and seawater at different temperatures. Only the blend was studied in distilled water presented synergism (enhancement in material properties like stability and viscosity) which was confirmed through rheology.     

Aggregate formation in oil and adsorption at oil/water interface: thermodynamics and its application to the oleyl alcohol system

The thermodynamic equations for examining aggregate formation in an oil phase and adsorption at the oil/water interface of a nonionic solute were derived. The total differentials of chemical potentials of species and the oil/water interfacial tension were expressed as functions of temperature, pressure, and the total concentration of solute in the oil phase after explicit consideration of aggregate formation. The partial derivatives of the chemical potentials and the interfacial tension with respect to the independent variables were found to provide the thermodynamic quantities of aggregate formation and adsorption from oil phase to the interface by introducing the concept of an ideally dilute associated solution. These equations were applied to the cyclohexane solution of oleyl alcohol/water system, and the adsorption and aggregate formation was examined.     

Reservoir-on-a-chip (ROC): a new paradigm in reservoir engineering

In this study, we design a microfluidic chip, which represents the pore structure of a naturally occurring oil-bearing reservoir rock. The pore-network has been etched in a silicon substrate and bonded with a glass covering layer to make a complete microfluidic chip, which is termed as 'Reservoir-on-a-chip' (ROC). Here we report, for the first time, the ability to perform traditional waterflooding experiments in a ROC. Oil is kept as the resident phase in the ROC, and waterflooding is performed to displace the oil phase from the network. The flow visualization provides specific information about the presence of the trapped oil phase and the movement of the oil/water interface/meniscus in the network. The recovery curve is extracted based on the measured volume of oil at the outlet of the ROC. We also provide the first indication that this oil-recovery trend realized at chip-level can be correlated to the flooding experiments related to actual reservoir cores. Hence, we have successfully demonstrated that the conceptualized 'Reservoir-on-a-Chip' has the features of a realistic pore-network and in principle is able to perform the necessary flooding experiments that are routinely done in reservoir engineering.     

Coreflooding and Pore-Scale Visualization of Foamed Gel Flowed in Porous Network Media

To investigate the mechanisms of enhancing oil recovery and the flow behaviors of foamed gel in porous media, foamed gels with characteristics of excellent strength and viscosity were prepared with polymer, crosslinking agent, foam agent, and formation water. The breakthrough-vacuum method and a rotary viscometer were used to evaluate the strength and viscosity of foamed gel. Coreflooding and pore-level visualization experiments were performed in heterogeneous reservoir models. Laboratory results illustrate that high strength and viscosity of foamed gel can be prepared by 0.15% NJ-8, 0.2% polyacrylamide solution, and 1.5% foaming agent. The strength and viscosity of the foamed gel reached 0.06 MPa and 10,000 MPa · s, respectively. The results of coreflooding experiments in heterogeneous cores show that oil recovery can be improved by approximately 36.9% after injecting 0.3 pore volume of the foamed gel, and enhanced oil recovery is mainly attributed to the improving sweep efficiency of mid- to low-permeability layers. Images of visualization flooding demonstrate that foamed gel exhibits good oil resistance and elasticity when used with crude oil. Furthermore, the new amoeba effect, Jamin effect, fluid-diverting effect, and extruding effect between foamed gel and oil in porous media can enhance oil recovery by improving sweep efficiency.     

Novel investigation based on cationic modified starch with residual anionic polymer for enhanced oil recovery

Cationic modified starch polymer (CMSP) is a newly developed green chemical agent designed to reutilize the residual anionic polymer found in reservoirs for enhanced oil recovery (EOR). In this study, a series of experiments were conducted to investigate the phase behavior of the residual anionic polymer, CMSP solution, and the flocculation generated from the mixture in plugging capacity and capability of enhancing oil recovery in heterogeneous reservoirs. The experiment results show that the phase behavior of the residual anionic polymer and CMSP solution could be divided into two parts: rapid flocculation reaction and dispersion reaction. The main mechanisms of the rapid flocculation reaction were charge neutralization and bridging. Based on the above results, an optimal amount of CMSP was chosen for plugging capacity, stability, and EOR study. Plugging tests in both parallel cores and EOR in three-layer heterogeneous square cores illustrate that the injected CMSP slug after polymer flooding can effectively block the high-permeability zone and initiate the remaining oil in middle- to low-permeability zones. The investigation results prove that the CMSP solution, injected after polymer flooding, reduces the pollution of produced fluid and further improves oil recovery.