Spontaneous Imbibition Process Research Articles

Pore-scale two-phase filtration in imbibition process through porous media at high- and low-interfacial tension flow conditions

This study provides new insights into pore-scale two-phase filtration during imbibition process through porous media under the high- and low-interfacial tension (IFT) flow conditions. First, the distribution and configuration of imbibing wetting and non-wetting phases in primary imbibition (free spontaneous imbibition or wetting process) is depicted. Second, the detailed pore-scale topology, structure, distribution, and configuration of different phases together with the pore-scale displacement mechanisms in primary drainage (i.e., desaturation of continuous wetting phase or de-wetting process), secondary imbibition (i.e., controlled spontaneous imbibition or desaturation of continuous non-wetting phase in high-IFT flow condition), and tertiary imbibition (i.e., forced imbibition or mobilization of discontinuous trapped non-wetting phase in low-IFT flow condition), are expounded. Finally, the advance of the displacement front and flow pattern configuration in secondary and tertiary imbibition is demonstrated and discussed. Furthermore, in tertiary imbibition, the blob size distribution of the displacing wetting phase, formation of the secondary displacement front and wetting film before breakthrough of the displacing wetting phase, rate-dependency of the advance of secondary displacement front and wetting film, interruption of the wetting film flow within wetting film region, pore-level phenomena within the wetting film region, and role of wetting film in pore-scale displacement mechanism are elucidated.

Enhanced Wettability Alteration by Surfactants with Multiple Hydrophilic Moieties

AbstractThe main production mechanism during water flooding of naturally fractured oil reservoirs is the spontaneous imbibition of water into matrix blocks and resultant displacement of oil into the fracture system. This is an efficient recovery process when the matrix is strongly water‐wet. However, in mixed‐ to oil‐wet reservoirs, secondary recovery from water flooding is often poor. Oil production can be improved by dissolving low concentrations of surfactants in the injected water. The surfactant alters the wettability of the reservoir rock, enhancing the spontaneous imbibition process. Our previous study revealed that the two main mechanisms responsible for the wettability alteration are ion‐pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface. Based on the superior performance of surfactin, an anionic biosurfactant with two charged groups on the hydrophilic head, it was hypothesized that the wettability alteration process might be further improved through the use of dimeric or gemini surfactants, which have two hydrophilic head groups and two hydrophobic tails. We believe that when ion‐pair formation is the dominant wettability alteration mechanism, wettability alteration in oil‐wet cores can be improved by increasing the charge density on the head group(s) of the surfactant molecule since the ion‐pair formation is driven by electrostatic interactions. At a concentration of 1.0 mmol L−1 a representative anionic gemini surfactant showed oil recoveries of up to 49% original oil‐in‐place (OOIP) from oil‐wet sandstone cores, compared to 6 and 27% for sodium laureth sulfate and surfactin, respectively. These observations are consistent with our hypothesis.

A Many-Body Dissipative Particle Dynamics Study of Spontaneous Capillary Imbibition and Drainage

The spontaneous capillary imbibition and drainage processes are studied using many-body dissipative particle dynamics (MDPD) simulations. By adjusting the solid-liquid interaction parameter, different wetting behavior between the fluid and the capillary wall, corresponding to the static contact angle ranging from 0 degrees to 180 degrees, can be controllably simulated. For wetting fluids, the spontaneous capillary imbibition (SCI) is evident in MDPD simulations. It is found that, whereas the corrected Lucas-Washburn equation (taking into account the dynamic contact angle and the fluid inertia) can well describe the SCI simulation result for the completely wetting fluid, it deviates, to a notable degree, from the results of partly wetting fluids. In particular, this corrected equation cannot be used to describe the spontaneous capillary drainage (SCD) processes. To solve this problem, we derive an improved form of the Lucas-Washburn equation, in which the slip effects of fluid particles at the capillary wall are treated. Such an improved equation turns out to be capable of describing all the simulation results of both the SCI and the SCD. These findings provide new insights into the SCI and SCD processes and improve the mathematical base.

Fractal Characterization of Spontaneous Co-current Imbibition in Porous Media

Spontaneous capillary imbibition is an important fundamental phenomenon existing extensively in a variety of processes such as polymer composite manufacturing, oil recovery, soil science and hydrology, etc. In this work, analytical expressions for characterizing a spontaneous co-current imbibition process of wetting fluid into gas-saturated porous media are proposed based on the fractal characters of porous media. The mass of imbibed liquid is expressed as a function of the fractal dimensions for pores and for tortuous capillaries, the minimum and maximum hydraulic diameter of pores, and the ratio for minimum to maximum hydraulic diameters, porosity, and fluid properties, as well as the fluid−solid interaction. The imbibed weight predicted by the present model is in good agreement with the available experimental data.

Mechanistic Study of Wettability Alteration Using Surfactants with Applications in Naturally Fractured Reservoirs

In naturally fractured reservoirs, oil recovery from waterflooding relies on the spontaneous imbibition of water to expel oil from the matrix into the fracture system. The spontaneous imbibition process is most efficient in strongly water-wet rock where the capillary driving force is strong. In oil- or mixed-wet fractured carbonate reservoirs, however, the capillary driving force for the spontaneous imbibition process is weak, and therefore the waterflooding oil recoveries are low. The recovery efficiency can be improved by dissolving low concentrations of surfactants in the injected water to alter the wettability of the reservoir rock to a more water-wet state. This wettability alteration accelerates the spontaneous imbibition of water into matrix blocks, thereby increasing the oil recovery during waterflooding. Several mechanisms have been proposed to explain the wettability alteration by surfactants, but none have been verified experimentally. Understanding of the mechanisms behind wettability alteration could help to improve the performance of the process and aid in identification of alternative surfactants for use in field applications. Results from this study revealed that ion-pair formation and adsorption of surfactant molecules through interactions with the adsorbed crude oil components on the rock surface are the two main mechanisms responsible for the wettability alteration. Previous researchers observed that, for a given rock type, the effectiveness of wettability alteration is highly dependent upon the ionic nature of the surfactant involved. Our experimental results demonstrated that ion-pair formation between the charged head groups of surfactant molecules and the adsorbed crude oil components on rock surface was more effective in changing the rock wettability toward a more water-wet state than the adsorption of surfactant molecules as a monolayer on the rock surface through hydrophobic interaction with the adsorbed crude oil components. By comparing two anionic surfactants with different charge densities, we propose that wettability alteration processes might be improved through the use of dimeric surfactants, which have two charged head groups and two hydrophobic tails. Gemini surfactants where the molecules are joined at the head end are likely to be effective when ion-pair formation is the wettability alteration mechanism, and bolaform surfactants, in which molecules are joined by the hydrophobic tails, should be more effective in the case of surfactant monolayer adsorption.

Effect of Temperature on Enhanced Oil Recovery from Mixed-Wet Chalk Cores by Spontaneous Imbibition and Forced Displacement Using Seawater

Seawater, as wettability modifier in chalk, has been studied at different temperatures and flooding conditions. Without sulfate initially present in the formation water, previous studies by spontaneous imbibition have shown that a temperature of about 100 °C is needed for the wettability modification to take place. The temperature plays a very important role for the chemical reactions taking place at the chalk surface and for the diffusion of active ions (Ca2+, Mg2+, and SO42−) into the chalk matrix. In the present study, the enhanced oil recovery using seawater was studied by both spontaneous imbibition and viscous flooding at 90, 110, and 120 °C. A crude oil of high acid number (AN = 1.90 mg of KOH/g) was used to ensure a low, initial water wetness. At 90 °C, no difference in oil recovery using seawater and formation water in a spontaneous imbibition process was observed, but in the following viscous flooding process, seawater enhanced the oil recovery by 14% compared to formation water. At 110 and 120 °C, the impact of wettability modification using seawater became even more significant regarding oil recovery, but still, the viscous flood by seawater improved the oil recovery significantly compared to formation water. As a conclusion, improvements in oil recovery using seawater as a wettability modifier are obtained even at 90 °C, when displacing the oil by a viscous flood at low flooding rate.

New wettability test for chalk based on chromatographic separation of SCN − and SO 42−

Wettability, water-wetness or oil-wetness, is usually defined in terms of the method used to determine the wetting state of a porous medium. In the Amott test, which is most frequently used for porous media, the wetting indices of water and oil are determined by the extent of spontaneous imbibition of water and oil from the state of the corresponding residual fluid saturations of the core. Thus, the Amott fluid wetting index reflects the potential capillary energy associated with the spontaneous imbibition process, which results in a very insensitive way to detect wetting alterations close to neutral conditions. Unfortunately, the natural wetting state of many carbonate reservoirs is close to neutral conditions or preferential oil-wet. In this paper, the wetting state of porous chalk is characterized by the fraction of surface area covered by one of the two fluids, i.e. water or oil. As the new wettability test is based on the chromatographic separation of two water-soluble components, i.e. a tracer, SCN −, and a potential determining ion towards chalk, SO 4 2−, the fraction of the surface area covered by water was decided to represent the new wetting index. Using a chalk core at residual oil saturation, the area between the effluent curves for SCN − and SO 4 2− is proportional to the area contacted by water during the flooding process. The ratio between this area and the corresponding area obtained from a completely water-wet core will give a water index between 0 and 1, representing completely oil-wet and completely water-wet conditions, respectively. The method is excellent to be used close to neutral condition, which will give a wetting index of 0.5. Experimental results are presented for two different chalks at different wetting conditions. Furthermore, the change in the Zeta-potential of the chalk surface over the dispersion zone of SO 4 2− is visualised by a gradient in the Ca 2+ concentration in the same region.

Characterization of Spontaneous Water Imbibition Into Gas-Saturated Rocks

Summary A method has been developed to characterize the process of spontaneous water imbibition into gas-saturated rocks. Water relative permeability and capillary pressure can be calculated simultaneously from water imbibition data using this method. A linear relationship between imbibition rate and the reciprocal of the gas recovery by spontaneous water imbibition was found and confirmed both theoretically and experimentally, even at different initial water saturations. There was almost no effect of initial water saturation on residual gas saturation by spontaneous water imbibition. The higher the initial water saturation, the lower the imbibition rate and the ultimate gas recovery. It was found that the capillary pressure did not vary with initial water saturation in a certain range. The capillary pressure and the water relative permeability calculated using the new method was consistent with the experimental results measured using other techniques. The method developed in this paper is also of importance for scaling up experimental data.

Modeling forced versus spontaneous capillary imbibition processes commonly occurring in porous sediments

The extraction of ganglia of non-wetting petroleum fluid from underground reservoirs can occur whenever they are displaced and replaced by an invading wetting (e.g. aqueous) fluid phase. The problem is how to best specify, quantify, observe, and beneficially control such petroleum recovery processes. Cases that are considered are those that result form the fact that there may be two separate but superimposed imbibition mechanisms involved that inherently can reinforce and supplement each other. For example, when the displacing fluid phase more-or-less flows colinearly with the one being replaced, this will happen whenever it is only the imposition of mechanical energy gradients that causes it to happen. These kinds of processes can be thought of as being due to a forced imbibition mechanism. At the same time, however, a parallel spontaneous imbibition mechanism also can come into play whenever the local free interfacial surface energy of the system simultaneously is being diminished with time. The latter happens, of course, whenever the higher energy oil–rock interfacial tensions spontaneously become replaced by lower energy water–rock interfacial tensions. In effect, it is as though the entering wetting fluids push forward in ways somewhat akin to why a ball will roll down an unobstructed hill path by itself! To obtain a clear picture of what is involved, consideration should be given to the following three self-evident (but easily overlooked) propositions. First, it is easy to show that petroleum recovery due to the spontaneous imbibition effects can occur even when externally imposed forcing effects are totally absent. Second, it turns out to be clearly indicated that even in cases when superficially the magnitudes of the spontaneous imbibition effects appear to be minuscule compared to those caused by prevailing superimposed forced imbibition mechanisms, the influence of the former effects may not themselves prove to be necessarily inconsequential. Third, whenever rationally based algorithms are employed (viz. rather than simplified ones which are intended to mitigate and alleviate some of the computational problems), this will be the best way to guarantee that quantitatively believable reservoir performance simulation outcomes will be achieved. This latter proposition implicitly is affirmed by the work of Rose [Math. Geol. 22 (1990) 641] where reference was made to the apparent way simulation outputs for idealized systems were different depending on either or not spontaneous imbibition effects were incorporated in the analyses.

Spontaneous imbibition processes in Hele‐Shaw cells

AbstractExperiments on spontaneous imbibition processes in Hele‐Shaw cells were carried out in squared cells (20 cm × 20 cm) with separations of 0.005, 0.015 and 0.075 cm using twice‐distilled water and Soltrol 170 as the displacing and displaced fluids, respectively. The experiments indicated that it was possible to repeat the main features of the spontaneous imbibition process using a procedure for wettability restoration of the glass sheets. The best sweep efficiency was achieved for the 0.015 cm cell gap. Two or three consecutive stages occurred depended on the cell gap, as evidenced by a characteristic speed and a characteristic advancing front structure. The initial stage speed/development stage speed ratio and the oil total area/water‐oil total interfacial length ratio as functions of time were gap‐dependent. The capillary number and interfacial power density estimations indicated that at about 0.033 cm gap there was a flow pattern transition from slightly uniform displacement to fingering flow.