Rate Of Spontaneous Imbibition Research Articles

Experimental study of water imbibition characteristics of the lacustrine shale in Sichuan Basin

Through the stimulation method of large-scale hydraulic fracturing, the spontaneous imbibition capacity of the water phase in the shale reservoir has great influence on the effect of stimulation. Generally, the lacustrine shale has the characteristics of high clay minerals content, strong expansibility, development of nanopores and micro-pores, and underdevelopment of fractures, which leads to the unclear behavior of spontaneous imbibition of aqueous phase. The lacustrine shale of Da'anzhai Member and marine shale of Longmaxi Formation in Sichuan Basin were selected to prepare both the shale matrix sample and fractured shale sample, and the spontaneous imbibition experiment of simulated formation water was carried out. By means of an XRD test, SEM observation, nuclear magnetic resonance test and linear expansion rate test, the mineral composition, the structure of pores and fractures, the capacity of hydration and expansion of both lacustrine and marine shale are compared and analyzed. The results show that the average spontaneous imbibition rate of lacustrine shale is 60.8% higher than that of marine shale within the initial 12 hours of imbibition. The lacustrine shale has faster imbibition rate than the marine shale in the initial stage of spontaneous imbibition. However, the lacustrine shale has underdeveloped pores and fractures, as well as poor connectivity of pores. Besides, the strong hydration and expansion of clay minerals can easily lead to dispersion and migration of clay minerals on the fracture surface, which will plug up the seepage channels, resulting in poor capacity of spontaneous imbibition. The spontaneous imbibition rate in the middle and late stage of Lacustrine shale is obviously lower than that of the marine shale. The overall spontaneous imbibition rate ability of the lacustrine shale is less than that of the marine shale. According to the characteristics of water imbibition of lacustrine shale, considering the dual effects of hydration expansion of clay minerals on the effective reconstructed volume, the microfractures can be initiated and extended by fully utilizing the hydration of shale. Acidification treatment, oxidation treatment or high temperature treatment can be used to expand pore space, enhance water phase imbibition capacity and improve multi-scale mass transfer capacity of the lacustrine shale.

Effect of Fluid Properties on Contact Angles in the Eagle Ford Shale Measured with Spontaneous Imbibition.

Models of fluid flow are used to improve the efficiency of oil and gas extraction and to estimate the storage and leakage of carbon dioxide in geologic reservoirs. Therefore, a quantitative understanding of key parameters of rock–fluid interactions, such as contact angles, wetting, and the rate of spontaneous imbibition, is necessary if these models are to predict reservoir behavior accurately. In this study, aqueous fluid imbibition rates were measured in fractures in samples of the Eagle Ford Shale using neutron imaging. Several liquids, including pure water and aqueous solutions containing sodium bicarbonate and sodium chloride, were used to determine the impact of solution chemistry on uptake rates. Uptake rate analysis provided dynamic contact angles for the Eagle Ford Shale that ranged from 51 to 90° using the Schwiebert–Leong equation, suggesting moderately hydrophilic mineralogy. When corrected for hydrostatic pressure, the average contact angle was calculated as 76 ± 7°, with higher values at the fracture inlet. Differences in imbibition arising from differing fracture widths, physical liquid properties, and wetting front height were investigated. For example, bicarbonate-contacted samples had average contact angles that varied between 62 ± 10° and ∼84 ± 6° as the fluid rose in the column, likely reflecting a convergence–divergence structure within the fracture. Secondary imbibitions into the same samples showed a much more rapid uptake for water and sodium chloride solutions that suggested alteration of the clay in contact with the solution producing a water-wet environment. The same effect was not observed for sodium bicarbonate, which suggested that the bicarbonate ion prevented shale hydration. This study demonstrates how the imbibition rate measured by neutron imaging can be used to determine contact angles for solutions in contact with shale or other materials and that wetting properties can vary on a relatively fine scale during imbibition, requiring detailed descriptions of wetting for accurate reservoir modeling.

Simulation of Counter-Current Spontaneous Imbibition Based on Momentum Equations with Viscous Coupling, Brinkman Terms and Compressible Fluids

A numerical model is investigated representing counter-current spontaneous imbibition of water to displace oil or gas from a core plug. The model is based on mass and momentum conservation equations in the framework of the theory of mixtures. We extend a previous imbibition model that included fluid–rock friction and fluid–fluid drag interaction (viscous coupling) by including fluid compressibility and Brinkman viscous terms. Gas compressibility accelerated recovery due to gas expansion from high initial non-wetting pressure to ambient pressure at typical lab conditions. Gas compressibility gave a recovery profile with two characteristic linear sections against square root of time which could match tight rock literature experiments. Brinkman terms decelerated recovery and delayed onset of imbibition. Experiments where this was prominent were successfully matched. Both compressibility and Brinkman terms caused recovery deviation from classical linearity with the square root of time. Scaling yielded dimensionless numbers when Brinkman term effects were significant.Article HighlightsSpontaneous imbibition with viscous coupling, compressibility and Brinkman terms.Viscous coupling reduces spontaneous imbibition rate by fluid–fluid friction.Brinkman terms delay early recovery and explain seen delayed onset of imbibition.Gas compressibility accelerates recovery and can be significant at lab conditions.Gas compressibility gives recovery with two root of time lines as seen for shale.

Experimental Study on the EOR Performance of Imbibition and Huff and Puff in Fractured Tight Oil Reservoirs

AbstractInjection of imbibition fluids or CO2 during hydraulic fracturing is an effective stimulation method for tight oil reservoirs. Selecting appropriate agents is significant to optimize the integrated scheme of fracturing and production in tight oil reservoirs. In this study, a series of lab experiments, including spontaneous imbibition, dynamic imbibition, and huff and puff, were carried out using real tight cores, water absorption apparatus, and core flooding equipment. The EOR performances of imbibition fluids and CO2 in fractured tight cores were compared. The mass transfer of imbibition fluids and CO2 in tight oil reservoirs and its influence on the sweeping volume and EOR mechanisms were discussed. The results show that (1) the spontaneous imbibition rate of imbibition fluids in tight cores is slow, and the oil recovery factor by spontaneous imbibition in cracked cores is relatively high, up to 13.42%. (2) In the dynamic imbibition experiments, the final oil recovery by CO2 injection was significantly higher than that by injecting imbibition liquids. Because of the excellent miscibility effect of CO2, oil production by CO2 injection mainly occurred in the primary displacement stage. Comparatively, the EOR effect of imbibition fluids mainly played its role during production after well shut-in, which can increase the oil recovery factor by 7.35%-11.64%. (3) The influence of the huff and puff mode of CO2 on EOR performance is greater than that of imbibition fluids due to its more sensitive compressibility and mass transfer rate. Generally, a high oil recovery factor can be obtained if the depletion production is conducted first, and a huff and puff operation is followed. (4) Comprehensively understanding the mass transfer characteristics of CO2 and imbibition fluids in tight oil reservoirs can guide the fracturing parameter design, such as the order of fracturing fluid slugs, the optimal soak time, and fracture spacing.

Synergistic effects between anionic and amphoteric surfactants on promoting spontaneous imbibition in ultra-low permeability reservoirs: Study of mechanism and formula construction

Faster spontaneous imbibition in ultra-low permeability reservoirs ensures higher productivity. Surfactants can promote spontaneous imbibition by creating a strong water-wet condition while keeping the oil-water interfacial tension (IFT) at an intermediate level. In this paper, A surfactant mixture composed of Alpha Olefin Sulfonate (AOS, an anionic surfactant) and Cocoamidopropyl-Hydroxysulfobetaine (CHSB-35, an amphoteric surfactant)CHSB-35 was proposed to promote the spontaneous imbibition rate of Chang 9 reservoir, a sandstone reservoir with high salinity, and ultra-low permeability. The synergistic effects between AOS and CHSB-35 as well as the functional mechanisms were clarified by conducting spontaneous imbibition tests. Experimental results show that when the total surfactant concentration locates in the range of 0.20–0.35 wt%, the oil-water IFT can be lowered to an ultra-low level at a salinity of 11.2 wt%. However, the spontaneous imbibition rate was found to be higher at a total surfactant concentration around 0.10–0.15 wt% with intermediate IFTs and contact angles around 35°. Our results indicated that once surfactant changes the rock wettability from an oil-wet state to a water-wet state, ultra-low IFTs are unnecessary or should be avoided in ultra-low permeability reservoirs. Spontaneous imbibition tests show that the oil production rate of AOS-CHSB-35 mixture is four times faster than simulated water and two times faster than each single surfactant.

Subpore‐Scale Trapping Mechanisms Following Imbibition: A Microfluidics Investigation of Surface Roughness Effects

AbstractSurface roughness is ubiquitous in subsurface formations due to weathering and diagenesis. Yet micromodel studies of porous media have not sufficiently addressed the impact of pore‐wall roughness on multiphase fluid displacement. We investigate the influence of pore‐wall roughness on capillary trapping by implementing surface roughness into glass micromodels and conducting imbibition experiments. Time‐lapse fluorescence microscopy, micromolding in capillaries, and scanning electron microscopy are used to examine flow behavior during spontaneous and forced imbibition experiments with capillary numbers between 10−6 and 10−4. It is found that surface roughness causes interface pinning and irregular displacement fronts within a single pore, promotes latent pore filling following imbibition, enhances snap‐offs, and contributes to interface relaxation. Furthermore, we verify a cooperative effect between corner flow and surface roughness that causes pore filling to occur at over 10 times the channel width ahead of the main bulk front. Consequently, a significant increase in trapped air saturation of up to 60% is observed, especially at lower capillary numbers and narrower pores. Effects of surface roughness also decrease the rate of spontaneous imbibition, which is slower than the prediction from Washburn's equation. Our results emphasize the importance of surface roughness in building conceptual models for capillary trapping when the ratio of surface roughness‐to‐pore size reaches a critical value of about 0.1. Above this critical threshold value, subpore‐scale trapping mechanisms contribute significantly to capillary trapping, which theoretical and numerical models should consider for accurate quantification of fluid‐transport processes.

Mechanism of the Wettability Impact on Surfactant Imbibition in Dodecane-Saturated Tight Sandstone

As a result of low porosity and low permeability in tight reservoirs, spontaneous imbibition plays an important role in oil recovery. While wettability has a crucial impact on the imbibition, the mechanism of the effect of wettability on imbibition is still unclear. In this study, we screened the surfactants with similar interfacial tension (IFT) at the same concentration to study the wettability properties, which will contribute to improve the oil recovery tight reservoir. Two betaine surfactants, lauramide propyl hydroxysulfonated betaine (LHSB) and cocamidopropyl betaine (CAB), were screened according to their IFT. Through spontaneous imbibition experiments, the recovery of LHSB (27.26%) was better than that of CAB (21.69%). The contact angle method and U.S. Bureau of Mines method were used to analyze the core wettability comprehensively. After LHSB treatment, the core wettability index turned to hydrophobic and the wettability index changed from −0.06 to −0.56. However, the wettability index did not change significantly after CAB treatment (−0.15). Further molecular simulations showed that, after the surface of the rock is modified by LHSB, the oil droplets spread gradually and the interface energy with the quartz was enhanced. In combination of the analysis of the ζ potential and adsorption measurement, LHSB is predicted to be adsorbed in a single-layer configuration, while CAB formed a double-layer configuration, which caused the difference in wettability. It can be speculated that, when the surfactant changes the pore surface of the tight sample toward hydrophobic, the oil-wet surface promotes the residual oil droplets to form a continuous phase and, at the same time, reduces flow resistance of the water phase, thereby increasing the spontaneous imbibition rate and the ultimate recovery. This study will help to understand the wettability impact on imbibition by the surfactant and contribute to the improvement of tight oil reservoir recovery.

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

Spontaneous imbibition in coal: Experimental and model analysis

The understanding of the mechanisms that govern spontaneous water imbibition in gas-water systems plays a significant role in operating the hydraulic fracturing and the development of unconventional gas reservoirs. The main purpose of this paper is addressing how the spontaneous imbibition in coal reservoir affects reservoir permeability, and what is the microscopic mechanism of water transport during this process. To solve this problem, air-water co-current imbibition experiments, contact-angle tests and permeability tests were carried out on eight coal plugs originated from three Chinese coalbed methane hot spots. Moreover, NMR spectrometer is introduced as a method for monitoring the volume of water imbibed in pores with different sizes. The results reveal that the water imbibition rate of bituminous coal follows microfracture > micropores > meso/macropores, whereas for anthracite, the imbibition rate is in the order of microfracure > meso/macroproes > micropores. Permeability damage ratio due to the spontaneous imbibition follows a positive exponential relationship with increasing contact angle. Considering the multi-scale pore system and complex pore tortuosity, we established a model to estimate the spontaneous imbibition rate, which agrees well with experimental results at the early stage of imbibition process when the capillary force is dominant. Finally, four successive stages of moisture migration during spontaneous imbibition and spontaneous evaporation were divided based on the movement of the NMR T2 peak. The implications from this work is important for better understanding the mechanism controlling fluid loss and gas production in unconventional reservoir, which is significant for optimizing the recovery program and minimizing reservoir damage.

Nuclear Magnetic Resonance Measurement of Oil and Water Distributions in Spontaneous Imbibition Process in Tight Oil Reservoirs

Spontaneous imbibition of water into tight oil reservoirs is considered an effective way to improve tight oil recovery. We have combined testing techniques such as nuclear magnetic resonance, mercury injection capillary pressure, and magnetic resonance imaging to reveal the distribution characteristics of oil and water during the spontaneous imbibition process of tight sandstone reservoir. The experimental results were used to describe the dynamic process of oil–water distribution at the microscopic scale. The water phase is absorbed into the core sample by micropores and mesopores under capillary forces that dry away the original oil phase into the hydraulically connected macropores. The oil phase entering the macropores will drive away the oil in place and expel the original oil from the macropores. The results of magnetic resonance imaging clearly show that the remaining oil accumulates in the central region of the core because a large amount of water is absorbed in the late stage of spontaneous imbibition, and the water in the pores gradually connects to form a “water shield” that blocks the flow of the oil phase. We propose the spontaneous imbibition pathway, which can effectively explain the internal mechanisms controlling the spontaneous imbibition rate. The surface of the core tends to form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is fast. The deep core does not easily form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is slow. This paper reveals the pore characteristics and distribution of oil and water during the spontaneous imbibition process, which is of significance for the efficient development of tight oil.

Recent advances in spontaneous imbibition with different boundary conditions

Spontaneous imbibition plays an important role in many practical processes, such as oil recovery, hydrology, and environmental engineering. The development in spontaneous imbibition goes fast in the past few years. In this paper, we focus on boundary conditions of spontaneous imbibition, which has important effects on spontaneous imbibition rate and efficiency. We introduce the fundamental physical mechanism of spontaneous imbibition with different boundary conditions by capillary model. Then, the studies of spontaneous imbibition in core scale are reviewed. The feature of spontaneous imbibition with different boundary conditions is discussed and the relative permeability for co- and counter-current imbibition is analyzed. The scaling of imbibition data with different boundary condition is also discussed by combination of experimental and numerical methods. At last, the analytical model of spontaneous imbibition is discussed. Cited as : Meng, Q., Cai, J. Recent advances in spontaneous imbibition with different boundary conditions. Capillarity, 2018, 1(3): 19-26, doi: 10.26804/capi.2018.03.01

Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in the Horn River Shale Gas Formation

Summary After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous-imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay's strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction-reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.

Enhancing Water Imbibition Rate and Oil Recovery by Carbonated Water in Carbonate and Sandstone Rocks

Spontaneous imbibition is regarded as an important mechanism of oil recovery by waterflood, particularly in heterogeneous or fractured reservoirs where direct displacement of oil by water is usually poor. It has been shown that carbonated water injection (CWI) can improve recovery from oil reservoirs. It has also been reported that the dissolution of CO2 in water can alter water/oil contact angle, which is a direct indication of the wettability of a crude oil/water/rock/system. In this work, our main objective was to experimentally investigate the potential of carbonated water for improving the rate of spontaneous imbibition of water and, hence, the oil recovery from systems where spontaneous imbibition of water would be important. To achieve this objective, a special high-pressure imbibition cell has been designed, and six spontaneous imbibition experiments have been performed on two different types of rocks (carbonate rock and sandstone) at a pressure of 2500 psi and room temperature. Crude oil was used...

Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations

The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al, 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belonging to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salt, surfactants, viscosifiers and sample orientation with regard to the bedding plane. The study also proposes and applies a simple methodology to scale up the laboratory data for field-scale predictions.The data show that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.

Fractal Prediction Model of Spontaneous Imbibition Rate

By utilizing fractal dimension as one of the parameters to characterize rocks, a mathematical model was derived to predict the production rate by spontaneous imbibition. This fractal production model predicts a power law relationship between spontaneous imbibition rate and time. Fractal dimension can be estimated from the fractal production model using the experimental data of spontaneous imbibition in porous media. The experimental data of recovery in gas-water-rock and oil–water–rock systems were used to test the fractal production model. The rocks (Berea sandstone, chalk, and The Geysers graywacke) in which the spontaneous water imbibition experiments were conducted had different permeabilities ranging from 0.5 to over 1000 md. The results demonstrate that the fractal production model can match the experimental data satisfactorily in the cases studied. The fractal dimension data inferred from the model match were approximately equal to the values of fractal dimension measured using a different technique (mercury-intrusion capillary pressure) in Berea sandstone.

Effect of shape factor, characteristic length, and boundary conditions on spontaneous imbibition

Spontaneous imbibition is vital for oil recovery in porous media, especially when considering fluid flow behavior in fractured reservoirs. Small-scale laboratory tests on reservoir rock samples show that spontaneous imbibition becomes crucial in estimating field behavior according to oil recovery by imbibition performance. This paper presents experimental work on oil recovery by spontaneous water imbibition on kerosene/brine/Berea systems. The main objectives of this study were to investigate the effect of shape factor (SF), characteristic length (CL), and boundary conditions (BC) on the rate of spontaneous imbibition, and improve oil production simulation by spontaneous imbibition from naturally fractured reservoirs using derived shape factors. General mathematical definitions for shape factor and characteristic length are typically derived using irregular geometric shapes, but this investigation utilized regular geometric shapes of core samples (i.e., cylindrical, square prism, and triangular prism) for simplicity. Experiments were conducted on different sizes of core samples with cylindrical shapes yielding the highest imbibition rates and triangular prisms the lowest imbibition rates. Characteristic length had an inverse effect on the rate of spontaneous imbibition within the same shape family of core samples. Boundary condition (BC) experiments were performed to investigate the effect of the boundary on the rate of spontaneous imbibition. The four different boundary conditions applied to the samples were (1) all faces open (AFO), (2) two ends closed (TEC), (3) two ends open (TEO), and (4) one end open (OEO) systems. BC experiments showed that an increase in total surface area open to imbibition promoted the rate of spontaneous imbibition. In this study, kerosene/brine/Berea systems showed that imbibition recovery rates increase with an increase in shape factor while decreasing in characteristic length specific to the same shape of core samples.

Influence of Fluid Viscosity On Mass Transfer Between Rock Matrix And Fractures

Abstract Scaling of spontaneous imbibition measurements is important to characterization of wetting properties and to modelling mass transfer between rock matrix and fractures. A scaling equation proposed by Mattax and Kyte(ll) has been widely applied to prediction of field-scale oil recovery from fractured reservoirs. The scaling equation involves many assumptions including identical core-sample shapes and viscosity ratios. In this paper, the effect of viscosity and viscosity ratio on rate of spontaneous imbibition is investigated. Imbibition data is reported for systems with two orders of magnitude variation in viscosity ratio. The results show, for systems of similar geometry, that the imbibition time is proportional to the square root of viscosity ratio. This observation combined with a new definition of characteristic length is used to define a modified scaling group which allows for differences in viscosity ratio, and the shapes and boundary conditions of the core samples. Introduction Spontaneous imbibition is a natural physical process driven by capillary forces whereby a nonwetting phase is displaced by a wetting phase from a porous medium(l). Examples of practical significance may be found in civil and chemical engineering, soil science, and numerous other areas. In petroleum engineering, imbibition is considered especially important in oil recovery from fractured reservoirs, where the rate of mass transfer between rock matrix and the associated fractures controls the oil production. However, much remains to be learned about the combined effect of imbibition, gravity, and both microscopic and macroscopic fluid distribution on oil recovery from fractured systems. Development of analytical functions or other computational schemes which account for mass transfer between rock matrix and fractures is of special importance to mathematical modelling of fractured reservoirs(2–6). Scaling of spontaneous imbibition phenomena is a critical step in this development. Provided that gravity effects can be safely neglected, capillary pressure is the driving force for spontaneous imbibition. Permeability and relative permeabilities in the two phase region of flow determine the rate of imbibition. Both capillary pressure and relative permeability are functions of saturation. Thus many factors enter into scaling of imbibition rates. The effect of fluid viscosity is of primary concern in this study. The effect of core sample shapes and boundary conditions will also be discussed. Imbibition in Tubes Most analyses of imbibition consider behaviour in cylindrical tubes. For a cylindrical tube of radius r, the Laplace equation gives the capillary pressure, Pc Equation 1–8 (available in full paper) Analysis of imbibition behaviour in cylindrical tubes provides guidance to studies of imbibition in porous media. However, direct applications of the conclusions drawn from the tube models to porous media should not be expected because spontaneous imbibition in porous media is usually dominated by countercurrent flow. Scaling of Imbibition in Porous Media From Equations (1) and (2), capillary pressure is inversely proportional to pore size, and permeability is proportional to the pore size squared. Thus, although capillary pressure decreases with increasing permeability [Equation (3)], the more permeable the porous media, the faster the imbibition rate [Equations (5) and (6)]. This conclusion was verified experimentally by Handy for water displacing air(8).

Wettability Changes Induced by Adsorption of Asphaltenes

Summary Asphaltene fractions were precipitated from two crude oils (designated as Prudhoe Bay '95 and Wyoming '95) by addition of n-hexane. A solution of 250 mg/L of asphaltenes in toluene was used to induce wettability changes in Berea sandstone cores by flow of asphaltene solutions through the core. Concentration of asphaltenes in the effluent was measured by ultraviolet (UV) absorbance. Wettability changes were assessed from measurements of the rate of spontaneous imbibition for changes in initial water saturation and brine composition. Water wetness decreased markedly with increase in ionic strength, increase in cation valency, and decrease in initial water saturation. For comparable conditions, changing the brine anions (chloride, nitrate, carbonate, and sulphate) caused lesser but fairly consistent changes in wetting. Wetting changes induced by asphaltenes from the Wyoming '95 crude oil were always higher than for those prepared from the Prudhoe Bay '95 crude oil. Water-flood recoveries for NaCl, CaCl2, and AlCl3 brines (0.09 M) increased with decrease in water wetness, with recovery reaching a maximum at an Amott wettability index of about 0.2. This result agrees with results reported previously for wettability changes induced by adsorption from crude oil.