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1.
Different functions describing matrix-fracture transfer were tested for counter-current capillary imbibition interaction.
The recovery curves obtained from capillary imbibition experiments were used to fit the transfer functions. The exponential
coefficients yielding the best fit to the experimental data were obtained and correlated to the effective parameters such
as viscosity, IFT, matrix length and diameter, matrix permeability and porosity, and wettability using multivariable regression
analysis. In order to obtain the recovery curves, experiments were conducted on Berea sandstone and Indiana limestone samples.
Cylindrical samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5,
5, and 10 cm in length. All sides were coated with epoxy except one end. More than fifty static imbibition experiments were
carried out on vertically and horizontally situated samples where the imbibition took place upward and lateral directions,
respectively. Brine–air, brine–kerosene, brine–mineral oil, and surfactant solution–mineral oil pairs were used as fluids.
For many matrix shape factors (especially longer and small diameter ones), dividing the recovery curve into three parts were
needed as the early, intermediate, and late times, which are typically distinguished by the time required for the imbibition
front to reach the closed boundary at the end of the core. Correlations among the exponential coefficients and rock/fluid
properties were developed. It was observed that different rock/fluid properties and transfer mechanisms (capillary imbibition
and gravity drainage) govern the process for each part. Hence, the analyses done in this study were useful not only for developing
explicit transfer functions but also identifying the physics of the counter-current imbibition recovery. 相似文献
2.
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. 相似文献
3.
Counter-current spontaneous imbibition (COUCSI) in porous media is driven by capillary forces. Capillary action results in
a high capillary imbibition pressure at the imbibition front and a low capillary drainage pressure at the outlet face. It
is the difference between these two pressures that draws in the wetting phase and pushes out the non-wetting phase. A technique
for measuring the capillary pressure at an imbibition front under restricted flow conditions has been developed and applied
to Berea sandstone with a range of permeabilities. In the experiments, brine was the wetting phase and refined oil was the
non-wetting phase. One end face of a sandstone core was butted to a short section of a finer-pored rock. The composite core
surface was then sealed, apart from the end face of the low-permeability segment. A connection to a pressure transducer was
set in the opposite end face of the core. Initially, the main core segment was filled with oil. In most cases, the finer-pored
segment was filled with brine. Imbibition was started by immersing the core in brine. The purpose of the finer-pored segment
was to prevent the escape of non-wetting phase from the open face. For some tests there was an initial period of co-current
spontaneous imbibition (COCSI) created by allowing production of non-wetting phase through an outlet tapping in the sealed
end face. The outlet was then connected to the transducer and the imbibition changed to COUCSI. There followed an increase
in the monitored end pressure to a maximum as fluid redistributed within the core. For the tests in which the fine-pored segments
were pre-saturated with brine, even without an initial period of co-current imbibition, limited invasion of the main core
segment by brine resulted in an asymptotic rise of the end pressure to a maximum as the imbibition front dispersed. To confirm
that the dispersing front did not reach the dead end of the core, the distance of advance of the wetting liquid was detected
by a series of electrodes. The maximum value of the end pressure provides an estimate of the capillary pressure at an imbibition
front for COUCSI. The maximum capillary pressure generated by the invading fluids ranged from 6.6 kPa to 42 kPa for sandstone
with permeabilities between 1.050 (μm) 2 and 0.06 (μm) 2. 相似文献
4.
Laboratory experiments have been carried out to study the influence of high-frequency (20 kHz) acoustic waves on the flow
of brine through a core sample of reservoir rock containing residual oil. The experiments were done at reservoir conditions
with respect to temperature and pressure. Below a certain critical level of the acoustic intensity the relative permeability
for the flow of brine is independent of the acoustic intensity and there is no flow of oil out of the core. However, above
the critical level the relative permeability for the brine flow jumps to a significantly higher value and oil starts to flow
from the core. These experimental results are in agreement with a theoretical model proposed by Graham and Higdon [Oscillatory
flow of droplets in capillary tubes Part 2 Constricted tubes. J. Fluid Mech. 425, 55–77 (2000)]. The model is based on a microscopic picture of oil drops (surrounded by flowing brine) being trapped inside
the pores of the reservoir rock. Under the influence of ultrasonic waves the oil drops oscillate and can escape from their
pores above a critical level of the acoustic intensity. 相似文献
5.
The ultimate driving force for counter-current spontaneous imbibition of a fluid into a porous material is the capillary pressure developed under dynamic conditions at the imbibition front. This is a difficult variable to measure. We report experiments using restricted counter-current spontaneous imbibition to find the maximum capillary pressure developed during imbibition of a light mineral oil (and brine) into initially air-filled sandstone core samples with one end-face open. The production of air from the core was prevented by covering its open face with a low permeability core segment set against the main test segment. The location of the imbibition front and the pressure resulting from compression of air ahead of the imbibition front were monitored. In some cases, in order to achieve stabilized gas pressures with the front still advancing through the core, the air in the core was compressed at the start of the imbibition test. The subsequently measured stabilized air pressures dropped only slightly as imbibition slowed. The measured pressures are directly related to the effective capillary pressures that drive spontaneous imbibition. After spontaneous imbibition ceased, the pressure was released by flow of air through the sealed end of the core and further spontaneous imbibition occurred in co-current mode. Comparison of the stabilized pressures with previously published oil/brine imbibition results showed close agreement after compensation for the difference in interfacial tension. 相似文献
6.
This article describes a semi-analytical model for two-phase immiscible flow in porous media. The model incorporates the effect
of capillary pressure gradient on fluid displacement. It also includes a correction to the capillarity-free Buckley–Leverett
saturation profile for the stabilized-zone around the displacement front and the end-effects near the core outlet. The model
is valid for both drainage and imbibition oil–water displacements in porous media with different wettability conditions. A
stepwise procedure is presented to derive relative permeabilities from coreflood displacements using the proposed semi-analytical
model. The procedure can be utilized for both before and after breakthrough data and hence is capable to generate a continuous
relative permeability curve unlike other analytical/semi-analytical approaches. The model predictions are compared with numerical
simulations and laboratory experiments. The comparison shows that the model predictions for drainage process agree well with
the numerical simulations for different capillary numbers, whereas there is mismatch between the relative permeability derived
using the Johnson–Bossler–Naumann (JBN) method and the simulations. The coreflood experiments carried out on a Berea sandstone
core suggest that the proposed model works better than the JBN method for a drainage process in strongly wet rocks. Both methods
give similar results for imbibition processes. 相似文献
7.
Surfactant loss due to adsorption on the porous medium of an oil reservoir is a major concern in enhanced oil recovery. Surfactant
loss due to adsorption on the reservoir rock weakens the effectiveness of the injected surfactant in reducing oil–water interfacial
tension (IFT) and making the process uneconomical. In this study, surfactant concentrations in the effluent of the corefloods
and oil–water IFT were determined under different injection strategies. It was found that in an extended waterflood following
a surfactant slug injection, surfactant desorbed in the water phase. This desorbed surfactant lasted for a long period of
the waterflood. The concentration of the desorbed surfactant in the extended waterflood was very low but still an ultralow
IFT was obtained by using a suitable alkali. Coreflood results show an additional recovery of 13.3% of the initial oil in
place was obtained by the desorbed surfactant and alkali. Results indicate that by utilizing the desorbed surfactant during
the extended waterflood operation the efficiency and economics of the surfactant flood can be improved significantly. 相似文献
8.
Including gravity and wettability effects, a full analytical solution for the frontal flow period for 1D counter-current spontaneous
imbibition of a wetting phase into a porous medium saturated initially with non-wetting phase at initial wetting phase saturation
is presented. The analytical solution applicable for liquid–liquid and liquid–gas systems is essentially valid for the cases
when the gravity forces are relatively large and before the wetting phase front hits the no-flow boundary in the capillary-dominated
regime. The new analytical solution free of any arbitrary parameters can also be utilized for predicting non-wetting phase
recovery by spontaneous imbibition. In addition, a new dimensionless time equation for predicting dimensionless distances
travelled by the wetting phase front versus dimensionless time is presented. Dimensionless distance travelled by the waterfront
versus time was calculated varying the non-wetting phase viscosity between 1 and 100 mPas. The new dimensionless time expression
was able to perfectly scale all these calculated dimensionless distance versus time responses into one single curve confirming
the ability for the new scaling equation to properly account for variations in non-wetting phase viscosities. The dimensionless
stabilization time, defined as the time at which the capillary forces are balanced by the gravity forces, was calculated to
be approximately 0.6. The full analytical solution was finally used to derive a new transfer function with application to
dual-porosity simulation. 相似文献
9.
Water imbibition during the waterflooding process of oil production only sweeps part of the oil present. After water disrupts
the oil continuity, most oil blobs are trapped in porous rock by capillary forces. Developing an efficient waterflooding scheme
is a difficult task; therefore, an understanding of the oil trapping mechanism in porous rock is necessary from a microscopic
viewpoint. The development of microfocused X-ray CT scanner technology enables the three-dimensional visualization of multiphase
phenomena in a pore-scale. We scanned packed glass beads filled with a nonwetting phase (NWP) and injected wetting phase (WP)
in upward and downward injections to determine the microscopic mechanism of immiscible displacement in porous media and the
effects of buoyancy forces. We observed the imbibition phenomena for small capillary numbers to understand the spontaneous
imbibition mechanism in oil recovery. This study is one of the first attempts to use a microfocused X-ray CT scanner for observing
the imbibition and trapping mechanisms. The trapping mechanism in spontaneous imbibition is determined by the pore configuration
causing imbibition speed differences in each channel; these differences can disrupt the oil continuity. Gravity plays an important
role in spontaneous imbibition. In upward injection, the WP flows evenly and oil is trapped in single or small clusters of
pores. In downward injection, the fingering phenomena determine the amount of trapped oil, which is usually in a network scale.
Water breakthrough causes dramatic decrease in the oil extraction rate, resulting in lower oil production efficiency. 相似文献
10.
Accurate models of multiphase flow in porous media and predictions of oil recovery require a thorough understanding of the
physics of fluid flow. Current simulators assume, generally, that local capillary equilibrium is reached instantaneously during
any flow mode. Consequently, capillary pressure and relative permeability curves are functions solely of water saturation.
In the case of imbibition, the assumption of instantaneous local capillary equilibrium allows the balance equations to be
cast in the form of a self-similar, diffusion-like problem. Li et al. [ J. Petrol. Sci. Eng. 39(3) (2003), 309–326] analyzed oil production data from spontaneous countercurrent imbibition experiments and inferred that
they observed the self-similar behavior expected from the mathematical equations. Others (Barenblatt et al. [ Soc. Petrol. Eng. J. 8(4) (2002), 409–416]; Silin and Patzek [ Transport in Porous Media 54 (2004), 297–322]) assert that local equilibirum is not reached in porous media during spontaneous imbibition and nonequilibirium
effects should be taken into account. Simulations and definitive experiments are conducted at core scale in this work to reveal
unequivocally nonequilbirium effects. Experimental in-situ saturation data obtained with a computerized tomography scanner
illustrate significant deviation from the numerical local-equilibrium based results. The data indicates: (i) capillary imbibition
is an inherently nonequilibrium process and (ii) the traditional, multi-phase, reservoir simulation equations may not well
represent the true physics of the process. 相似文献
11.
In the first part of this work (Dong et al., Transport Porous Media, 59, 1–18, 2005), an interacting capillary bundle model was developed for analysing immiscible displacement processes in
porous media. In this paper, the second part of the work, the model is applied to analyse the fluid dynamics of immiscible
displacements. The analysis includes: (1) free spontaneous imbibition, (2) the effects of injection rate and oil–water viscosity
ratio on the displacement interface profile, and (3) the effect of oil–water viscosity ratio on the relative permeability
curves. Analysis of a non-interacting tube bundle model is also presented for comparison. Because pressure equilibration between
the capillaries is stipulated in the interacting capillary model, it is able to reproduce the behaviour of immiscible displacement
observed in porous media which cannot be modelled by using non-interacting tube bundle models. 相似文献
12.
Recovery of oil from the blocks of an initially oil-wet, naturally fractured, reservoir as a result of counter-current flow
following introduction of aqueous wettability-altering surfactant into the fracture system is considered, as an example of
a practical process in which phenomena acting at the single pore-scale are vital to the economic displacement of oil at the
macroscopic scale. A Darcy model for the process is set up, and solutions computed illustrating the recovery rate controlling
role of the bulk diffusion of surfactant. A central ingredient of this model is the capillary pressure relation, linking the
local values of the pressure difference between the oleic and aqueous phases, the aqueous saturation and the surfactant concentration.
Using ideas from single capillary models of oil displacement from oil-wet tubes by wettability-altering surfactant, we speculate
that the use of a capillary pressure function, with dependences as assumed, may not adequately represent the Darcy scale consequences
of processes acting at the single pore-scale. Multi-scale simulation, resolving both sub-pore and multi-pore flow processes
may be necessary to resolve this point. Some general comments are made concerning the issues faced when modelling complex
displacement processes in porous media starting from the pore-scale and working upwards. 相似文献
13.
Counter-current imbibition occurs when brine spontaneously displaces oil from a very strongly water-wet rock. Experiments
are usually carried out on cylindrical core plugs which have all of their faces open, mainly because this is easiest to do
and also because it appears to give the most reproducible results. The flow patterns are complex, but a reasonable approximation
can be obtained by assuming piston-like advance of fronts from the radial outer face and both flat ends. This separates the
flow pattern into two types: linear imbibition into cones and radial imbibition into the surrounding toroid ring. Production
versus time curves have been calculated for cylinders of varying aspect ratios and other core shapes. The analytical results
confirm the experimental observation that sample shape does not have much effect on the shape of the production versus time
curves. Bearing in mind the inherent variability of experimental results for individual core samples, the differences would
be difficult to detect in experiments. The time for imbibition to be completed scales as the characteristic length. The function
given by Ma et al. (J Pet Sci Eng 18:165–178, 1997) requires only a small correction factor for agreement with the analytical
result. The present analysis makes straightforward the comparison of results from the complex flow condition of all-faces-open
imbibition with results from linear and radial experiments. A comparison is made with published results. 相似文献
14.
In the present study the velocity profiles and the instability at the interface of a two phase water-oil fluid were investigated.
The main aim of the research project was to investigate the instability mechanisms that can cause the failure of an oil spill
barrier. Such mechanisms have been studied before for a vast variety of conditions (Wicks in Fluid dynamics of floating oil
containment by mechanical barriers in the presence of water currents. In: Conference on prevention and control of oil spills,
pp 55–106, 1969; Fannelop in Appl Ocean Res 5(2):80–92, 1983; Lee and Kang in Spill Sci Technol Bull 4(4):257–266, 1997; Fang and Johnston in J Waterway Port Coast Ocean Eng ASCE 127(4):234–239, 2001; among others). Although the velocity field in the region behind the barrier can influence the failure significantly, it
had not been measured and analyzed precisely. In the present study the velocity profiles in the vicinity of different barriers
were studied. To undertake the experiments, an oil layer was contained over the surface of flowing water by means of a barrier
in a laboratory flume. The ultrasonic velocity profiler method was used to measure velocity profiles in each phase and to
detect the oil–water interface. The effect of the barrier geometry on velocity profiles was studied. It was determined that
the contained oil slick, although similar to a gravity current, can not be considered as a gravity current. The oil–water
interface, derived from ultrasonic echo, was used to find the velocity profile in each fluid. Finally it was shown that the
fluctuations at the rearward side of the oil slick head are due to Kelvin–Helmholtz instabilities. 相似文献
15.
A parametric two-phase, oil–water relative permeability/capillary pressure model for petroleum engineering and environmental applications is developed for porous media in which the smaller pores are strongly water-wet and the larger pores tend to be intermediate- or oil-wet. A saturation index, which can vary from 0 to 1, is used to distinguish those pores that are strongly water-wet from those that have intermediate- or oil-wet characteristics. The capillary pressure submodel is capable of describing main-drainage and hysteretic saturation-path saturations for positive and negative oil–water capillary pressures. At high oil–water capillary pressures, an asymptote is approached as the water saturation approaches the residual water saturation. At low oil–water capillary pressures (i.e. negative), another asymptote is approached as the oil saturation approaches the residual oil saturation. Hysteresis in capillary pressure relations, including water entrapment, is modeled. Relative permeabilities are predicted using parameters that describe main-drainage capillary pressure relations and accounting for how water and oil are distributed throughout the pore spaces of a porous medium with mixed wettability. The capillary pressure submodel is tested against published experimental data, and an example of how to use the relative permeability/capillary pressure model for a hypothetical saturation-path scenario involving several imbibition and drainage paths is given. Features of the model are also explained. Results suggest that the proposed model is capable of predicting relative permeability/capillary pressure characteristics of porous media mixed wettability. 相似文献
16.
Water chemistry has been shown experimentally to affect the stability of water films and the sorption of organic oil components on mineral surfaces. When oil is displaced by water, water chemistry has been shown to impact oil recovery. At least two mechanisms could account for these effects, the water chemistry could change the charge on the rock surface and affect the rock wettability, and/or changes in the water chemistry could dissolve rock minerals and affect the rock wettability. The explanations need not be the same for oil displacement of water as for water imbibition and displacement of oil. This article investigates how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock similar to the Stevns Klint chalk by constructing and applying a chemical model that couples bulk aqueous and surface chemistry and also addresses mineral precipitation and dissolution. We perform calculations for seawater and formation water for temperatures between 70 and 130°C. The model we construct accurately predicts the surface potential of calcite and the adsorption of sulfate ions from the pore water. The surface potential changes are not able to explain the observed changes in oil recovery caused by changes in pore water chemistry or temperature. On the other hand, chemical dissolution of calcite has the experimentally observed chemical and temperature dependence and could account for the experimental recovery systematics. Based on this preliminary analysis, we conclude that although surface potential may explain some aspects of the existing spontaneous imbibitions data set, mineral dissolution appears to be the controlling factor. 相似文献
17.
Additive manufacturing technology, or 3D printing, with silica sand has enabled the manufacture of porous rock analogues for the use in experimental studies of geomechanical properties of reservoir rocks. The accurate modelling of the fluid flow phenomena within a reservoir and improving the performance of hydrocarbon recovery require an understanding of physical and chemical interactions of the reservoir fluids and the rock matrix. Therefore, for the 3D printed samples to serve as rock analogues, flow properties have to be equivalent to the petrophysical properties of their natural counterparts, such as Berea sandstone. In this study, sandstones that were 3D printed with silica sand and Poly-Furfuryl alcohol (PFA) binder, were used to investigate interactions between porous media with different fluids. Wettability preference of 3D printed samples was characterized through contact angle measurements, as well as co-current and counter-current spontaneous imbibition experiments. Results indicated that 3D printed sandstones had mixed-wet characteristics due to the high preference of silica grains for polar fluids and the affinity PFA binder to the oleic phase. Printing configurations including binder saturation were found to greatly influence the wettability preference of the 3D printed analogue rocks as higher PFA concentrations resulted in more strongly oil-wet preferences. Efforts to optimize the printing process and challenges to control the wettability preferences of the 3D printed samples are also highlighted. 相似文献
18.
We have developed a mathematical model describing the process of microbial enhanced oil recovery (MEOR). The one-dimensional
isothermal model comprises displacement of oil by water containing bacteria and substrate for their feeding. The bacterial
products are both bacteria and metabolites. In the context of MEOR modeling, a novel approach is partitioning of metabolites
between the oil and the water phases. The partitioning is determined by a distribution coefficient. The transfer part of the
metabolite to oil phase is equivalent to its ”disappearance,” so that the total effect from of metabolite in the water phase
is reduced. The metabolite produced is surfactant reducing oil–water interfacial tension, which results in oil mobilization.
The reduction of interfacial tension is implemented through relative permeability curve modifications primarily by lowering
residual oil saturation. The characteristics for the water phase saturation profiles and the oil recovery curves are elucidated.
However, the effect from the surfactant is not necessarily restricted to influence only interfacial tension, but it can also
be an approach for changing, e.g., wettability. The distribution coefficient determines the time lag, until residual oil mobilization
is initialized. It has also been found that the final recovery depends on the distance from the inlet before the surfactant
effect takes place. The surfactant effect position is sensitive to changes in maximum growth rate, and injection concentrations
of bacteria and substrate, thus determining the final recovery. Different methods for incorporating surfactant-induced reduction
of interfacial tension into models are investigated. We have suggested one method, where several parameters can be estimated
in order to obtain a better fit with experimental data. For all the methods, the incremental recovery is very similar, only
coming from small differences in water phase saturation profiles. Overall, a significant incremental oil recovery can be achieved,
when the sensitive parameters in the context of MEOR are carefully dealt with. 相似文献
19.
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. 相似文献
20.
In this article, the numerical simulations for one-dimensional three-phase flows in fractured porous media are implemented.
The simulation results show that oil displacement in matrix is dominated by oil–water capillary pressure only under certain
conditions. When conditions are changed to decrease the amount of water entering into the fractured media from the boundary
of the flow field, water in fracture may be vaporized to superheated steam. In these cases, the appearance of superheated
steam in fracture rather than in matrix will decrease the fracture pressure and generate the pressure difference between matrix
and fracture, which results in oil flowing from matrix to fracture. Assuming that oil is wetting to steam, the matrix steam–oil
capillary pressure will decrease the matrix oil-phase pressure as the matrix steam saturation increases. After the steam–oil
capillary pressure finally exceeds the pressure difference due to the appearance of superheated steam in fracture, the oil
displacement in matrix will stop. It is also shown that variations of the water relative permeability curve in matrix do not
result in different mechanisms for oil displacement in matrix. The simulation results suggest that the amount of liquid water
supply from the boundary of flow field fundamentally influence the mechanisms for oil displacement in matrix. 相似文献
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