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1.
We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms
during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under
conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate
that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG
injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the
main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by
a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the
oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible
SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection.
Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows
that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil
recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous
and high-rate gas injection is not possible (e.g. due to supply constraint). 相似文献
2.
Performance of a polymer flood process requires the knowledge of rheological behavior of the polymer solution and reservoir
properties such as rock wettability. To provide a better understanding of effects of polymer chemistry and wettability on
the performance of a polymer flood process, a comprehensive experimental study was conducted using a two-dimensional glass
micromodel. A series of water and polymer flood processes were carried out at different polymer molecular weights, degrees
of polymer hydrolysis, and polymer concentrations in both water-wet and oil-wet systems. Image processing technique was applied
to analyze and compare microscopic and macroscopic displacement behaviors of polymer solution in each experiment. From micro-scale
observations, the configuration of connate water film, polymer solution trapping, flow of continuous and discontinuous strings
of polymer solution, piston-type displacement of oil, snap-off of polymer solution, distorted flow of polymer solution, emulsion
formation, and microscopic pore-to-pore sweep of oil phase were observed and analyzed in the strongly oil-wet and water-wet
media. Rheological experiments showed that a higher polymer molecular weight, degree of hydrolysis, and concentration result
in a higher apparent viscosity for polymer solution and lower oil–polymer viscosity ratio. It is also shown that these parameters
have different impacts on the oil recovery in different wettabilities. Moreover, a water-wet medium generally had higher recovery
in contrast with an oil-wet medium. This experimental study illustrates the successful application of glass micromodel techniques
for studying enhanced oil recovery (EOR) processes in five-spot pattern and provides a useful reference for understanding
the displacement behaviors in a typical polymer flood process. 相似文献
3.
Saber Mohammadi Mohsen Masihi Mohammad Hossein Ghazanfari 《Transport in Porous Media》2012,91(3):973-998
Many heavy oil reservoirs contain discontinuous shales which act as barriers or baffles to flow. However, there is a lack
of fundamental understanding about how the shale geometrical characteristics affect the reservoir performance, especially
during polymer flooding of heavy oils. In this study, a series of polymer injection processes have been performed on five-spot
glass micromodels with different shale geometrical characteristics that are initially saturated with the heavy oil. The available
geological characteristics from one of the Iranian oilfields were considered for the construction of the flow patterns by
using a controlled-laser technology. Oil recoveries as a function of pore volumes of injected fluid were determined from analysis
of continuously recorded images during the experiments. We observed a clear bypassing of displacing fluid which results in
premature breakthrough of injected fluid due to the shale streaks. Moreover, the results showed a decrease of oil recovery
when shales’ orientation, length, spacing, distance of the shale from production well, and density of shales increased. In
contrast, an increase of shale discontinuity or distance of the shale streak from the injection well increased oil recovery.
The obtained experimental data have also been used for developing and validating a numerical model where good matching performance
has been observed between our experimental observations and simulation results. Finally, the role of connate water saturation
during polymer flooding in systems containing flow barriers has been illustrated using pore level visualizations. The microscopic
observations confirmed that besides the effect of shale streaks as heterogeneity in porous medium, when connate water is present,
the trapped water demonstrates another source of disturbance and causes additional perturbations to the displacement interface
leading to more irregular fingering patterns especially behind the shale streaks and also causes a reduction of ultimate oil
recovery. This study reveals the application of glass micromodel experiments for studying the effects of barriers on oil recovery
and flow patterns during EOR processes and also may provide a set of benchmark data for recovery of oil by immiscible polymer
flood around discontinuous shales. 相似文献
4.
In this study, the main recovery mechanisms behind oil/water/gas interactions during the water-alternating-gas (WAG) injection process, in a network of matrix/fracture, were fundamentally investigated. A visual micromodel was utilized to provide insights into the potential applications of WAG process in fractured oil-wet media as well as the possibility of observing microscopic displacement behavior of fluids in the model. The model was made of an oil-wet facture/matrix network system, comprised of four matrix blocks surrounded with fractures. Different WAG injection scenarios, such as slug arrangements and the effects of fluid injection rates on oil recovery were studied. A new equation representing the capillary number, considering the fracture viscous force and matrix capillary force, was developed to make the experimental results more similar to a real field. In general, WAG tests performed in the fractured model showed a higher oil recovery factor compared with the results of gas and water injection tests at their optimum rates. The results showed that the presence of an oil film, in all cases, was the main reason for co-current drainage and double displacement of oil under applied driving forces. Furthermore, the formation of oil liquid bridges improved the recovery efficiency, which was greatly influenced by the size of fracture connecting the two matrix blocks; these connecting paths were more stable when there was initial water remaining in the media. Analyzing different recovery curves and microscopic view of the three phases in the transparent model showed that starting an injection mode with gas (followed by repeated small slugs of water and gas), could considerably improve oil recovery by pushing water into the matrix zone and increasing the total sweep efficiency. 相似文献
5.
Ali Maghzi Ali Mohebbi Riyaz Kharrat Mohammad Hossein Ghazanfari 《Transport in Porous Media》2011,87(3):653-664
It is well known that the oil recovery is affected by wettability of porous medium; however, the role of nanoparticles on
wettability alteration of medium surfaces has remained a topic of debate in the literature. Furthermore, there is a little
information of the way dispersed silica nanoparticles affect the oil recovery efficiency during polymer flooding, especially,
when heavy oil is used. In this study, a series of injection experiments were performed in a five-spot glass micromodel after
saturation with the heavy oil. Polyacrylamide solution and dispersed silica nanoparticles in polyacrylamide (DSNP) solution
were used as injected fluids. The oil recovery as well as fluid distribution in the pores and throats was measured with analysis
of continuously provided pictures during the experiments. Sessile drop method was used for measuring the contact angles of
the glass surface at different states of wettability after coating by heavy oil, distilled water, dispersed silica nanoparticles
in water (DSNW), polyacrylamide solution, and DSNP solution. The results showed that the silica nanoparticles caused enhanced
oil recovery during polymer flooding by a factor of 10%. The distribution of DSNP solution during flooding tests in pores
and throats showed strong water-wetting of the medium after flooding with this solution. The results of sessile drop experiments
showed that coating with heavy oil, could make an oil-wet surface. Coating with distilled water and polymer solution could
partially alter the wettability of surface to water-wet and coating with DSNW and DSNP could make a strongly water-wet surface. 相似文献
6.
Enhanced oil recovery (EOR) by alkaline flooding for conventional oils has been extensively studied. For heavy oils, investigations are very limited due to the unfavorable mobility ratio between the water and oil phases. In this study, the displacement mechanisms of alkaline flooding for heavy oil EOR are investigated by conducting flood tests in a micromodel. Two different displacement mechanisms are observed for enhancing heavy oil recovery. One is in situ water-in-oil (W/O) emulsion formation and partial wettability alteration. The W/O emulsion formed during the injection of alkaline solution plugs high permeability water channels, and pore walls are altered to become partially oil-wetted, leading to an improvement in sweep efficiency and high tertiary oil recovery. The other mechanism is the formation of an oil-in-water (O/W) emulsion. Heavy oil is dispersed into the water phase by injecting an alkaline solution containing a very dilute surfactant. The oil is then entrained in the water phase and flows out of the model with the water phase. 相似文献
7.
Experiments were performed to study the diffusion process between matrix and fracture while there is flow in fracture. 2-inch
diameter and 6-inch length Berea sandstone and Indiana limestone samples were cut cylindrically. An artificial fracture spanning
between injection and production ends was created and the sample was coated with heat-shrinkable teflon tube. A miscible solvent
(heptane) was injected from one end of the core saturated with oil at a constant rate. The effects of (a) oil type (mineral
oil and kerosene), (b) injection rates, (c) orientation of the core, (d) matrix wettability, (e) core type (a sandstone and
a limestone), and (f) amount of water in matrix on the oil recovery performance were examined. The process efficiency in terms
of the time required for the recovery as well as the amount of solvent injected was also investigated. It is expected that
the experimental results will be useful in deriving the matrix–fracture transfer function by diffusion that is controlled
by the flow rate, matrix and fluid properties. 相似文献
8.
9.
Pavel Z. S. Paz Thomas H. Hollmann Efe Kermen Grigori Chapiro Evert Slob Pacelli L. J. Zitha 《Transport in Porous Media》2017,119(1):57-75
We report a study of heavy oil recovery by combined water flooding and electromagnetic (EM) heating at a frequency of 2.45 GHz used in domestic microwave ovens. A mathematical model describing this process was developed. Model equations were solved, and the solution is presented in an integral form for the one-dimensional case. Experiments consisting of water injection into Bentheimer sandstone cores, either fully water saturated or containing a model heavy oil, were also conducted, with and without EM heating. Model prediction was found to be in rather good agreement with experiments. EM energy was efficiently absorbed by water and, under dynamic conditions, was transported deep into the porous medium. The amount of EM energy absorbed increases with water saturation. Oil recovery by water flooding combined with EM heating was up to \(37.0\%\) larger than for cold water flooding. These observations indicate that EM heating induces an overall improvement in the mobility ratio between the displacing water and the displaced heavy oil. 相似文献
10.
Low Tension Polymer Flooding or Polymer Assisted Dilute Surfactant Flooding is generally deployed as a method to produce additional
oil trapped in oil reservoirs after waterflooding. Fundamental study of microscopic mechanisms and pore-level phenomena in
Polymer Assisted Dilute Surfactant Flooding needs more investigation. Of particular concern and interest is to probe into
and document the effect of pore morphology and structure on microscopic phenomena occurring at pore level. No previous works
on the effect of pore morphology in Polymer Assisted Dilute Surfactant Flooding has been reported in the literature. In this
study, one-quarter five-spot glass micromodels were deployed to examine the effect of porous media morphology and structure
on microscopic mechanisms as well as macroscopic behavior of Polymer Assisted Dilute Surfactant Flooding. Four types of pore
morphologies were employed to study this factor. Results show that the pore geometric properties in a porous medium will dictate
the degree of displacement front instability, capillary imbalance, viscous fingering, wetting characteristics and its distribution, and finally magnitude of ultimate oil recovery. We also found that the formation of flow scheme is dramatically influenced by the pre-designed injection scheme. 相似文献
11.
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
12.
Y. Li 《Transport in Porous Media》2011,90(2):333-362
Low salinity water injections for oil recovery have shown seemingly promising results in the case of clay-bearing sandstones
saturated with asphaltic crude oil. Reported data showed that low salinity water injection could provide up to 20% pore volume
(PV) of additional oil recovery for core samples and up to 25% PV for reservoirs in near wellbore regions, compared with brine
injection at the same Darcy velocity. The question remains as to whether this additional recovery is also attainable in reservoirs.
The answer requires a thorough understanding of oil recovery mechanism of low salinity water injections. Numerous hypotheses
have been proposed to explain the increased oil recovery using low salinity water, including migration of detached mixed-wet
clay particles with absorbed residual oil drops, wettability alteration toward increased water-wetness, and emulsion formation.
However, many later reports showed that a higher oil recovery associated with low salinity water injection at the common laboratory
flow velocity was neither necessarily accompanied by migration of clay particles, nor necessarily accompanied by emulsion.
Moreover, increased water-wetness has been shown to cause the reduction of oil recovery. The present study is based on both
experimental and theoretical analyses. Our study reveals that the increased oil recovery is only related to the reduction
of water permeability due to physical plugging of the porous network by swelling clay aggregates or migrating clay particles
and crystals. At a fixed apparent flow velocity, the value of negative pressure gradient along the flow path increases as
the water permeability decreases. Some oil drops and blobs can be mobilized under the increased negative pressure gradient
and contribute to the additional oil recovery. Based on the revealed mechanism, we conclude that low salinity water injection
cannot be superior to brine injection in any clay-bearing sandstone reservoir at the maximum permitted injection pressure.
Through our study of low salinity water injection, the theory of tertiary oil recovery has been notably improved. 相似文献
13.
Carbon dioxide (CO2) injection is a well-established method for increasing recovery from oil reservoirs. However, poor sweep efficiency has been
reported in many CO2 injection projects due to the high mobility contrast between CO2 and oil and water. Various injection strategies including gravity stable, WAG and SWAG have been suggested and, to some extent,
applied in the field to alleviate this problem. An alternative injection strategy is carbonated water injection (CWI). In
CWI, CO2 is delivered to a much larger part of the reservoir compared to direct CO2 injection due to a much improved sweep efficiency. In CWI, CO2 is used efficiently and much less CO2 is required compared to conventional CO2 flooding, and hence the process is particularly attractive for reservoirs with limited access to large quantities of CO2 (offshore reservoirs or reservoirs far away from inexpensive natural CO2 resources). This article describes the results of a pore-scale study of the process of CWI by performing high-pressure visualisation
flow experiments. The experimental results show that CWI, compared to unadulterated (conventional) water injection, improves
oil recovery as both a secondary (before water flooding) and a tertiary (after water flooding) recovery method. The mechanisms
of oil recovery by CWI include oil swelling, coalescence of the isolated oil ganglia and flow diversion due to flow restriction
in some of the pores as a result of oil swelling and the resultant fluid redistribution. In this article the potential benefit
of a subsequent depressurisation period on oil recovery after the CWI period is also investigated. 相似文献
14.
A mathematical model of the time-dependent two-dimensional flow of a two-phase multicomponent incompressible fluid through a porous medium is proposed for the micellar-polymeric flooding of oil reservoirs. The oil displacement process is investigated numerically using an implicit first-order-accurate upwind scheme with integration over the nonlinearity on a uniform grid under the assumption of plane-radial motion in the neighborhood of the wells. The influence of the nonuniform permeability of the porous medium on the efficiency of the proposed method of improving oil recovery is analyzed using a five-point slug injection scheme.Translated from Izvestiya Rossiiskoi Academii Nauk, Mekhanika Zhidkosti i Gaza, No. 6, 2004, pp. 124–132. Original Russian Text Copyright © 2004 by Inogamov and Khabeev. 相似文献
15.
The significant reduction in heavy oil viscosity when mixed with \(\hbox {CO}_{2}\) is well documented. However, for \(\hbox {CO}_{2}\) injection to be an efficient method for improving heavy oil recovery, other mechanisms are required to improve the mobility ratio between the \(\hbox {CO}_{2}\) front and the resident heavy oil. In situ generation of \(\hbox {CO}_{2}\)-foam can improve \(\hbox {CO}_{2}\) injection performance by (a) increasing the effective viscosity of \(\hbox {CO}_{2}\) in the reservoir and (b) increasing the contact area between the heavy oil and injected \(\hbox {CO}_{2}\) and hence improving \(\hbox {CO}_{2}\) dissolution rate. However, in situ generation of stable \(\hbox {CO}_{2}\)-foam capable of travelling from the injection well to the production well is hard to achieve. We have previously published the results of a series of foam stability experiments using alkali and in the presence of heavy crude oil (Farzaneh and Sohrabi 2015). The results showed that stability of \(\hbox {CO}_{2}\)-foam decreased by addition of NaOH, while it increased by addition of \(\hbox {Na}_{2}\hbox {CO}_{3}\). However, the highest increase in \(\hbox {CO}_{2}\)-foam stability was achieved by adding borate to the surfactant solution. Borate is a mild alkaline with an excellent pH buffering ability. The previous study was performed in a foam column in the absence of a porous medium. In this paper, we present the results of a new series of experiments carried out in a high-pressure glass micromodel to visually investigate the performance of borate–surfactant \(\hbox {CO}_{2}\)-foam injection in an extra-heavy crude oil in a transparent porous medium. In the first part of the paper, the pore-scale interactions of \(\hbox {CO}_{2}\)-foam and extra-heavy oil and the mechanisms of oil displacement and hence oil recovery are presented through image analysis of micromodel images. The results show that very high oil recovery was achieved by co-injection of the borate–surfactant solution with \(\hbox {CO}_{2}\), due to in-situ formation of stable foam. Dissolution of \(\hbox {CO}_{2}\) in heavy oil resulted in significant reduction in its viscosity. \(\hbox {CO}_{2}\)-foam significantly increased the contact area between the oil and \(\hbox {CO}_{2}\) significantly and thus the efficiency of the process. The synergy effect between the borate and surfactant resulted in (1) alteration of the wettability of the porous medium towards water wet and (2) significant reduction of the oil–water IFT. As a result, a bank of oil-in-water (O/W) emulsion was formed in the porous medium and moved ahead of the \(\hbox {CO}_{2}\)-foam front. The in-situ generated O/W emulsion has a much lower viscosity than the original oil and plays a major role in the observed additional oil recovery in the range of performed experiments. Borate also made \(\hbox {CO}_{2}\)-foam more stable by changing the system to non-spreading oil and reducing coalescence of the foam bubbles. The results of these visual experiments suggest that borate can be a useful additive for improving heavy oil recovery in the range of the performed tests, by increasing \(\hbox {CO}_{2}\)-foam stability and producing O/W emulsions. 相似文献
16.
We report optical observations of the dissolution behaviour of glycerol/water, soybean oil/hexane, and isobutyric acid (IBA)/water binary mixtures within a glass micromodel built as a 2D regular network of capillary tubes with diameter of 0.2 mm. The micromodel is initially filled with solute and then is horizontally immersed into a thermostatic solvent-filled bath. The micromodel is open at its corners for solute dissolution to occur with no pressure gradients being applied. Our study shows that the solvent penetration into the micromodel is diffusion-dominated in completely miscible binary mixtures (glycerol/water and soybean oil/hexane). This is, however, non-Fickian diffusion with the dissolution rate, dV/dt, being proportional to $D^{1/3}t^{-0.4}$ for almost the entire duration of the experiment (V is the volume occupied by the solvent, D is the diffusion coefficient, and t is time). For the partially miscible IBA/water mixture the experiments performed at undercritical temperatures revealed that the diffusive transport was negligible despite the mixture being out of its thermodynamic equilibrium. The water phase penetrated into some of the channels, but IBA was never completely displaced/dissolved from the micromodel and numerous interfaces remained visible after very long-time periods. 相似文献
17.
Fundamental Study of Pore Scale Mechanisms in Microbial Improved Oil Recovery Processes 总被引:1,自引:0,他引:1
A fundamental study of microscopic mechanisms and pore-level phenomena in the Microbial Improved Oil Recovery method has been
investigated. Understanding active mechanisms to increase oil recovery is the key to predict and plan MIOR projects successfully.
This article presents the results of visualization experiments carried out in a transparent pore network model. In order to
study the pore scale behavior of bacteria, dodecane and an alkane oxidizing bacterium, Rhodococcus sp. 094, suspended in brine, are examined for evaluating the performance of bacterial flooding in the glass micromodel. The
observations show the effects of bacteria on remaining oil saturation, allowing us to get better insight on the mechanisms.
Bacterial mass composed of bacteria and bioproducts growth in the fluid interfaces and pore walls have been recorded and are
presented. No gas is observed throughout any of the experiments. The biomass blocks some pores and pore-throats, and thereby
changing the flow pattern. As a consequent, the flow pattern change together with the previously proposed mechanisms, including
the interfacial tension reduction and wettability changes are recognized as active mechanisms in the MIOR process. 相似文献
18.
油水乳化渗流是三元复合驱和热力采油过程中常见的现象,地层介质的微观孔隙结构特征对乳状液流动有着重要影响.现有描述乳状液渗流的理论模型都属于确定性方法,只能反映出介质孔隙结构的体积平均效果.当介质内部微观非均质性相比其尺寸不能被忽略时,采用确定性方法描述会与实验结果存在偏差.基于连续时间随机游走理论建立了描述乳状液渗流的随机理论模型.该模型引入反映液滴微观运动特征的跃迁时间和跃迁位移两个概率分布函数来反映多孔介质微观非均质特征.研究结果表明该模型能很好地刻画实验曲线中出现的与介质尺度相关的拖尾现象,可作为更一般的过滤模型. 相似文献
19.
In a WAG process (Water Alternate Gas), water and a miscible solvent (gas) are injected into a reservoir containing water and oil. The solvent will finger through the oil, leading to early breakthrough and poor recovery. Compared with a miscible flood, when only solvent is injected, fingering is supressed by the simultaneous injection of water, since this reduces the apparent mobility contrast between the injected and displaced fluids. The fingering in a miscible flood, with only hydrocarbon flowing, can be modelled successfully using a Todd and Longstaff fractional flow. In this paper, we demonstrate how to modify the effective Todd and Longstaff mobility ratio self-consistently to account for fingering in three component systems. The resultant empirical equations of flow are solved exactly in one dimension and are in excellent agreement with the averaged saturation and concentration profiles computed using two dimensional high resolution simulation, for a variety of injected water saturations, in both secondary and tertiary displacements. 相似文献
20.
In this article, a new model is developed to determine the solvent convective dispersion coefficient in a solvent vapor extraction
(VAPEX) heavy oil recovery process. It is assumed that solvent mass transfer by convective dispersion takes place along the
transition zone between the solvent chamber and untouched heavy oil, whereas solvent mass transfer by molecular diffusion
occurs in the direction normal to the transition zone. It is also assumed that the solvent-diluted heavy oil gravity drainage
through the transition zone has a linear or quadratic velocity profile in order to obtain analytical solutions of the solvent
convective dispersion coefficients for the solvent chamber spreading and falling phases. As a result, this analytical model
correlates the solvent convective dispersion coefficient to the maximum apparent oil gravity drainage velocity at the interface
between the solvent chamber and transition zone, solvent molecular diffusion coefficient, transition-zone thickness, and porosity
of the porous medium. To determine the solvent convective dispersion coefficient, the maximum apparent oil gravity drainage
velocity is calculated by using Darcy’s law and the transition-zone thickness is obtained either from a previous study or
by using a time similarity between the solvent molecular diffusion and oil gravity drainage. It is found that such a determined
solvent convective dispersion coefficient is two to five orders larger than the solvent molecular diffusion coefficient, depending
on the detailed experimental conditions of a specific VAPEX test. 相似文献