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An Improved Study of Emulsion Flooding for Conformance Control in a Heterogeneous 2D Model with Lean Zones
Abstract
Use of oil-in-water (O/W) emulsion has shown its potential for conformance control in heterogeneous porous media, yet it is essential to understand how to improve the conformance control performance in the heterogeneous 2D model with lean zones before it is applied in the fields. In this paper, an O/W emulsion-based conformance control method is improved through newly designed flow tests and optimized modeling study. A heterogeneous 2D model was designed with a high water mobility zone (HWMZ) and a low water mobility zone (LWMZ) separated by a horizontal injection well to mimic real oil sands with lean zones (top- or bottomwater) and with application of horizontal wells. Optimal conformance control strategies were proposed and examined in the 2D model by injecting correspondingly designed O/W emulsions.
In an improvement of our previously proposed emulsion flow model (Ding et al. 2020c), we introduce the real phenomena of permeability reduction (PR) coefficients in this paper to describe the three ambiguous coefficients: flow distribution coefficient (γ), plugging coefficient (α), and retention rate coefficient (a). This newly developed model can incorporate with characteristics of the emulsion and the heterogeneous porous media through the introduction of the experimentally derived PR coefficient. It is well established in COMSOL Multiphysics® (COMSOL AB 2005), and the modeling results show good agreement with the experimentally monitored results in the three types of flow tests. This work bridges experimental and mathematical studies on emulsion flow in 2D models associated with lean zones and is able to provide a guide on optimal emulsion design and injection strategy for optimal conformance control performances.
... The oil present in the high permeability zones was produced during this water flood and the water cut gradually increased to values as high as $ 98%. This represents a state of uneconomical water production ratio and requires chemical intervention to render a 'conforming' drive the porous flow [14]; X. [79]. This was performed by introducing an additional 1.15 PV of surfactant-based ME slug at the same rate (12 ml/h). ...
... The pressure response showed a sharp increase in pressure drop with a favorable reduction in water cut percentage to 30% until 0.84 PV injection of ME fluid. This occurs due to the plugging of water channels in the high per- meability zones of the rock, which leads to a lower water-to-oil production ratio [14,26,52]; X. [79]. However, the water cut again is observed to increase post 30% water-cut condition with time due to the gradual decrease in viscosity and inefficiency in blocking ability of the ME. ...
The field of microemulsion-assisted conformance improvement technology (ME-CIT) requires workflow planning in order to effectively decrease the water-to-oil ratio during production operations. This article deals with the implementation of a suitable ME-CIT route via experimental validation. The ternary diagram identified the different Winsor regions to classify phase behavior. The aggregation behavior of micellar structures in ME phase was studied via dynamic light scattering tests. Relative phase behavior experiments depicted the presence of Winsor I phase at low salinity upto 20,000 ppm total dissolved salts (TDS) content. At nearly 25,000 ppm, this altered into a Winsor III system. This phase behavior further changed into a Winsor Type III phase at 50,000 ppm. The surfactant-based microemulsion exhibited favorable time-dependent flow attributes, as evident from the observation that the steady-state viscosity did not alter markedly with elapse of time. The pseudoplastic rheology of microemulsion has been explained on a macroscopic level and micelle morphology on a microscopic scale with two phenomena: electro-shielding and micelle deformation. With increasing salinity, the viscosity versus salt concentration plots revealed a unique ‘M’ shape at 7.34 s-1. This describes an initial increase, then a decreasing trend, followed by a increase and eventually a near-constant viscosity as salt content increases further. Porous media flow experiments were conducted for optimized microemulsion slug using a sandstone core model. A favorable pressure drop and reduction in water-cut percentages were recorded during microemulsion flooding stage in the laboratory. In summary, the proposed methodology contributes toward developing potential surfactant-based microemulsions systems for application in conformance improvement technology.
... Among them, emulsion flooding is one of the most important methods to enhance oil recovery [21,22] and shows a good application further in enhanced oil recovery after water flooding. Meanwhile, studies have shown that in situ emulsification of crude oil is also an important means to enhance oil recovery, especially for heavy oil reservoirs [23][24][25][26]. ...
O/W emulsion reinforced by nanosilica particle has good application in hydrocarbon development. However, there are few reports on the influence of nanosilica particles on the oil-water interface of O/W emulsion. The effect of nanosilica particles on the interfacial properties of O/W emulsion was indirectly investigated by measuring the interfacial properties between aqueous dispersion of nanosilica particles and kerosene, and the properties of O/W emulsion reinforced by nanosilica particle were studied. The results showed that the aqueous dispersion of nanosilica particles could significantly reduce the interface tension (with kerosene) by more than 50%, and the interface tension between the aqueous dispersion and kerosene decreased with the increase in nanosilica content. The aqueous dispersion of nanosilica particles could significantly change rock wettability. When the content of nanosilica particles increased from 0.1% to 0.7%, the contact angle decreased from 44.89° to 27.62°. The surface tension of O/W emulsion prepared by the aqueous dispersion of nanosilica particles and kerosene was among 25 mN/m~30 mN/m. The contact angle was also particularly small, with an average of about 20.00°, a minimum of 12.50°. The salts had little effect on the interface tension of emulsions but had a significant influence on the contact angle and its stability. Magnesium salt could reduce the three-phase contact angle and increase the hydrophilic properties of O/W emulsion, while calcium salt had the opposite effect. Calcium salt and magnesium salt could reduce the stability of the emulsion, and calcium salt had a greater influence. The oil-water stratification adding either calcium salt or magnesium salt was about 1 day~3 days earlier than that without salts. In the experiment, when the content of nanosilica particles was among 0.3%~0.7%, the viscosity of O/W emulsion increased with the increase in nanosilica particles. When the content was 0.9%, the viscosity suddenly decreased, and the extent of reduction was about 21.7%. The findings of this study can help for better understanding the application of nanosilica particles in O/W emulsion, giving some suggestions for the application of nanoparticles in hydrocarbon development.
... It can be used as a plugging agent and has a good plugging effect at high reservoir temperature (140 • C). Overall, external injection emulsions can be used to enhance recovery in non-homogeneous thick oil reservoirs (Ding et al., 2021a(Ding et al., , 2021b(Ding et al., , 2022. With most oilfields entering the high water cut stage, the traditional polymer flooding can no longer meet the requirement of increasing the recovery rate (Corredor et al., 2019). ...
Asphaltene and hydrolyzed polyacrylamide (HPAM) are important components for stabilizing polymer-containing oil water/sludge in oilfield. In this study, the effects of asphaltenes concentration, HPAM concentration, pH, oil/water ratio and salinity on the storage stability and shear rheology of the emulsions were investigated. The results showed that the addition of HPAM could change the emulsion type from W/O to O/W, and the shear modulus of the emulsions stabilized by HPAM and asphaltenes were 10 times lower than that of asphaltenes emulsions. As the pH increased from 4 to 11, the emulsion type changed from W/O to O/W and the shear modulus of the emulsion decreased by 2 orders of magnitude. The addition of inorganic salts destroyed the asphaltene interfacial film and reduced the stability of the emulsion. Secondly, the interaction of amide and carboxylic acid groups in HPAM molecules with asphaltenes was investigated through interfacial properties. The carboxylic groups and amide groups of HPAM molecules could interact with the interfacial active components of asphaltenes and formed a carboxyl-asphaltene-amide complex unit, which made the asphaltene molecules “anchorage” on the HPAM molecular chain. This study is intended to provide a theoretical basis for the efficient and environmentally friendly treatment of polymer-containing oil water/sludge in oilfield.
... In addition, fundamental mechanisms of emulsion flow have also been investigated experimentally in capillary tubes (Cobos et al., 2009;Guillen et al., 2012b;Romero et al., 2011), micromodels (Xu et al., 2015(Xu et al., , 2017b(Xu et al., , 2017c and sandpacks/cores (Ding et al., 2020a;Guillen et al., 2012a;Ning et al., 2018;Soo and Radke, 1984) in the past several decades. There are also some experimental investigations, focusing on the performance of conformance control in heterogeneous parallel-sandpack and 2-D models where are only saturated with water (Ding et al., , 2020b(Ding et al., , 2021bYu et al., 2018c). To date, no literature has reported a quantitative study of the performance of EOR through conformance control by emulsion injection in heterogeneous porous media saturated with oil and water. ...
Many of western Canada's heavy oil reservoirs are too thin to allow expensive thermal recovery techniques. Therefore, waterflooding is still often employed in heavy oil reservoirs due to its relatively inexpensive and easy manipulation. However, heterogeneity in permeability and/or in water saturation has been widely encountered in heavy oil reservoirs, resulting in very poor oil recovery with excessive water production. In this study, performances of enhanced oil recovery (EOR) by injection of oil-in-water (O/W) emulsions in heterogeneous heavy oil reservoirs were evaluated through experiments, modeling and reservoir simulation. For experiments, each O/W emulsion was firstly characterized via its stability behavior, emulsion quality, oil-water interfacial tension (IFT), oil viscosity, and droplet size distribution. Parallel-sandpack models with two different types of heterogeneities, either in oil saturation or absolute permeability, were applied to simulate the heterogeneity in heavy oil reservoirs. Experimental results show that injection of the emulsions is effective to recover the by-passed oil in the water-unswept sandpack and the EOR performance is strongly dependent on the emulsion characteristics. In order to achieve optimal oil recovery, a conformance in water mobility (outflow percentage ratio of 50%:50%) is found to be effecitve in the parallel-sandpack with heterogeneity in permeability. In parallel-sandpack with variations in water saturation, a strong blockage in high water saturation sandpack with a long penetration distance contributes an optimal oil recovery.
An in-house simulator was developed based on an optimized emulsion flow model, for the first time, to be able to describe the physics of emulsion-assisted EOR in heterogeneous porous media. The simulation results show that emulsion injection in parallel-sandpack causes a greater average permeability reduction in the high water mobility sandpack resulted from longer emulsion slug penetration compared to that in the low water mobility sandpack. This leads to an increased water flood rate in the low water mobility sandpack, resulting in more oil production. A case study of emulsion flooding for EOR in a heterogeneous heavy oil reservoir was conducted. Strategies for optimal EOR in heterogeneous heavy oil reservoirs were discussed. Reservoir simulation results show that a greater ratio of emulsion slug in high water mobility zone to that in low water mobility zone is beneficial for EOR with a fixed emulsion plugging strength. For a given emulsion slug, there exists an optimal emulsion plugging strength for a prime EOR which can be designed through the optimized emulsion flow model.
The article presents a solution to the problem of determining the most effective system for the development of hard-to-recover oil reserves confined to thin-layered clay-bearing reservoirs, based on geological and hydrodynamic modeling. The ratio of oil recovery factor and net discounted income was used as an assessment of the project efficiency. When selecting, the profile was varied - a directional well with hydraulic fracturing and a horizontal well with multi-stage hydraulic fracturing, the method of organizing the system for maintaining reservoir pressure, the density of the well grid and the technological parameters of well completion - the length of the horizontal section and the distance between the hydraulic fracturing sleeves. To confirm the results obtained, an analysis of the operation of the wells launched at the facility was carried out, which showed the convergence of the rate of decline in production rates in the absence of the involvement of the underlying horizon by a hydraulic fracture. Additionally, when choosing a site for pilot work, an option was considered to use the existing well stock to organize a reservoir pressure maintenance system while maintaining the geometry of the development element. According to the calculations, the application of the developed solutions will make it possible to double the oil recovery factor and the net discounted income of the project compared to the base case.
Emulsification is a crucial technique for mixing immiscible liquids into droplets in various industries, such as food, cosmetics, biomedicine, agrochemistry, and petrochemistry. Quantitative analysis of the stability is pivotal before the utilization of these emulsions. Differences in X-ray attenuation for emulsion components and surface relaxation of the droplets may contribute to X-ray CT imaging and low-field NMR spectroscopy as viable techniques to quantify emulsion stability. In this study, Pickering (stabilized solely by nanoparticles) and Classical (stabilized solely by low molecular weight polymers) nanoemulsions were prepared with a high-energy method. NMR and X-ray CT were employed to constantly monitor the two types of nanoemulsions until phase separation. The creaming rates calculated from NMR match well with the results obtained from X-ray CT. Furthermore, we show that Stokes' law coupled with the classical Lifshitz-Slyozov-Wagner theory underestimates the creaming rate of the nanoemulsions compared to the experimental results from NMR and X-ray CT imaging. A new theory is proposed by fully incorporating the effects of Pickering nanoparticles, hydrocarbon types, volume fraction, size distribution, and flocculation on the droplet coarsening. The theoretical results agree well with the experimentally measured creaming rates. It reveals that the attachment of nanoparticles onto a droplet surface decreases the mass transfer for hydrocarbon molecules to move from the bulk aqueous phase into other droplets, thus slowing the Ostwald ripening. Therefore, Pickering nanoemulsions show a better stability behavior compared to Classical nanoemulsions. The impacts of hydrocarbon and emulsification energy on the stability of nanoemulsions are reported. These findings demonstrate that the stability of the nanoemulsions can be manipulated and optimized for a specific application, setting the stage for subsequent investigations of these nanodroplets.
The application of microemulsion-assisted conformance improvement technology (ME-CIT) has the potential to significantly reduce the water-to-oil production ratio and operational costs during oilfield stimulation/production. However, the efficacy of this process is dependent on workflow planning and validation from an experimental viewpoint. The current article aims to develop a functional ME-CIT route and propose a viable microemulsion fluid system, based on this approach. Initially, the liquid-liquid phase behavior was classified using the ternary phase diagram. A phase envelope was identified to separate the multi-phase (2- and 3-phase) region from the uneconomical one-phase region. ME droplets were characterized via dynamic light scattering tests to understand the aggregation behavior of micelles and the extent of salt on coalescence. Relative phase volume investigations revealed the existence of Winsor I at low salinities upto 20,000 ppm total dissolved salts (TDS) content. The first phase transition occurred at 25,000 ppm TDS to exhibit a Winsor III system and continued till the salinity reached 40,000 ppm. At 50,000 ppm, the Winsor III changed into Winsor II phase behavior. In addition, the steady-state shear viscosity of ME fluids does not alter markedly with time, irrespective of their salt content. Viscosity plots show the pseudoplastic or shear-thinning flow behavior of MEs. The ME rheology can be discussed in terms of two opposing interaction effects: electro-shielding and micelle deformation. The viscosity is, therefore, a function of salinity-induced phase behavior on a macroscopic level and micelle morphology on a microscopic scale. Viscosity versus salinity plots at 7.34 s-1 depicts a unique ‘M’ shape with increasing salinity, characterized by an initial increase, followed by a decrease, then an increase, and finally a near-constant viscosity. Flow displacement tests of optimized ME slug illustrated a favorable pressure drop response after water-flood, which is accompanied by a significant decrease in water cut. Based on the physicochemical evaluation and subsequent displacement testing, the proposed laboratory workflow model contributes to a potentially useful method of optimizing and designing surfactant-based ME fluid systems for conformance improvement.
Steam-Assisted Gravity Drainage (SAGD) is a widely used technology for heavy oil and bitumen recovery in Alberta, Canada. However, a SAGD conformance problem arises due to the heterogeneity of oil sands reservoirs, such as the presence of high permeability zones and high water saturation zones. In particular, during a geomechanical dilation start-up process that has been developed and applied in SAGD start-up operations, the dilation fluid tends to flow into the high permeability zones, leaving the low per-meability zones un-swept. Therefore, the high permeability zones must be temporarily and selectively blocked off so as to more effectively dilate the low permeability zones along a SAGD well-pair.
Laboratory permeability reduction tests in sandpacks by oil-in-water (O/W) emulsion injection showed that a permeability reduction of up to 99.95% can be achieved. Results of emulsion injection in parallel-sandpack tests demonstrated that a good conformance control can be obtained by a suitable combinations of IFT, emulsion quality, emulsion slug size, and oil phase viscosity of an emulsion system. The reservoir simulation study was conducted to first match the laboratory test results and then to optimize SAGD conformance control operations by emulsion injection in heterogeneous oil sands reservoirs. A field-scale SAGD simulation model was established to show that emulsion injection during the dilation start-up process can build up communication between the injector and producer, resulting in better steam chamber growth and lower cumulative steam-oil-ratio (CSOR).
Oil-in-water (O/W) emulsion flow tests were conducted in visual and heterogeneous two-dimensional (2-D) models in which the crossflow between the high (HPZ) and low permeability zones (LPZ) can be modelled. Impacts of emulsion droplet size on promoting crossflow between the two permeability zones were investigated. Emulsion flood pattern and outflow percentage from the two heterogeneous zones show that injection of O/W emulsions with an appropriate range of droplet sizes can induce crossflows between the two permeability zones, thereby resulting in the water mobility conformance in the heterogeneous 2-D model. Two types of crossflow were observed in the experiments and verified in the numerical modeling: flow redistribution at the injection boundary and crossflows in the emulsion-invaded area. A new mathematical model was established to capture the dynamics of 2-D emulsion flow. A finite element method was used to obtain the solution of the mathematical model, and the experimentally observed emulsion conformance control processes were successfully predicted. Mathematical analyses on emulsion concentration distribution, velocity field and pressure distribution reveal that it is the capillary resistance contributed by the emulsion that changes the pressure distribution in the two permeability zones; therefore, the changed pressure distribution affects the local flow in the two permeability zone and thus influences the outflows. The proposed emulsion flow model is compatible with a standard reservoir simulator, providing a potentially efficient and useful method of simulating field-scale emulsion flow for designing conformance control process.
An oil-in-water (O/W) emulsion treatment has shown its potential in improving the conformance in oil sands, yet it is essential to understand how the displacing pressure drop would vary with the character and size of the fluid slug in oil fields. In this study, emulsion injection followed by water flooding was conducted in 15 sandpack tests to evaluate the emulsion plugging process. Four stages of the plugging process were observed and are discussed. Different emulsion properties (emulsion quality, interfacial tension (IFT) and droplet size), sandpack length, and emulsion slug size were assessed as their impacts on each stage of the plugging process. For a specified emulsion slug, the length of the sandpack can influence the time when the pressure drop starts to decline during the extended water injection, thereby changing the plugging process. Enhancing the “Jamin effect” by promoting the emulsion properties (emulsion quality, IFT and droplet size) does not always provide the best option for plug of high mobility zones in the oil sands. Emulsions with a fast plugging ability have short penetration length in the sandpacks under a required pressure gradient, whereas emulsions with a slow plugging ability may not achieve the expected plugging strength. For a sandpack with specified properties, only injection of an optimal emulsion system can achieve a desired plugging strength and depth. To design an optimal emulsion system, this study developed a new mathematical model to simulate the plugging pressure drop by fully incorporating emulsion properties, sandpack properties and emulsion slug size. The simulated results can successfully match the experimental results.
Emulsion flow behavior in porous media is predominantly affected by the emulsion’s droplet size distribution, as the macro flow character is determined by the micro transport phenomena of emulsion droplets passing through pore constrictions. In this work, oil-in-water emulsions (O/W) with different droplet sizes but with the same oil concentration were first prepared and characterized by their interfacial tension, size distribution, stability, and bulk viscosity. Then, sandpack flow tests were conducted to quantitatively investigate the plugging characteristics of the different emulsions in porous media. The results show that pressure drop of the emulsions in 1 μm2 permeability sandpacks initially increases as emulsion droplet size increases from 1.57 μm to 3.58 μm, but then begins to decrease as the droplet size continues to increase. For a single emulsion droplet, a larger droplet size can result in a greater capillary resistance force, as it has a more significant “Jamin” effect in pore constrictions. However, for an emulsion system, the total pressure drop is also affected by droplet number. A larger droplet size means a smaller droplet number in the emulsion system. The macro flow character of emulsions in porous media is determined both by droplet size and droplet number. A new mathematical model, which incorporates geometry of the porous media, emulsion droplet size, emulsion droplet number, and interactions between droplets and porous media was developed to theoretically describe the plugging of an emulsion in the sandpacks. For the first time, this model takes into account the size difference between the pore-body and the pore-throat of a real porous medium when simulating emulsion transport. Results calculated from the newly proposed model appear to match well with the experimental data, with the smallest average error being 7.67%.
In western Canada, a significant number of oil sands reserves have little or no cap rock with a top water zone. Due to huge heat loss to the top water zone, the conventional Steam-Assisted Gravity Drainage (SAGD) process is uneconomical when applied directly in this type of reservoir.
Building on the comprehensive, fundamental mechanisms and mathematical computations detailed in the First Edition, the new Second Edition of Enhanced Oil Recovery presents the latest insights into the applications of EOR processes, including-Field-scale thermal-recovery such as steam-assisted gravity drainage and cyclic steam stimulation-Field-scale polymer flooding including horizontal wells-Field-scale miscible-displacement processes such as CO2 miscible flooding-Laboratory-scale chemical flooding in the development and testing of surfactant formulations
An invaluable tool for petroleum engineering students, Enhanced Oil Recovery also serves as an important resource for those practicing oil recovery in the field or engaged in the design and operation of commercial projects involving enhanced-or improved-oil-recovery processes. A prior understanding of basic petrophysics, fluid properties, and material balance is recommended.
The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control.
This work establishes the flow mechanism of dilute, stable emulsions in fine grained porous media. Oil-in-water emulsions of mean drop sizes ranging from 1 to 10 mu m are studied in sandpacks of 0. 57 and 1. 15 mu m**2 permeability at a superficial velocity of 0. 07 mm/s. Low viscosity oil drops cause permeability reductions of up to 80%, with 4 to 5 mu m size drops being the most effective. By examining drop sizes and pore sizes, as well as transient effluent emulsion concentration and transient pressure data, we find that permeability reductions during emulsion flow are caused by droplet capture mechanisms similar to those found for solid particle deep-bed filtration. The proposed filtration mechanism is verified by a micromodel study. This work is pertinent to wastewater renovation.
When oil emerges from a water-wet constriction into a water-filled pore, the interfacial forces are such that a leading portion of the oil may separate into a droplet (snap off). Theory indicates that for a given shape of constriction, there is a minimum size to the protruding portion of the oil that permits snap-off. If the oil/solid contact angle is zero and if the constriction has the shape of the throat of a tore (a doughnut hole), the oil must protrude for a distance of at least seven times the throat radius before snap-off can occur. Experiments were performed in approximately toric constrictions constructed of glass. Liquids used were a dyed mineral oil and a water-ethanol mixture adjusted to the same density as the mineral oil to avoid gravitational effects. Within the limitations imposed by visual distortions through the glass and the liquids, the observations appear to be in accord with the theoretical predictions.
Introduction
Production of oil from a reservoir involves flow of oil through a porous medium that also contains water. Because of the small size of the pores in the reservoir rock or sand capillary forces at the oil-water interface are of considerable importance in determining the nature of the flow through the pores. This report deals with one aspect of such pores. This report deals with one aspect of such How, determining the conditions that must be met in order that the oil emerging from a water-wet constriction will separate (snap off or pinch off) into a droplet in the larger parts of the channel. By applying the fundamental equation of capillarity to oil flowing through certain geometrically describable water-wet constrictions we can calculate the minimum size of the protruding body of oil that will permit snap-off of the oil to give a separate droplet. The theoretical treatment can be checked, at least semiquantitatively, by observations on dyed mineral oil flowing through glass pores previously filled with a water-alcohol mixture. This mixture should be adjusted to give be same density as that of the mineral oil in order to eliminate gravitational effects, which can be large relative to capillary effects in constrictions having an internal diameter of about 2 mm.
THEORETICAL
In a report on pore structure and fluid distribution, Pickell, Swanson and Hickman included a discussion Pickell, Swanson and Hickman included a discussion on some aspects of snap-off of oil into droplets as that nonwetting phase moves through constrictions in pores. The discussion may be extended to indicate some pores. The discussion may be extended to indicate some of the physical conditions that must be met if snap-off is to occur. Pickell et al considered a single pore to be generally quite angular in cross-section, as shown in Fig. 1a (after Fig. 3 of their report). However, let us first consider an isolated constriction that is circular in cross-section and then comment on a less ideal pore.
DOUGHNUT-HOLE PORE
Let the constriction have the shape of the hole within a tore, i.e., the hole through a doughnut,* as in Fig. 1b. This pore, initially water-filled, now has oil of the same density being forced into it. As the nose of the oil and the wall of the pore, so that thin layer of water is imagined as being retained between the oil and the wall of the pore, so that the contact angle between rock and oil remains zero. The oil is moving so slowly that the pressure (or, more properly, the head) is essentially equal at all points within the oil phase. A longitudinal section of a toric pore is indicated in Fig. 1c. Pertinent lengths are shown in Fig. 1d, where Pertinent lengths are shown in Fig. 1d, where these lengths are given relative to the radius of the throat (this word being used to indicate the narrowest part of the constriction).
SPEJ
P. 85
This study is aimed at developing an alkaline/surfactant-enhanced oil recovery process for heavy oil reservoirs with oil viscosities ranging from 1000 to 10,000mPas, through the mechanism of interfacial instability. Instead of the oil viscosity being reduced, as in thermal and solvent/gas injection processes, oil is dispersed into and transported through the water phase to production wells.Extensive emulsification tests and oil/water interfacial tension measurements were conducted to screen alkali and surfactant for the oil and the brine samples collected from Brintnell reservoir. The heavy oil/water interfacial tension could be reduced to about 7×10−2dyn/cm with the addition of a mixture of Na2CO3 and NaOH in the formation brine without evident dynamic effect. The oil/water interfacial tension could be further reduced to 1×10−2dyn/cm when a very low surfactant concentration (0.005–0.03wt%) was applied to the above alkaline solution. Emulsification tests showed that in situ self-dispersion of the heavy oil into the water phase occurred when a carefully designed chemical solution was applied.A series of 21 flood tests were conducted in sandpacks to evaluate the chemical formulas obtained from screening tests for the oil. Tertiary oil recoveries of about 22–23% IOIP (32–35% ROIP) were obtained for the tests using 0.6wt% alkaline (weight ratio of Na2CO3 to NaOH=2:1) and 0.045wt% surfactant solution in the formation brine. The sandpack flood results obtained in this project showed that a synergistic enhancement among the chemicals did occur in the tertiary recovery process through the interfacial instability mechanism.
Steam Surfactant Systems at Reservoir Conditions. Paper presented at the SPE California Regional Meeting
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