Oil Recovery by Hydrocarbon Slugs Driven by a Hot Water Bank

1971 ◽  
Vol 11 (04) ◽  
pp. 342-350 ◽  
Author(s):  
Abbas A. Alikhan ◽  
S.M. Farouq Ali
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Miscible Displacement ◽  
Light Hydrocarbon ◽  
Hot Water ◽  
Residual Oil ◽  
Oil Viscosity ◽  
Connate Water ◽  
Experimental Apparatus

Abstract An experimented study was conducted of the recovery of oil from as porous medium overlain and underlain by heat-conducting formations and containing a residual oil or connate water saturation by injection of a small slug of a light hydrocarbon followed by 1/2 PV of hot water driven by a conventional waterflood. The fluid production histories and the temperature distribution obtained showed that a light hydrocarbon sag injected ahead of a hot water slug leads to a considerable increase in oil recovery. The net oil recovery was found to depend on the original oil viscosity, hydrocarbon slug viscosity, and the injection rate. The process was more effective in a previously waterflooded core rather than in one containing connate water. The over-all ratio of the total hydrocarbon produced to the hydrocarbon injected ranged from 1.10 to 3.96, the variation corresponding to the viscosity of the hydrocarbon slug employed. Introduction Numerous methods have been proposed for recovering oil from previously waterflooded porous media. Some methods involve the application of heat in one form or another, while others utilize miscible displacement processes. The proposed method involves a combination of the two, employing a small hydrocarbon slug followed by a slug of hot water, which is driven by a conventional waterflood. An attempt was made to investigate the conditions (residual oil saturation, viscosity, etc.) under which such a method would yield a sizable oil recovery. Use of a solvent dug followed by at heat-carrying agent was earlier considered by Pirela and Farouq Ali. The process was designed to take advantage of the improved ternary-phase equilibrium behavior at elevated temperatures in the alcohol slug process. The experimental runs were conducted under isothermal conditions. In another study, Avendano found that injection of a light crude oil into a core containing a highly viscous oil prior to steam injection led to a large improvement in oil recovery. A number of investigators have studied the effect of water-driven hydrocarbon slugs on oil recovery from waterflooded porous media. Csaszar and Holm employed slugs of propane in waterflood cores containing oils with viscosities ranging from 3 to 9 cp. The volume of the oil recovered was 2 to 3 times the propane injected, the efficiency of the process depending on the amount of mobile oil process depending on the amount of mobile oil near the point of injection and the viscosity of the in-place oil. Wiesenthal used gasoline as an intermediate slug when waterflooding cores containing oils having viscosities of 1.28 to 324 cp. He found that the process was effective in waterflooded porous media, especially in the case of viscous oils. Fitzgerald conducted similar experiments using gasoline and arrived at more or less the same conclusions. The process under consideration involves a combination of miscible displacement and hot waterflooding, both of which have been amply discussed in the literature. A comprehensive survey of miscible displacement has been presented by Perkins and Johnston, while a description of hot Perkins and Johnston, while a description of hot waterflooding may be found elsewhere. In the following, only the most important features of the two processes operating in the combination process will be considered. EXPERIMENTAL APPARATUS AND PROCEDURE PROCEDURE APPARATUS The porous medium used in the present investigation consisted of a steel cube 4 ft in length with a rectangular cross-section and inside dimensions of 1.5 × 3.5 in., packed with 130-mesh glass beads. The resulting core had a porosity of 39.95 percent (PV = 1,690 cc) and permeability of 7 darcies. The core was provided with 15 connections on one side for thermocouples and 5 connections on the other side for transducers. SPEJ P. 342

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

2021 ◽  
Author(s):  
Randy Agra Pratama ◽  
Tayfun Babadagli
Keyword(s):  
Porous Media ◽  
Phase Change ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Phase Distribution ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Residual Oil ◽  
Tertiary Recovery

Abstract Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

Pore-Scale Investigation of Phase Distribution and Residual-Oil Development During Secondary and Tertiary Solvent Injection

2014 ◽  
Vol 18 (01) ◽  
pp. 39-52 ◽  
Author(s):  
Yousef Hamedi Shokrlu ◽  
Tayfun Babadagli
Keyword(s):  
Oil Recovery ◽  
Phase Distribution ◽  
Water Saturation ◽  
Hot Water ◽  
Experimental Investigations ◽  
Residual Oil ◽  
Displacement Efficiency ◽  
Oil Viscosity ◽  
Flow Process ◽  
Water Solvent

Summary Flow of three phases, of which one is miscible with another, in porous media may commonly be encountered during enhanced-oil-recovery (EOR) applications in oil reservoirs. Typical examples include solvent (miscible-gas) injection alternated with water and coinjection or alternate injection of steam (or hot water) and solvent in heavy-oil/bitumen reservoirs. Oil, water, and solvent flow together under immiscible (water/oil and water/solvent) and miscible (oil/solvent) conditions at the same time, and the distribution of phases and removal of residual oil in those types of processes depend on many parameters. This paper reports microscale experimental investigations on this complex flow process and provides an extensive parametric analysis on the microscopic displacement efficiency of oil recovery using miscible solvent. For this purpose, micromodels created by use of a replica of sandstones were used. Waterflood residual-oil displacement requires contact of the injected solvent with the blocked oil. The efficiency of this process depends on several parameters, including matrix wettability, oil viscosity, initial water saturation, and reservoir heterogeneity. On the other hand, the sequence of injection of solvent and water is considered as another parameter by which oil recovery can be affected significantly. The results of the micromodel-visualization experiments showed that injection of solvent before the introduction of any water to the reservoir can increase the recovery factor significantly. Existence of the water phase in the reservoir creates capillary barriers that prevent oil/solvent contact. The matrix wettability and oil viscosity were observed to be critically important to the amount of oil recovery.

Displacement of Polymers in Waterflooded Porous Media and Its Effects on a Subsequent Micellar Flood

1977 ◽  
Vol 17 (05) ◽  
pp. 358-368 ◽  
Author(s):  
Mahmoud K. Dabbous
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Phase Distribution ◽  
Mobility Control ◽  
Reservoir Rock ◽  
Residual Oil ◽  
Improved Oil Recovery ◽  
Residual Resistance ◽  
Oil Water

Abstract Injection of polymers in advance of a micellar fluid slug has been considered to improve reservoir volumetric sweep in a tertiary-mode micellar flood. An investigation was made of the injection of polyacrylamide-type polymers in waterflooded polyacrylamide-type polymers in waterflooded porous media and its effects on a subsequent porous media and its effects on a subsequent micellar flood. It was found that the presence of waterflood residual oil saturations in the porous medium increased the flow resistance and residual resistance factors (2- to 3.5-fold) compared with their corresponding values when the rock was free of residual oil. Inaccessible pore volume to polymer flow also appeared to be larger when waterflood residual oil saturations were present. These effects have been attributed to wettability and phase distribution of fluids in the porous medium. phase distribution of fluids in the porous medium. The study emphasized basic differences in the flow behavior of polymer injected ahead of a micellar slug (to improve sweep) and behind the micellar fluid (to control mobility). Both effects are for improved oil-recovery efficiency. Water mobility was greatly reduced following the displacement of polyacrylamide polymers in the waterflooded cores, yet mobility of the oil-water bank in a subsequent micellar flood was reduced to a lesser degree than the water bank. For a residual resistance factor to water ranging from 2 to 7, mobility control of a subsequent micellar flood could be achieved with a 22- to 39-percent increase in polymer concentration in the mobility buffer bank. This increase is in excess of the concentration required for a flood not preceded with polymer injection. Polymer preinjection had no adverse effects on oil displacement characteristics of the micellar fluid and appeared to reduce surfactant adsorption on the rock for the polymer-micellar system studied. Some experimental data indicated that the oil bank breaks through earlier and at a slightly higher oil cut in linear core floods. Such a result is theoretically feasible if the reduced-mobility water is not completely displaced at the front end (immiscible portion) of the oil-water bank. Oil-bank breakthrough probably would be delayed in the reservoir because of the action of the preinjected polymer to decrease the flow of fluids in polymer to decrease the flow of fluids in high-permeability zones. Introduction In a previous paper, preinjection of polymers in advance of a micellar slug was proposed as a means for improving reservoir volumetric sweep and oil recovery by a micellar flood. Increased flooding efficiency should result from reduced interwell permeability contrast in the reservoir following the polymer treatment. Preinjection of polymers also should result in better preflushing polymers also should result in better preflushing efficiency in displacing incompatible formation brines over "conventional" water preflushes. Thus, an improved oil-recovery method designed to increase reservoir volumetric sweep and miscibly recover tertiary oil consists ofpreinjection of a carefully designed slug of preinjection of a carefully designed slug of high-molecular-weight polyacrylamide polymers followed by a water-bank spacer to displace the polymer in the interwell area, andinjection of polymer in the interwell area, andinjection of a surfactant (micellar) slug followed by a polymer mobility buffer bank and chase water. The fluid banks that are injected or developed during the process are illustrated in Fig. 1. Mixing and process are illustrated in Fig. 1. Mixing and interaction zones at fluid-bank boundaries are not shown in the schematic. The preinjection of a polymer is intended to rectify interwell permeability variation. The polymer is injected in reservoir rock that has waterflood residual oil saturations. SPEJ p. 358

scholarly journals SURFACTANT-POLYMER FLOODING PERFORMANCE IN HETEROGENEOUS TWO-LAYERED POROUS MEDIA

2011 ◽  
Vol 12 (1) ◽  
pp. 31-38 ◽  
Author(s):  
Muhammad Taufiq Fathaddin ◽  
Asri Nugrahanti ◽  
Putri Nurizatulshira Buang ◽  
Khaled Abdalla Elraies
Keyword(s):  
Porous Media ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Reservoir Heterogeneity ◽  
Residual Oil Saturation ◽  
Layered Porous Media ◽  
Multiple Porosity

In this paper, simulation study was conducted to investigate the effect of spatial heterogeneity of multiple porosity fields on oil recovery, residual oil and microemulsion saturation. The generated porosity fields were applied into UTCHEM for simulating surfactant-polymer flooding in heterogeneous two-layered porous media. From the analysis, surfactant-polymer flooding was more sensitive than water flooding to the spatial distribution of multiple porosity fields. Residual oil saturation in upper and lower layers after water and polymer flooding was about the same with the reservoir heterogeneity. On the other hand, residual oil saturation in the two layers after surfactant-polymer flooding became more unequal as surfactant concentration increased. Surfactant-polymer flooding had higher oil recovery than water and polymer flooding within the range studied. The variation of oil recovery due to the reservoir heterogeneity was under 9.2%.

Capillary Impregnation of Viscous Fluids in a Multi-Layered Porous Medium

2019 ◽  
Author(s):  
Shabina Ashraf ◽  
Jyoti Phirani
Keyword(s):  
Porous Medium ◽  
Porous Media ◽  
Oil Recovery ◽  
Viscous Fluids ◽  
Spontaneous Imbibition ◽  
Lab On Chip ◽  
Capillary Impregnation ◽  
Relative Placement ◽  
Homogeneous Porous Medium ◽  
Wetting Fluid

Abstract Capillary impregnation of viscous fluids in porous media is useful in diagnostics, design of lab-on-chip devices and enhanced oil recovery. The impregnation of a wetting fluid in a homogeneous porous medium follows Washburn’s diffusive law. The diffusive dynamics predicts that, with the increase in permeability, the rate of spontaneous imbibition of a wetting fluid also increases. As most of the naturally occurring porous media are composed of hydrodynamically interacting layers having different properties, the impregnation in a heterogeneous porous medium is significantly different from a homogeneous porous medium. A Washburn like model has been developed in the past to predict the imbibition behavior in the layers for a hydrodynamically interacting three layered porous medium filled with a non-viscous resident phase. It was observed that the relative placement of the layers impacts the imbibition phenomena significantly. In this work, we develop a quasi one-dimensional lubrication approximation to predict the imbibition dynamics in a hydrodynamically interacting multi-layered porous medium. The generalized model shows that the arrangement of layers strongly affects the saturation of wetting phase in the porous medium, which is crucial for oil recovery and in microfluidic applications.

Visualization of a Surfactant Flood of an Oil-Saturated Porous Medium

1984 ◽  
Vol 24 (03) ◽  
pp. 325-327 ◽  
Author(s):  
L. Paterson ◽  
V. Hornof ◽  
G. Neale
Keyword(s):  
Porous Medium ◽  
Oil Recovery ◽  
Capillary Number ◽  
Saturated Porous Medium ◽  
Surfactant Solution ◽  
Viscous Fingering ◽  
Water Flooding ◽  
Alkyl Aryl Sulfonate ◽  
Oil Viscosity ◽  
Paraffin Oil

Abstract This paper discusses the viscous fingering that occurs when water or a surfactant solution displaces oil in a porous medium. Such floods were visualized in an porous medium. Such floods were visualized in an oil-wet porous medium composed of fused plastic particles. The flow structure changed significantly within the range of capillary numbers between 10 -4 and 10 -3 . The addition of surfactant resulted in narrower fingers, which developed in a more dispersive fashion. Introduction In describing fluid/fluid displacements in porous media, a useful dimensionless quantity is the capillary number, (1) which corresponds to the ratio of viscous forces to capillary forces. Here, v is the specific fluid discharge or Darcy velocity, it is viscosity, and o is interfacial tension (IFT). It has been shown that the recovery of oil from an underground reservoir increases significantly if the capillary number can be increased beyond the range of 1 × 10 -4 to 2 × 10 -3 during water flooding (see Larson et al. 1 ). To this end, surfactants are used extensively in tertiary oil recovery operations with the objective of reducing IFT and consequently mobilizing the oil ganglia which otherwise would remain trapped. This paper is concerned with the viscous fingering that occurs when water displaces oil in a porous medium, and we present a brief consideration on the effects that surfactants have on fingering. Noting that Peters and Flock have visualized fingering within the range of capillary numbers between 1.6 × 10 -6 and 7.2 × 10 -4, we present here visualizations at capillary numbers of 7.7 × 10 5 and 1.0 × 10 -3. Both our visualizations and the experiments of Peters and Flock involve large viscosity ratios so that only the viscosity of the more viscous fluid is considered when determining the capillary number. In particular, it is observed that as the capillary number increases, ganglia or blobs of displacing fluid are created at the displacement front in correspondence with the capillary numbers at which trapped ganglia are mobilized. This creation of ganglia at capillary numbers above 10 -3 was noted briefly in a previous paper 3 in which heptane displacing glycerine previous paper 3 in which heptane displacing glycerine was described. A secondary objective of this work was to test the Chuoke et al. theory for predicting the wavelength of fingers, wavelength being the peak-to-peak distance between adjacent well-developed fingers. Experimental Procedure The apparatus for these studies was described in Ref. 3. Basically, it consists of a slab of consolidated plastic particles 1.34 × 0.79 × 0.0 1 8 ft [0.44 × 0.26 × 0.006 m] with particles 1.34 × 0.79 × 0.0 1 8 ft [0.44 × 0.26 × 0.006 m] with a porosity of 0.43 and a permeability of 7, 100 darcies. This high permeability, when compared with that of reservoir rocks, should not be important for this study since capillary numbers and residual saturations are independent of pore size. Water (viscosity 1 cp [1 mPa s]) was used to displace paraffin oil (viscosity 68 cp 168 mPa s] at 77F [25C]). The water was dyed with methylene blue (which acts as a mild surfactant). Without the dye, the oil/water IFT was 42 dyne/cm [42 mN/m]. The addition of dye lowered this value to 36 dyne/cm [36 mN/m] for the concentration of dye used. For the surfactant flood, a 1 % sodium alkyl aryl sulfonate solution was used, giving a surfactant-solution/paraffin-oil IFT of 3.0 dyne/cm [3.0 mN/m]. Water Displacing Oil To compare our experiments with previous investigations of fingering, the displacement of paraffin oil by water at an average specific fluid discharge of 1.34 × 10–4 ft/sec [4.1 × 10 -5 m/s], corresponding to a capillary number of 7.7 × 10 -5, was studied (Fig. 1). Chuoke et al .4 and later Peters and Flock 2 have presented a formula for predicting the wavelength of presented a formula for predicting the wavelength of finger, lambda m : (2) where k is permeability, C is a dimensionless parameter which Peters and Flock call the wettability number and suggest would have the value 25 for an oil-wet porous medium, and mu o and mu ware viscosities of the displaced oil and displacing water, respectively. It was observed that the plastic particles of the porous medium considered here were oil wet because of adsorption of oil. SPEJ P. 325

Study of Enhanced-Oil-Recovery Mechanism of Alkali/Surfactant/Polymer Flooding in Porous Media From Experiments

SPE Journal ◽  
2009 ◽  
Vol 14 (02) ◽  
pp. 237-244 ◽  
Author(s):  
Pingping Shen ◽  
Jialu Wang ◽  
Shiyi Yuan ◽  
Taixian Zhong ◽  
Xu Jia
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Oil Recovery ◽  
Production Performance ◽  
Residual Oil ◽  
Flow Mechanism ◽  
Displacement Efficiency ◽  
High Permeability ◽  
Heterogeneous Reservoir ◽  
Asp Flooding

Summary The fluid-flow mechanism of enhanced oil recovery (EOR) in porous media by alkali/surfactant/polymer (ASP) flooding is investigated by measuring the production performance, pressure, and saturation distributions through the installed differential-pressure transducers and saturation-measurement probes in a physical model of a vertical heterogeneous reservoir. The fluid-flow variation in the reservoir is one of the main mechanisms of EOR of ASP flooding, and the nonlinear coupling and interaction between pressure and saturation fields results in the fluid-flow variation in the reservoir. In the vertical heterogeneous reservoir, the ASP agents flow initially in the high-permeability layer. Later, the flow direction changes toward the low- and middle-permeability layers because the resistance in the high-permeability layer increases on physical and chemical reactions such as adsorption, retention, and emulsion. ASP flooding displaces not only the residual oil in the high-permeability layer but also the remaining oil in the low- and middle-permeability layers by increasing both swept volume and displacement efficiency. Introduction Currently, most oil fields in China are in the later production period and the water cut increases rapidly, even to more than 80%. Waterflooding no longer meets the demands of oilfield production. Thus, it is inevitable that a new technology will replace waterflooding. The new technique of ASP flooding has been developed on the basis of alkali-, surfactant-, and polymer-flooding research in the late 1980s. ASP flooding uses the benefits of the three flooding methods simultaneously, and oil recovery is greatly enhanced by decreasing interfacial tension (IFT), increasing the capillary number, enhancing microscopic displacing efficiency, improving the mobility ratio, and increasing macroscopic sweeping efficiency (Shen and Yu 2002; Wang et al. 2000; Wang et al. 2002; Sui et al. 2000). Recently, much intensive research has been done on ASP flooding both in China and worldwide, achieving some important accomplishments that lay a solid foundation for the extension of this technique to practical application in oil fields (Baviere et al. 1995; Thomas 2005; Yang et al. 2003; Li et al. 2003). In previous work, the ASP-flooding mechanism was studied visually by using a microscopic-scale model and double-pane glass models with sand (Liu et al. 2003; Zhang 1991). In these experiments, the water-viscosity finger, the residual-oil distribution after waterflooding, and the oil bank formed by microscopic emulsion flooding were observed. In Tong et al. (1998) and Guo (1990), deformation, threading, emulsion (oil/water), and strapping were observed as the main mechanisms of ASP flooding in a water-wetting reservoir, while the interface-producing emulsion (oil/water), bridging between inner pore and outer pore, is the main mechanism of ASP flooding in an oil-wetting reservoir. For a vertical heterogeneous reservoir, ASP flooding increases displacement efficiency by displacing residual oil through decreased IFT, simultaneously improving sweep efficiency by extending the swept area in both vertical and horizontal directions. Some physical and chemical phenomena, such as emulsion, scale deposition, and chromatographic separation, occur during ASP flooding (Arihara et al. 1999; Guo 1999). Because ASP flooding in porous media involves many complicated physicochemical properties, many oil-recovery mechanisms still need to be investigated. Most research has been performed on the microscopic displacement mechanism of ASP flooding, while the fluid-flow mechanism in porous media at the macroscopic scale lacks sufficient study. In this paper, a vertical-heterogeneous-reservoir model is established, and differential-pressure transducers and saturation-measuring probes are installed. The fluid-flow mechanism of increasing both macroscopic sweep efficiency and microscopic displacement efficiency is studied by measuring the production performance and the variation of pressure and saturation distributions in the ASP-flooding experiment. An experimental database of ASP flooding also is set up and provides an experimental base for numerical simulation.

Enhanced Oil Recovery by Flooding With Dilute Aqueous Chemical Solutions

1981 ◽  
Vol 103 (4) ◽  
pp. 285-290 ◽  
Author(s):  
K. I. Kamath ◽  
S. J. Yan
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Recovery Process ◽  
Immiscible Displacement ◽  
Residual Oil ◽  
Oil Viscosity ◽  
Recovery Mechanism ◽  
Tertiary Oil Recovery ◽  
Hydrolyzed Polyacrylamide

The theory of enhanced oil recovery by surfactant flooding (micellarpolymer and “low-tension” floods) is based on three premises: that the chemical slug is 1) less mobile than the crude oil, 2) miscible with the reservoir fluids (oil and brine), and 3) stable over long periods of time (years) in the reservoir environment. We report here a rather simple process in which none of these expensive and exacting requirements have to be met. In this process, relatively small amounts of “EOR-active” substances present in certain petroleum-based sulfonates are found to recover 15–20 percent of the residual oil from waterflooded Berea sandstone cores. The chemicals are injected in the form of slugs of their aqueous solutions. If the chemical slugs are followed with similar slugs of additives such as partially hydrolyzed polyacrylamide, acrylamide monomer, urea, EDTA, or anions such as P2O7‴‴‴‴ and PO4‴‴‴, the oil recovery is increased 30–40 percent of the in-place residual oil. The concentrations of the “active” sulfonate and additive in their respective slugs appear to be of the order of 500 ppm or less. Extrapolation of the laboratory data to field conditions indicate that chemical requirements for the recovery of a barrel of tertiary oil are about 0.5–2 lb of sulfonate and a like amount of additive. The main features of the displacement process are: 1) Oil recovery is independent of oil viscosity in the tested range of 0.4–100 cps. 2) The process is essentially an immiscible displacement in which oil recovery depends on the amount of active chemical in the slug and not its concentration. 3) Tertiary oil is produced in the form of a clean “oil bank” and the buildup of a residual oil saturation at the producing end of linear cores occurs during the flood. From the data on hand, it is apparent that the oil recovery mechanism differs basically in character from the conventional Buckley-Leverett-type immiscible displacement. The low level concentrations of sulfonate and additive involved, and the independence of oil recovery with respect to oil viscosity suggest that the recovery mechanism is possibly actuated by certain specific functional groups in the structure of the EOR-active molecule or its anion, and of the additive. The results hold great potential for developing a simple and economical tertiary oil recovery process that can recover, very substantially, more oil (light as well as moderately viscous) than is now considered possible by conventional chemical floods.

scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

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