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Results
Laboratory Investigation on Impact of Gas Type on the Performance of Low-Tension-Gas Flooding in High Salinity, Low Permeability Carbonate Reservoirs
Monette, Matthew (The University of Texas at Austin) | Das, Alolika (The University of Texas at Austin) | Nasralla, Ramez (Shell Development Oman LLC) | Farajzadeh, Rouhi (Petroleum Development Oman LLC) | Shaqsi, Abdulaziz (Petroleum Development Oman LLC) | Nguyen, Quoc Phuc (The University of Texas at Austin)
Abstract Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity. LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type. High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali. The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.
- North America > United States (1.00)
- Asia (1.00)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract Alkaline-Surfactant-Polymer (ASP) flooding is an attractive enhanced oil recovery method. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability or other unfavorable conditions. Foam can be an alternative to polymer for improving the displacement efficiency in chemical-EOR process. The use of foam as a mobility control agent by co-injection or alternate injection of gas and chemical slug is termed, here, as Alkaline-Surfactant-Gas (ASG) Process. Foam reduces the relative permeability of the injected chemical slug that forms microemulsion at ultra-low oil-water interfacial tension (IFT) and generates sufficient viscous pressure gradient to drive the foamed chemical slug. The concept of ASG process as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. Polymer is replaced by foam in corefloods experiments as a mobility control agent. Phase behavior and ASG coreflood experiments were carried out to identify high performance chemicals, designed for both foaming and strong IFT reduction performance. The coreflood experiments were performed on sandstone and dolomite rock samples. Oil recovery and coreflood pressure response were evaluated to determine the success of the process. Different injection strategies for foam generation were investigated, and mechanisms of mobility control by foam were studied. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. Maximum recovery of 95% of remaining oil after waterflood was observed. Oil recovery and pressure responses from ASG experiments are comparable to ASP coreflood experiments carried out under similar conditions. Experimental data show a strong synergic effect of foam and ultra-low oil-water IFT on oil recovery. Compared to polymer, foam has lower cost associated with its use and is less susceptible to biological, shear, and thermal degradation. The use of foam in chemical EOR can reduce the technical disadvantages associated with polymer in low permeability and fractured reservoirs. Introduction Polymer is widely used for mobility control in enhanced oil recovery (EOR) processes. In Alkaline-Surfactant-Polymer (ASP) process, polymer provides mobility control during ASP slug and polymer drive injection. However, there are several disadvantages of using polymer. Some of the major disadvantages are: - High molecular weight polymers can plug rocks with very low permeability, or if a lower molecular weight polymer is used to avoid plugging, then the cost of using polymer increases and eventually becomes uneconomic. - Many of the commercially available EOR polymers can be unstable at high temperature. - Some polymers can mechanically degrade due to high shear stress through chokes or perforations at high flow rate. - There can be other problems with polymers under some conditions associated with unfavorable interactions with surfactants.
- North America > United States > Texas (0.29)
- North America > United States > Louisiana (0.28)
- North America > Canada > Alberta (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract Alkaline-surfactant-polymer (ASP) flooding using conventional alkali requires soft water. However, soft water is not always available, and softening hard brines may be very costly or infeasible in many cases depending on the location, the brine composition and other factors. For instance, conventional ASP uses sodium carbonate to reduce the adsorption of the surfactant and generate soap in-situ by reacting with acidic crude oils; however, calcium carbonate precipitates unless the brine is soft. A form of borax known as metaborate has been found to sequester divalent cations such as Ca++ and prevent precipitation. This approach has been combined with the screening and selection of surfactant formulations that will perform well with brines with high salinity and hardness. We demonstrate this approach in this paper by combining high performance, low cost surfactants with co-surfactants that increase salinity and hardness tolerance with metaborate. Chemical formulations containing surfactants and alkali in hard brine were screened for performance and tolerance using microemulsion phase behavior experiments and crude at reservoir temperature. A formulation was found that with an optimum salinity of 120,000 ppm TDS (with 6600 ppm divalent cations) that performed well in core floods with high oil recovery and almost zero final chemical flood residual oil saturation. Additionally, chemical formulations containing sodium metaborate and hard brine gave nearly 100% oil recovery, with no indication of precipitate formation. Metaborate chemistry was incorporated into the mechanistic UTCHEM simulator and the simulator was then used to model the core floods. Overall, novel ASP with metaborate performed comparable to conventional ASP using sodium carbonate in soft water, demonstrating advancements in ASP adaptation to hard, saline reservoirs without the need for soft brine, which increases the number of oil reservoirs that are candidates for enhanced oil recovery using ASP flooding. Introduction This paper describes a laboratory and modeling approach to ASP flooding in reservoirs containing very hard, saline brines without the need for soft brine. Our target reservoir is a low temperature (50 °C), light oil (API 45) sandstone reservoir containing hard, saline formation brine with 157,000 mg/L TDS salinity of which 8600 mg/L are Ca++ and Mg++. Our objective was to design an ASP slug to use as much of the formation brine as possible and eliminate the need for soft water. We show that a novel alkali, sodium metaborate, can provide tolerance to high divalent cation concentrations, which the conventional alkali sodium carbonate cannot. Our laboratory approach uses quick, inexpensive microemulsion phase behavior experiments to screen chemical formulations for both performance and tolerance to salinity and hardness. Well performing formulations are validated for good oil recovery and other criteria using prepared Berea sandstone cores saturated with very hard, saline brine at residual oil saturation. Experimental data containing metaborate were modeled using UTCHEM, a chemical flooding compositional simulator developed by The University of Texas at Austin. UTCHEM is a three-dimensional multiphase, multicomponent, mechanistic simulator that can considers three liquid phases (aqueous, oleic, and microemulsion) formed from a number of chemical species (such as water, oil, surfactant, polymer, alkali, electrolytes). Metaborate chemistry was added to UTCHEM to model chemical reactions such as precipitation, dissolution, consumption, sequestration and ion exchange reactions of the metaborate components during ASP flooding with hard brine. UTCHEM is capable of modeling soap generation from alkali reaction with acidic components in crude oil; however, this crude oil was found to be non-reactive with alkali. Experimental phase behavior data were matched to obtain critical model parameters used in the chemical flood simulations and needed to explain performance changes with salinity. The simulations were useful for understanding changes in pH, electrolyte concentrations and other important details within the cores during the chemical floods.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.67)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract We present a systematic study of laboratory tests of alternative chemical formulations for a chemical flood design and application. Aqueous and microemulsion phase behavior tests have previously been shown to be a rapid, inexpensive and highly effective means to select the best chemicals and minimize the need for relatively expensive core flood tests. Microemulsion phase behavior testing was therefore conducted using various combinations of surfactants, co-solvents and alkalis with a particular crude oil and reservoir conditions of interest. Branched alcohol propoxy sulfates and internal olefin sulfonates showed high performance in these tests, even when mixed with both conventional and novel alkali agents. Systematic screening methods helped tailor and fine-tune chemical mixtures to perform well under the given design constraints. The best chemical formulations were validated in core flood experiments, and compared in terms of both oil recovery and surfactant retention in cores. Each of the four best formulations tested in core floods gave nearly 100% oil recovery and very low surfactant adsorption. The two formulations with conventional and novel alkali agents gave almost zero surfactant retention. In standard practice, soft water must be used with alkali, but we show how ASP flooding can be used in this case even with very hard, saline brine. Introduction Many mature reservoirs under water flood have low economic production rates despite having as much as 50 - 75% of the original oil still in place. These reservoirs are viable candidates for chemical enhanced oil recovery (EOR) that uses both surfactant to reduce oil-water interfacial tension (IFT) and polymer to improve sweep efficiency. However, designing these aqueous chemical mixtures is complex, and must be tailored to the reservoir rock and fluid (i.e. crude oil and formation brine) properties of the application. A strategic design methodology can help provide a low cost, well-performing chemical formulation, even for challenging and problematic reservoir properties. Additionally, furthering laboratory and field-testing in this area contributes to an expanding research database to help broaden reservoir types that can become candidates for routine chemical EOR application. This paper describes a systematic laboratory approach to low cost, high performance chemical flooding, and explores novel approaches to alkali-surfactant-polymer (ASP) flooding in reservoirs containing very hard, saline brines. The design strategy first uses microemulsion phase behavior experiments to quickly select and optimize concentrations of injected chemicals. Assessment of formula optimization strategies are carried out through varying surfactant-to-co-surfactant ratio, reducing co-solvent concentration, reducing total surfactant concentration, selecting a suitable alkali, and utilizing formation brine in the injection mixture. Formulations performing well in phase behavior are validated in core flood experiments that adhere to necessary design criteria such as pressure and salinity gradients, surfactant adsorption, and capillary effects. We illustrate the application of our design approach in prepared Berea sandstone cores previously water flooded with very hard, saline brine, and show how ASP flooding can use some of the same brine in the chemical formulation. Conventional ASP flooding requires soft water that may not always be available, and softening hard brines can be very costly or infeasible in many cases depending on the location and other factors. These new results demonstrate high tolerance to both salinity and hardness of the high performance surfactants, and how novel alkalis, in particular sodium metaborate, can provide similar benefits in such harsh environments as sodium carbonate has shown in environments without divalent cations. This experimental success begins to vastly increase the range of conditions for economical enhanced oil recovery using chemicals.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract CO2 injection has become the most attractive solution for enhanced oil recovery (EOR). However, this process frequently suffers from viscous fingering, gravity override, and channeling of CO2 in heterogeneous formations and the inefficient displacement of oil in below-miscibility-pressure reservoirs. These challenging issues are closely related to the very limited ability to control CO2 mobility. CO2 foam stabilized with CO2 soluble surfactants has exhibited more economical and technical advantages in effective control of CO2 mobility in porous media than the existing direct methods of CO2 viscosification. An integrated research framework was developed to strengthen the role of molecular design for these features as wells as provide a better understanding of foam behavior with complex formation of viscous water/oil or oil/water emulsions. A simple block model was developed in CMG/STARS to demonstrate the advantages of the novel foam concept over the conventional foam processes in the field. We proposed a novel injection strategy which involves dissolving the surfactant in the CO2. This method drastically lowers the injection costs, reduces the loss of surfactant onto the rock surface due to adsorption, and improves in-situ foam generation to significantly increase oil recovery. Two different novel methods, continuous CO2-dissolved-surfactant injection and water-alternating-gas with CO2-dissolved-surfactant injection, have been studied in this paper. Foam corefloods performed with carbonate core show that CO2-dissolved surfactants greatly reduce the mobility of the injected gas compared to conventional injection strategies. This is consistently observed in the numerically simulated foam process at the field level. Introduction CO2 flood have been applied worldwide as a routine EOR technology, particularly for reservoir candidates whose pressures are above minimum miscibility pressure (MMP). However, reservoir heterogeneity and high gas mobility reduce sweep efficiency and drastically decrease oil recovery (Renkema and Rossen, 2007). For formations with relatively high vertical permeability and vertical well pattern, the injected CO2 tends to rise to the top of the reservoir due to its low density and overrides the bottom oil-rich zone, leading to early gas breakthrough. CO2 displacement could be improved by water-alternating gas (WAG) injection. The efficiency of this process relies on the ability to reduce gas relative permeability in the presence of the aqueous phase and to promote gas trapping in depleted zones that diverts both the injected gas and water into the oil-rich zones. However, WAG injection has frequently encountered some important issues such as the reduction of CO2-oil contact in the presence of water and low injectivity commonly observed in carbonate reservoirs. Gravity segregation tends to impair further the advantages of this injection strategy. This has inspired the application of surfactant stabilized CO2 foam to improve CO2 conformance as foam could generate not only a large amount of stable trapped gas but also a significantly high local pressure gradients induced by aqueous foam films that disperse the gas phase.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (34 more...)
Chemical Flooding of Fractured Carbonates Using Wettability Modifiers
Najafabadi, Nariman Fathi (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin) | Nguyen, Quoc Phuc (The University of Texas at Austin) | Zhang, Jieyuan
Abstract Waterfloods performed in carbonate and naturally fractured reservoirs frequently suffer from relatively poor sweep efficiency by virtue of geological heterogeneity and preferentially oil-wet rock surface commonly seen in these reservoirs. The application of chemical-based wettability modification in such problematic formations has become one of the most potential enhanced oil recovery techniques for the worldwide abundance of fractured carbonates with significant amount of remaining oil. Chemical stimulation with surfactant or electrolyte to alter the wettability towards more water-wetness has the potential to enhance water imbibition to expel more oil from matrix to the fractures. The countercurrent interaction at matrix-fracture interface involves interplay of capillary, gravitational and viscous forces. A clear understanding of these processes is required for an optimum oil recovery design and field implementation in fractured carbonate reservoirs. To this end, we have developed a systematic experimental and modeling approach on the combined benefit of wettability alteration for enhanced water imbibition and interfacial tension reduction. Both natural and forced imbibition experiments were performed in mixed-wet rocks where oil volume produced was recorded for sequential injection of water, alkali, and surfactant/alkali mixture. The alkali was effective in wettability modification and enhanced water imbibition. Additional oil was recovered by injection of surfactant/alkali mixture following alkali injection due to interfacial tension reduction and oil mobilization. A wettability alteration model based on these mechanisms was developed and implemented in a compositional chemical flooding simulator. The experiments were successfully modeled with the enhanced simulator. A better understanding of mechanisms involved in improved recovery of oil from fractured carbonates using wettability modifier will aid in identifying and implementing future field demonstration projects. Introduction A large quantity of world's oil reserves is contained in carbonate reservoirs (Roehl and Choquette, 1985). Most of these reservoirs are naturally fractured. The fracture network normally has much higher permeability than that of porous matrix, accounting for poor primary oil recovery. Waterflooding would be an effective method for improvement of oil recovery from water-wet fractured reservoirs, where spontaneous imbibition of the injected water is known to be the main recovery mechanism. Unfortunately, about 80% of carbonate rocks are mixed-wet to preferentially oil-wet (Downs and Hoover, 1989) which are unfavorable conditions for spontaneous water imbibition. Hirasaki and Zhang (2004) refer to "Imbibition" as the process of water displacing oil and "Spontaneous Imbibition" as imbibition that takes place under the influence of capillary or buoyancy forces when a core sample or matrix block is surrounded by aqueous phase. At high interfacial tension (IFT) the main driving force for spontaneous imbibition is capillary pressure. Morrow and Mason (2001) studied the rate of capillary pressure driven imbibition for different wettability conditions.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Summary We present the first 1D simulations of dynamic foam displacements with a population-balance model incorporating bubble creation controlled by pressure gradient. For the first time, a population-balance model is fit to steady-state experimental data for both the three foam states (coarse foam, intermediate, and strong foam) and the two strong-foam regimes (low-quality and high-quality) observed in laboratory studies. Simulations confirm the stability of the coarse-foam and strong-foam states to small perturbations, and the instability of the intermediate state, at fixed injection rates. In dynamic displacements, the model shows foam generation as injection rates increase, or as liquid fraction of injected fluids increases, in agreement with laboratory observations. When coarse foam is created instead of strong foam, there is a narrow region of finer foam predicted near the gas displacement front. This region appears to play a role in foam generation. However, in the limited cases examined here, foam generation occurs at roughly the same injection rate as predicted by local-steady-state theory. Because of this narrow region of finer-textured foam, fronts can be sharper than estimated from fractional-flow theory assuming a constant effective gas viscosity at its steady-state value behind the displacement front. If a strong foam forms in the low-quality regime, the kinetics of foam generation and destruction affects the length of the entrance region in which foam forms. Therefore, the length of the entrance region can be used to calibrate the kinetic parameters in the model. The displacement front and the bank behind it, however, are essentially what one would have predicted from local-steady-state modeling. The complexities of population-balance modeling are not necessary, if it is known that strong foam will be created. Introduction Foam can improve sweep efficiency in gas-injection improved oil recovery (IOR) processes (Schramm 1994; Rossen 1996; Terdre 2003), redirect acid flow in matrix acid stimulation (Gdanski 1993; Cheng et al. 2002; Nguyen et al. 2003), and increase the efficiency of environmental remediation of aquifers (Hirasaki et al. 2000; Mamun et al. 2002). A continuing goal of foam research is the development of a fully mechanistic, predictive model. This paper describes efforts toward such a model and insights gained from application of the model to dynamic displacements. Before providing a detailed description of the model, it is worthwhile to review the mechanisms of foam in porous media and the experimental observations that the model attempts to reproduce.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Does Polymer Stabilize Foam in Porous Media?
Shen, Chun | Nguyen, Quoc Phuc | Huh, Chun (U. of Texas Austin) | Rossen, William Richard (U. of Texas Austin)
Abstract Addition of polymer has been proposed as a way to stabilize foam, especially in the presence of oil. This study probes the putative stabilizing effect of polymer on foam in terms of steady-state properties. Specifically, we tested the effect of polymer addition on the two steady-state foam regimes identified by Alvarez et al. (SPEJ, 2001). For the two polymers (xanthan and partially hydrolyzed polyacrylamide), two oils (decane and 37.5º API crude oil), and an alpha-olefin sulfonate surfactant, it appears from coreflood pressure gradient that polymer destabilizes foam modestly, raising water saturation and water relative permeability. The increased viscosity of the aqueous phase with polymer counteracts the effects of destabilization of foam. For the same polymers and surfactant, polymer does not stabilize foam in the presence of decane or 37.5º API crude oil relative to foam without polymer. Surface-tension measurements with these polymers and surfactant likewise showed no evidence of presence of polymer at the air-water interface that might stabilize foam lamellae between bubbles. This suggests that, for similar polymers and surfactants, addition of polymer would not give stronger foam in field application or stabilize foam against the presence of crude oil. Complex behavior, some of it in contradiction to the expected two steady-state foam regimes, was observed. At the limit of, or in the place of, the high-quality regime, there was sometimes an abrupt jump upwards in pressure gradient as though from hysteresis and a change of state. In the low-quality regime, pressure gradient was not independent of liquid superficial velocity, but decreased with increasing liquid superficial velocity, as previously reported and explained by Kim et al. (SPEJ, 2005). Introduction Foam is a dispersion of gas in liquid stabilized by surfactant. It is used for mobility control in EOR (Rossen, 1996), acid diversion in well stimulation (Gdanski, 1993; Rossen and Wang, 1999) and recovery of wastes in environmental remediation (Hirasaki et al., 2000; Mamun et al., 2002). However, foam has a limited lifetime. One proposed solution is the use of polymer in conjunction with surfactant solution to improve foam properties. It is a familiar observation that polymer increases liquid viscosity and slows the rate of liquid drainage from bulk foam. Whether polymer stabilizes foam in porous media, where water drains rapidly from one pore to the next driven by capillary forces, not gravity, is not clear. In this paper we investigate the effect of polymer additives on the stability of foams made from AOS surfactant. Coreflood experiments have been run with both conventional and polymer-enhanced foam, without and with oil in sandpacks and Boise sandstone.
- North America > United States > Texas (0.93)
- North America > United States > Idaho > Ada County > Boise (0.27)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract Foam flow in porous media plays an important role in oil and gas recovery. Besides experimental studies, the prediction of foam behavior in the applications relies on macroscopic modeling. In this paper, we present a numerical analysis of foam flow in porous media using a new stochastic bubble population (SBP) model. We also present a sensitivity analysis to the main parameters. The idea that foam flow in porous media can be described as a stochastic process emerged from recent studies of foam flow through porous media using X-ray computed tomography (CT). The model is simple as it describes the bubble generation using mainly two parameters, the maximum bubble density and a foam generation constant. It is also robust because it grasps the essence of foam physics in homogeneous porous media. A good qualitatively agreement exists between the numerical predictions and the water saturation profiles obtained from the CT scan experiments. Introduction Over the last decades, foam has been widely used as a mobility control agent in Enhanced Oil Recovery (EOR),[1–4] gas blocking[5] and acid diversion during matrix stimulation.[2] Foam remains one of the best EOR options, especially in maturing reservoirs. Besides experimental studies, the description of foam behavior in porous media relies on macroscopic modeling. Among the existing foam modeling approaches, the most documented ones are the fractional flow and the population balance models. The foam fractional flow modeling was initiated by Rossen and et al..[2,6,7] It assumes implicitly that foam is incompressible. This approach is valid when pressure variations are small, compared with the reference pressure (backpressure). The classical fractional flow models do not account explicitly for the evolution of bubble population and, therefore, might not be accurate when describing transient foam motion. The population balance approach introduced by Patzek[8] and further elaborated by Kovscek et al.[3,9–11] and Falls et al.,[12] starts from the principle that foam mobility depends on the bubble density (number of bubbles per unit gas volume). The population balance model splits gas saturation into flowing and trapped fractions. Although this appears to be in agreement with the early experimental work of Bernard et al.[13,14] and Holm,[15,16] it turns out to be disadvantageous, as it leads to the introduction of parameters that may be difficult to determine experimentally. The petroleum community, therefore, perceives the population balance models as being comprehensive but complex. Recently Zitha[17] developed an alternative population balance theory for foam motion in porous media (other paper in this conference). The theory is build upon the following basic postulates:Foam is a complex fluid, characterized by a yield stress and, above the yield stress, by a power law behavior; its rheology is described using the Herschel-Bulkley model. Foam rheology depends essentially on the bubble density (number of bubbles per unity volume of porous medium). Finally, on the macroscopic level, we can treat the bubble generation as a stochastic process; we describe the kinetics of foam generation using a simple exponential growth function. The bubble generation involves essentially two parameters that are in principle easier to determine experimentally. During foam development, we expect the bubble density to be small. From the above it follows therefore that, the yield stress of foam is low and, consequently, foam trapping is unlikely.[17] Hence, in the model for foam propagation, foam trapping is not taken into account. This is in good agreement with foam experiments performed using X-ray computed tomography (CT).]18–22] These experiments showed no evidence of gas trapping during co-injection of gas and a surfactant solution in sandstone cores containing surfactant solution (transient foam flow). The new stochastic bubble population model lies therefore upon a more realistic picture of foam physics. The model is simpler and more robust because bubble generation depends only on two unknown parameter.
- North America > United States > Texas (0.93)
- Asia (0.68)
- Research Report > New Finding (0.74)
- Research Report > Experimental Study (0.74)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)