Surfactant-alternating-gas Process Research Articles

Effect of Gas Composition on Surfactant Injectivity in a Surfactant-Alternating-Gas Foam Process.

Aqueous foam is a dispersion of gas in liquid, where the liquid acts as the continuous phase and the gas is separated by thin liquid films stabilized by a surfactant. Foam injection is a widely used technique in various applications, including CO2 sequestration, enhanced oil recovery, soil remediation, etc. Surfactant-alternating-gas (SAG) is a preferred approach for foam injection, and injectivity plays a vital role in determining the efficiency of the SAG process. Different gases can be applied depending on the process requirements and availability. However, the underlying mechanisms by which gas composition impacts injectivity are not yet fully understood. In this work, the effect of gas composition on fluid behavior and injectivity in a SAG process was investigated using three gases: N2, CO2, and Kr. Our observations revealed that gas solubility in liquid was key for the formation and evolution of liquid fingers, and therefore was very important for liquid injectivity. A lower gas solubility in liquid led to a slower increase in surfactant solution injectivity. In addition, the development of surfactant solution injectivity took significantly longer when the surfactant solution was partially pre-saturated compared to when it was unsaturated. Additionally, the propagation of the collapsed-foam bank during gas injection was accelerated when the gas had a greater solubility in water.

Liquid injectivity in a SAG foam process: Effect of permeability

Foam is utilized in enhanced oil recovery and CO2 sequestration. Surfactant-alternating-gas (SAG) is a preferred approach for placing foam into reservoirs, due to it enhances gas injection and minimizes corrosion in facilities. Our previous studies with similar permeability cores show that during SAG injection, several banks occupy the area near the well where fluid exhibits distinct behaviour. However, underground reservoirs are heterogeneous, often layered. It is crucial to understand the effect of permeability on fluid behaviour and injectivity in a SAG process. In this work, coreflood experiments are conducted in cores with permeabilities ranging from 16 to 2300 mD. We observe the same sequence of banks in cores with different permeabilities. However, the speed at which banks propagate and their overall mobility can vary depending on permeability. At higher permeabilities, the gas-dissolution bank and the forced-imbibition bank progress more rapidly during liquid injection. The total mobilities of both banks decrease with permeability. By utilizing a bank-propagation model, we scale up our experimental findings and compare them to results obtained using the Peaceman equation. Our findings reveal that the liquid injectivity in a SAG foam process is misestimated by conventional simulators based on the Peaceman equation. The lower the formation permeability, the greater the error.

Experimental and simulation investigations of carbon storage associated with CO2 EOR in low-permeability reservoir

CO2 based water-alternating-gas (WAG) injection and surfactant-alternating-gas (SAG) injection have shown to be two effective and practical methods to enhance oil recovery, which, also achieves carbon sequestration as well. In this study, a combination of experiment and numerical simulation was used to evaluate the performances of WAG and SAG flooding in low-permeability reservoir. Core drainage experiments were conducted, and NMR equipment was used to reveal the microscopic fluid distribution and explain the macroscale drainage results for each of the enhancing oil recovery (EOR) technique. In addition, the two EOR techniques were further evaluated in a realistic low-permeability reservoir, Yushulin oil field from Songliao Basin, China. The results show that, gas phase can lower gas-oil interfacial tension (IFT) in WAG process which contributes the oil displacement from smaller pores. Besides that, the surfactant in SAG process can also improve the oil displacement efficiency in larger pores due to the generation of foams. The optimal WAG and SAG ratios (1.25–1.5) in the realistic reservoir are all higher than the typical ratio (equal to 1) from the core experimental results and that in the most conventional oilfields due to the higher heterogeneity in low-permeability reservoir with easier gas breakthrough. Furthermore, the CO2 utilization efficiency for SAG is higher than WAG.

Effect of superficial velocity on liquid injectivity in SAG foam EOR. Part 2: Modelling

Surfactant-alternating-gas (SAG) is a favored method of foam injection, which has been proved as an efficient way for enhancing oil recovery. However, foam flow is extremely complicated, and there are still unsolved problems for foam application. One is liquid injectivity. Our previous studies suggest that the injectivity in a SAG process is determined by propagation of several banks near the injection well that are not represented by current foam models. Uniform bank properties were assumed. However, in a companion paper, our experimental results show that the dimensionless propagation velocity and the total mobility of banks during the liquid-injection period depends on superficial velocity. Shearing-thinning behavior is observed. In radial flow, the superficial velocity varies with distance from the well. In this study, we scale-up the experimental results using a radial bank-propagation model. The comparison of liquid injectivity estimated from conventional foam simulators (Peaceman equation) and the bank-propagation model show that the conventional foam models cannot represent the effect of the superficial-velocity-dependent fluid properties during liquid injection in a SAG process. The shear-thinning behavior can lead to much better liquid injectivity than expected, which should be accounted for in a field application of a SAG foam process.

Effect of superficial velocity on liquid injectivity in SAG foam EOR. Part 1: Experimental study

Surfactant-alternating-gas (SAG) is a preferred method of foam injection, which is a promising means of enhanced oil recovery. Liquid injectivity in a SAG process is commonly problematic. Our previous studies suggest that the liquid injectivity can be better than expected due to the existence of a collapsed-foam region formed during the gas-injection period ahead of the liquid-injection period. A single superficial velocity was used in those studies to examine the flow behavior during gas- and liquid-injection periods, separately. However, in radial flow from an injection well, superficial velocity decreases with distance from the injection well. Understanding the effect of superficial velocity on gas and liquid injectivities is important, but remains unexplored. In this study, we first examine gas injection at different superficial velocities following foam injection. We then study the effect of liquid superficial velocity on the liquid injectivity following a similar volume of gas injection. Our results show that during a prolonged period of gas injection following foam, the propagation velocity and the total mobility of the collapsed-foam bank are not significantly affected by the gas superficial velocity. During liquid injection after a period of gas injection, the dimensionless propagation velocities and the total mobilities of the forced-imbibition bank and the gas-dissolution bank follow a power-law dependence on the liquid superficial velocity. Liquid fingering through the weakened-foam region shows strongly shear-thinning behavior. It is also observed from X-ray computer-tomography experiments that the liquid fingers are wider if the liquid superficial velocity is greater. The impact of the shear-thinning behavior on the estimation of liquid injectivity in a field application is the subject of a companion paper.

Scaleup of Laboratory Data for Surfactant-Alternating-Gas Foam Enhanced Oil Recovery

SummaryFoam increases sweep efficiency during gas injection in enhanced oil recovery processes. Surfactant alternating gas (SAG) is the preferred method to inject foam for both operational and injectivity reasons. Dynamic SAG corefloods are unreliable for direct scaleup to the field because of core-scale artifacts. In this study, we report fit and scaleup local-equilibrium (LE) data at very-low injected-liquid fractions in a Bentheimer core for different surfactant concentrations and total superficial velocities.We fit LE data to an implicit-texture foam model for scaleup to a dynamic foam process on the field scale using fractional-flow theory. We apply different parameter-fitting methods (least-squares fit to entire foam-quality scan and the method of Rossen and Boeije 2015) and compare their fits to data and predictions for scaleup. We also test the implications of complete foam collapse at irreducible water saturation for injectivity.Each set of data predicts a shock front with sufficient mobility control at the leading edge of the foam bank. Mobility control improves with increasing surfactant concentration. In every case, scaleup injectivity is much better than with coinjection of gas and liquid. The results also illustrate how the foam model without the constraint of foam collapse at irreducible water saturation (Namdar Zanganeh et al. 2014) can greatly underestimate injectivity for strong foams.For the first time, we examine how the method of fitting the parameters to coreflood data affects the resulting scaleup to field behavior. The method of Rossen and Boeije (2015) does not give a unique parameter fit, but the predicted mobility at the foam front is roughly the same in all cases. However, predicted injectivity does vary somewhat among the parameter fits. Gas injection in a SAG process depends especially on behavior at low injected-water fraction and whether foam collapses at the irreducible water saturation, which may not be apparent from a conventional scan of foam mobility as a function of gas fraction in the injected foam. In two of the five cases examined, this method of fitting the whole scan gives a poor fit for the shock in gas injection in SAG. We also test the sensitivity of the scaleup to the relative permeability krw(Sw) function assumed in the fit to data.There are many issues involved in scaleup of laboratory data to field performance: reservoir heterogeneity, gravity, interactions between foam and oil, and so on. This study addresses the best way to fit model parameters without oil for a given permeability, an essential first step in scaleup before considering these additional complications.

Fractional-Flow Theory for Non-Newtonian Surfactant-Alternating-Gas Foam Processes

Foam can improve sweep efficiency in gas-injection-enhanced oil recovery. Surfactant-alternating-gas (SAG) is a favored method of foam injection. Laboratory data indicate that foam can be non-Newtonian at low water fractional flow fw, and therefore during gas injection in a SAG process. We investigate the implications of this finding for mobility control and injectivity, by extending fractional-flow theory to gas injection in a non-Newtonian SAG process in radial flow. We make most of the standard assumptions of fractional-flow theory (incompressible phases, one-dimensional displacement through a homogeneous reservoir, instantaneous attainment of local equilibrium), excluding Newtonian mobilities. For this initial study, we ignore the effect of changing or non-uniform oil saturation on foam. Non-Newtonian behavior at low fw implies that the limiting water saturation for foam stability varies as superficial velocity decreases with radial distance from the well. We discretize the domain radially and perform Buckley–Leverett analysis on each narrow increment in radius. Solution characteristics move outward with fixed fw. We base the foam model parameters and non-Newtonian behavior on laboratory data in the absence of oil. We compare results to mobility and injectivity determined by conventional simulation, where grid resolution is usually limited. For shear-thinning foam, mobility control improves as the foam front propagates from the well, but injectivity declines somewhat with time. This change in mobility ratio is not that at steady state at fixed water fractional flow in the laboratory, however, because the shock front in a non-Newtonian SAG process does not propagate at fixed fractional flow (though individual characteristics do). Moreover, the shock front is not governed by the conventional condition of tangency to the fractional-flow curve, though it continually approaches this condition. Injectivity benefits from the increased mobility of shear-thinning foam near the well. The foam front, which maintains a constant dimensionless velocity for Newtonian foam, decelerates somewhat with time for shear-thinning foam. For shear-thickening foam, mobility control deteriorates as the foam front advances, though injectivity improves somewhat with time. Overall, however, injectivity suffers from reduced foam mobility at high superficial velocity near the well. The foam front accelerates somewhat with time. Conventional simulators cannot adequately represent these effects, or estimate injectivity accurately, in the absence of extraordinarily fine grid resolution near the injection well.

An Empirical Model to Estimate Sweep Efficiency of a Surfactant-Alternating-Gas Foam Process in Heterogeneous Reservoirs

A surfactant-alternating-gas (SAG) process is a promising enhanced oil recovery (EOR) method for tight oil reservoirs. In this study, an empirical model is developed to predict the dynamic performance of a SAG process including sweep efficiency of multiple types of well patterns, in which major factors of the SAG process are involved, including gas channeling, reservoir heterogeneity, gravity segregation, and the instability of a foam structure. A novel empirical model is proposed to estimate the recovery factor of a SAG process in typical well patterns, which divides the whole area into three parts based on dominate occupation in situ fluids. Estimating the breakthrough time of each area is the key of this model. A new concept pseudomobility ratio is proposed to convert the negative effect of heterogeneity into unfavorable increment of mobility ratio. Numerical simulation studies are introduced to validate the proposed SAG empirical model. The comparison shows that the SAG performance model is highly consistent with the numerical simulation results calculated by cmg. Sensitivity analysis is introduced to study the effects of variables in the SAG process, including the fluid injection rate, slug size, slug proportion, and reservoir heterogeneity. Oil production estimated by the proposed model is also validated with field production data collected from the Ganguyi SAG project in China, and the growth trend of oil production agrees well with the field data. The proposed model provides a fast approach to predict the dynamic performance of SAG flooding in a field scale, which can be used as a tool to evaluate and optimize current operational parameters.

Laboratory Investigation of Liquid Injectivity in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery

Surfactant-alternating-gas (SAG) is a favored method of foam injection, in part because of excellent gas injectivity. However, liquid injectivity is usually very poor in SAG. We report a core-flood study of liquid injectivity under conditions like those near an injection well in SAG application in the field, i.e., after a prolonged period of gas injection following foam. We inject foam [gas (nitrogen) and surfactant solution] into a 17-cm-long Berea core at temperature of 90 °C with 40 bar back pressure. Pressure differences are measured and supplemented with CT scans to relate water saturation to mobilities. Liquid injectivity directly following foam is very poor. During prolonged gas injection following foam, a collapsed-foam region forms near the inlet and slowly propagates downstream, in which water saturation is reduced. This decline in liquid saturation reflects in part liquid evaporation, also pressure-driven flow and capillary effects on the core scale. In the collapsed-foam region, liquid mobility during subsequent liquid injection is much greater than downstream, and liquid sweeps the entire core cross section rather than a single finger. Mobility in the region of liquid fingering is insensitive to the quality of foam injected before gas and the duration of the period of gas injection. This implies that at the start of liquid injection in a SAG process in the field, there is a small region very near the well, crucial to injectivity, substantially different from that further out, and not described by current foam models. The results can guide the development of a model for liquid injectivity based on radial propagation of the various banks seen in the experiments.

Foam Diversion in Heterogeneous Reservoirs: Effect of Permeability and Injection Method

SummaryFoam can divert flow from higher- to lower-permeability layers and thereby improve the injection profile in gas-injection enhanced oil recovery (EOR). This paper compares two methods of foam injection, surfactant-alternating-gas (SAG) and coinjection of gas and surfactant solution, in their abilities to improve injection profiles in heterogeneous reservoirs. We examine the effects of these two injection methods on diversion by use of fractional-flow modeling. The foam-model parameters for four sandstone formations ranging in permeability from 6 to 1,900 md presented by Kapetas et al. (2015) are used to represent a hypothetical reservoir containing four noncommunicating layers.Permeability affects both the mobility reduction of wet foam in the low-quality-foam regime and the limiting capillary pressure at which foam collapses. The effectiveness of diversion varies greatly with the injection method. In a SAG process, diversion of the first slug of gas depends on foam behavior at very-high foam quality. Mobility in the foam bank during gas injection depends on the nature of a shock front that bypasses most foam qualities usually studied in the laboratory. The foam with the lowest mobility at fixed foam quality does not necessarily give the lowest mobility in a SAG process. In particular, diversion in SAG depends on how and whether foam collapses at low water saturation; this property varies greatly among the foams reported by Kapetas et al. (2015). Moreover, diversion depends on the size of the surfactant slug received by each layer before gas injection. This favors diversion away from high-permeability layers that receive a large surfactant slug. However, there is an optimum surfactant-slug size: Too little surfactant and diversion from high-permeability layers is not effective, whereas with too much, mobility is reduced in low-permeability layers. For a SAG process, injectivity and diversion depend critically on whether foam collapses completely at irreducible water saturation.In addition, we show the diversion expected in a foam-injection process as a function of foam quality. The faster propagation of surfactant and foam in the higher-permeability layers aids in diversion, as expected. This depends on foam quality and non-Newtonian foam mobility and varies with injection time. Injectivity is extremely poor with foam injection for these extremely strong foams, but for some SAG foam processes with effective diversion it is better than injectivity in a waterflood.

Simulation of instabilities and fingering in surfactant alternating gas (SAG) foam enhanced oil recovery

Gas-injection enhanced oil recovery (EOR) has good displacement efficiency but poor sweep efficiency. Foam can improve sweep efficiency in these processes, but its direct injection would not be practical due to its poor injectivity. Field results suggest that the well injectivity can be improved if gas and surfactant solution are injected in alternating slugs, leading to foam creation inside porous medium as gas and surfactant intermingle in situ. This process, referred to as Surfactant Alternating Gas (SAG), aims at reducing gas mobility at the displacement front. Behind the front, because of low water saturation, foam collapses (partially or completely); thus, gas mobility gradually increases to its original mobility at the injection well. This can potentially lead to fingering of the highly-mobile gas into the region with low-mobility gas in the form of foam.To the best of our knowledge this phenomenon has not been investigated in the literature, apparently due to poor grid resolutions employed in the numerical simulations and/or focus on other parameters, from which it is difficult to infer instabilities. In this paper we use an implicit-texture foam model to simulate a SAG process with fine grid resolution. The magnitude of the instabilities decreases with weaker foam, coarser grid resolution, increasing diffusion, and inclusion of capillary pressure, suggesting that fingering reflects the intrinsic physics of the process: it is not a numerical artifact.In a successful SAG process, as long as there is enough surfactant ahead of the gas bank to form a region with low mobility, the fluid ahead of it is efficiently displaced (i.e., stable front exists). In numerical simulations, however, there are extremely low discrete mobility values in grid blocks located at the front. In such a process, there can be fingering within the foam bank (unstable displacement), while the foam front itself appears relatively stable. Further studies are required to verify the extent to which simulations of fingering reflect numerical artifacts at the front. These results have practical implications, especially in calculation of the well injectivity and design of optimum slug size and foam strength in a SAG process.

Comparison of oil removal in surfactant alternating gas with water alternating gas, water flooding and gas flooding in secondary oil recovery process.

Growing oil prices coupled with large amounts of residual oil after operating common enhanced oil recovery methods has made using methods with higher operational cost economically feasible.Nitrogen is one of the gases used in both miscible and immiscible gas injection process in oil reservoir. In heterogeneous formations gas tends to breakthrough early in production wells due to overriding, fingering and channeling. Surfactant alternating gas (SAG) injection is one of the methods commonly used to decrease this problem. Foam which is formed on the contact of nitrogen and surfactant increases viscosity of injected gas. This increases the oil–gas contact and sweep efficiency, although adsorption of surfactant on rock surface can causes difficulties and increases costs of process. Many parameters must be considered in design of SAG process. One of the most important parameters is SAG ratio that should be in optimum value to improve the flooding efficiency.In this study, initially the concentration of surfactant was optimized due to minimization of adsorption on rock surface which results in lower cost of surfactant. So, different sodium dodecyl sulfate (SDS) concentrations of 100, 500, 1000, 2000, 3000 and 4000 ppm were used to obtain the optimum concentration at 70 °C and 144.74×105 Pa. A simple, clean and relatively fast spectrophotometric method was used for determination of surfactant which is based on the formation of an ion-pair. Then the effect of surfactant to gas volume ratio on oil recovery in secondary oil recovery process during execution of immiscible surfactant alternating gas injection was examined experimentally. The experiments were performed with sand pack under certain temperature, pressure and constant rate. Experiments were performed with surfactant to gas ratio of 1:1, 1:2, 1:3, 2:1 and 3:1 and 1.2 pore volume injected. Then, comparisons were made between obtained results (SAG) with water flooding, gas flooding and water alternating gas (WAG) processes.This study shows that using the concentration of 1500 ppm of surfactant solution is practical and economical. Results also show that the SAG ratio of 1:1 with 0.2 cm3/min at temperature and pressure of 70 °C and 144.74×105 Pa, has the maximum oil removal efficiency. In this SAG ratio, stable foam was formed and viscous fingering delayed in comparison to other ratios. Finally, the results demonstrated that SAG injection has higher oil recovery in comparison to other displacement methods (water flooding, gas flooding and WAG).

Fitting Foam-Simulation-Model Parameters to Data: II. Surfactant-Alternating-Gas Foam Applications

Summary Foam improves sweep in miscible and immiscible gas-injection enhanced-oil-recovery processes. Surfactant-alternating-gas (SAG) foam processes offer many advantages over coinjection of foam for both operational and sweep-efficiency reasons. The success of a foam SAG process depends on foam behavior at very low injected-water fraction (high foam quality). This means that fitting data to a typical scan of foam behavior as a function of foam quality can miss conditions essential to the success of an SAG process. The result can be inaccurate scaleup of results to field application. We illustrate how to fit foam-model parameters to steady-state foam data for application to injection of a gas slug in an SAG foam process. Dynamic SAG corefloods can be unreliable for several reasons. These include failure to reach local steady state (because of slow foam generation), the increased effect of dispersion at the core scale, and the capillary end effect. For current foam models, the behavior of foam in SAG depends on three parameters: the mobility of full-strength foam, the capillary pressure or water saturation at which foam collapses, and the parameter governing the abruptness of this collapse. We illustrate the fitting of these model parameters to coreflood data, and the challenges that can arise in the fitting process, with the published foam data of Persoff et al. (1991) and Ma et al. (2013). For illustration, we use the foam model in the widely used STARS (Cheng et al. 2000) simulator. Accurate water-saturation data are essential to making a reliable fit to the data. Model fits to a given experiment may result in inaccurate extrapolation to mobility at the wellbore and, therefore, inaccurate predicted injectivity: for instance, a model fit in which foam does not collapse even at extremely large capillary pressure at the wellbore. We show how the insights of fractional-flow theory can guide the model-fitting process and give quick estimates of foam-propagation rate, mobility, and injectivity at the field scale.

Can Formation Relative Permeabilities Rule Out a Foam EOR Process?

Summary Foam is a promising means of increasing sweep in miscible- and immiscible-gas enhanced oil recovery (EOR). Surfactant alternating gas (SAG) is a preferred method of injection. Numerous studies verify that the water relative permeability function krw(Sw) is unaffected by foam. Studies of foam have used a variety of krw functions. This paper shows a connection between the krw(Sw) function and SAG foam effectiveness that is independent of the details of how foam reduces gas mobility. For simplicity, we analyze SAG processes in the absence of mobile oil; success without oil is a precondition to success with oil, and our analysis also applies to a miscible-gas process with oil in 1D in the absence of dispersion. Fractional-flow methods have proved useful and accurate for modeling foam EOR processes. The success of SAG depends on total mobility at a point of tangency to the fractional-flow curve, which defines the shock front at the leading edge of the foam bank. One can determine total mobility directly from the coordinates of this point (Sw, fw) if the function krw(Sw) is known. Geometric constraints limit the region in the fractional-flow diagram in which this point of tangency can occur. For a given krw(Sw) function, this limits the mobility reduction achievable for any possible SAG process. We examine the implications of this limitation for different krw functions. These implications include the following. Increasing nonlinearity of the krw function is advantageous for SAG processes, regardless of how foam reduces gas mobility. SAG is inappropriate for naturally fractured reservoirs if straight-line relative permeabilities apply, even if extremely strong foam can be stabilized in fractures. It is important to measure krw(Sw) separately for any formation for which a SAG process is envisioned.

The Method of Characteristics Applied to Oil Displacement by Foam

Summary Solutions obtained by the method of characteristics (MOC) provide key insights into complex foam enhanced-oil-recovery (EOR) displacements and the simulators that represent them. Most applications of the MOC to foam have excluded oil. We extend the MOC to foam flow with oil, where foam is weakened or destroyed by oil saturations above a critical oil saturation and/or weakened or destroyed at low water saturations, as seen in experiments and represented in foam simulators. Simulators account for the effects of oil and capillary pressure on foam using algorithms that bring foam strength to zero as a function of oil or water saturation, respectively. Different simulators use different algorithms to accomplish this. We examine SAG (surfactant-alternating-gas) and continuous foam-flood (coinjection of gas and surfactant solution) processes in one dimension, using both the MOC and numerical simulation. We find that the way simulators express the negative effect of oil or water saturation on foam can have a large effect on the calculated nature of the displacement. For instance, for gas injection in a SAG process, if foam collapses at the injection point because of infinite capillary pressure, foam has almost no effect on the displacement in the cases examined here. On the other hand, if foam maintains finite strength at the injection point in the gas-injection cycle of a SAG process, displacement leads to implied success in several cases. However, successful mobility control is always possible with continuous foam flood if the initial oil saturation in the reservoir is below the critical oil saturation above which foam collapses. The resulting displacements can be complex. One may observe, for instance, foam propagation predicted at residual water saturation, with zero flow of water. In other cases, the displacement jumps in a shock past the entire range of conditions in which foam forms. We examine the sensitivity of the displacement to initial oil and water saturations in the reservoir, the foam quality, the functional forms used to express foam sensitivity to oil and water saturations, and linear and nonlinear relative permeability models.

Success of SAG-Foam Processes in Heterogeneous Reservoirs

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 110408, "Success of SAG-Foam Processes in Heterogeneous Reservoirs," by W.J. Renkema and W.R. Rossen, Delft University of Technology, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11–14 November. In principle, miscible-gas injection can displace nearly all of the oil from the portions of a reservoir swept by gas. However, reservoir heterogeneity, low gas density, and high gas mobility reduce sweep efficiency and decrease recovery drastically. The use of foam can reduce gas mobility and the effect of heterogeneity, thereby increasing sweep efficiency. An optimal design strategy is proposed for surfactant-alternating-gas (SAG) -foam processes. Introduction Primary- and secondary-recovery methods leave behind up to two-thirds of the oil originally in place in the reservoir. Gas injection can increase the recovery from depleted reservoirs. Injected gas tends to rise to the top of the reservoir because of its low density, then over-ride the oil-rich zone, leading to early gas breakthrough. High mobility of the gas leads to viscous instability, which enhances gravity override and makes heterogeneity much worse by forming high-mobility flow paths. The use of foam for mobility control, proposed in 1958, traps some bubbles and reduces movement of flowing gas, thereby reducing gas mobility. Trapped gas reduces gas relative permeability because foam films (lamellae) block some of the flow channels. In flowing bubbles, the effective gas viscosity is increased because pore walls and constrictions cause significant drag. Foam does not change the water relative permeability function or liquid viscosity. Foam can be injected into the reservoir by coinjection of gas and water or by SAG injection (alternating slugs of surfactant solution and gas). For CO2-foam projects, the SAG process also reduces corrosion in surface facilities and pipe. In low-permeability porous media, the SAG process increases gas injectivity. When gas is injected, water is displaced from the near-well region farther into the reservoir, weakening foam near the well. As a result, gas mobility in the near-well region rises, and injectivity increases. Foam Model Existing models can be divided into local-steady-state models (ranging from simple to more-complex semimechanistic models) and dynamic "population-balance" models. Population-balance models take into account the rate of change of foam texture (i.e., bubble density), which depends on creation, destruction, and trapping of lamellae. Local-steady-state models use an algebraic relation (which could be empirical or more physically based) between gas mobility and factors determining foam texture (e.g., surfactant concentration). All these models account for foam having no effect on the relative permeability function for water.

Experimental Study of Gas Injection in a Surfactant-Alternating-Gas Foam Process

SummaryFractional-flow methods have been shown to be accurate and successful in modeling surfactant-alternating-gas (SAG) foam processes. Fractional-flow theory indicates that the success of gas diversion in a SAG process depends on steady-state foam behavior at very low water fractional flow fw (very high foam quality). Previous simulation studies of these processes have relied on extrapolating steady-state data taken at much higher values of fw. Radically different results are predicted depending on how these extrapolations are made. Data are needed at very low fw to predict SAG performance in the field.Laboratory coreflood experiments were conducted to obtain the needed fractional-flow curves. For each value of fw, constant water- and gas-injection rates were imposed and maintained until the system reached steady state. The corresponding average water saturation in the core was determined by weighing the core continuously during the experiment. Experimental fractional-flow curves are presented for two surfactant formulations in Berea sandstone core, with no oil present, at extremely high foam quality.Results are then scaled up using fractional-flow theory to a hypothetical field-scale application. In both cases, the data scale up to successful mobility control on the field scale. In one case, foam suffered an abrupt decline from stronger foam to coarser foam with increasing foam quality, with a multivalued fractional-flow function, in agreement with some earlier experimental and theoretical results.