Anomalous Foam-Fractional-Flow Solutions at High-Injection Foam Quality

2013 ◽  
Vol 16 (01) ◽  
pp. 40-50 ◽  
Author(s):  
A.. Roostapour ◽  
S.I.. I. Kam
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Mobility Control ◽  
Injection Velocity ◽  
Fractional Flow ◽  
Improved Oil Recovery ◽  
High Injection ◽  
Constant State ◽  
Dry Conditions ◽  
First Time

Summary A thorough understanding of foam fundamentals is crucial to the optimal design of foams for improved oil recovery (IOR) or enhanced oil recovery (EOR). This study, for the first time, presents anomalous foam-fractional-flow solutions that deviate significantly from the conventional solutions at high-injection foam qualities by comparing method-of-characteristics and mechanistic bubble-population-balance simulations. The results from modeling and simulations derived from coreflood experiments revealed the following: The fraction of grinding energy contributed by the flowing gas (fg)There are three regions—Region A with relatively wet (or high fw) injection conditions in which the solutions are consistent with the conventional fractional-flow theory; Region C with very dry (or low fw) injection conditions in which the solutions deviate significantly; and Region B in between, which has a negative dfw/dSw slope showing physically unstable solutions.For dry-injection conditions in Region C, the solutions require a constant state (IJ) between initial (I) and injection (J) conditions, forcing a shock from I to IJ by intersecting fractional-flow curves, followed by spreading waves or another shock to reach from IJ to J.The location of IJ in fw vs. Sw domain moves to the left (or toward lower Sw) as the total injection velocity increases for both weak and strong foams until it reaches limiting water saturation. Even though foams at high-injection quality are popular for mobility control associating a minimum amount of surfactant solutions, foam behaviors at dry conditions have not been thoroughly investigated and understood. The outcome of this study is believed to be helpful to the successful planning of foam IOR/EOR field applications.

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

SPE Journal ◽  
2020 ◽  
Vol 25 (04) ◽  
pp. 1857-1870
Author(s):  
Rodrigo O. Salazar-Castillo ◽  
William R. Rossen
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Laboratory Data ◽  
Mobility Control ◽  
Model Parameters ◽  
Fractional Flow ◽  
Foam Model ◽  
Irreducible Water Saturation

Summary Foam 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.

scholarly journals Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

2021 ◽  
Vol 3 (5) ◽  
Author(s):  
Ruissein Mahon ◽  
Gbenga Oluyemi ◽  
Babs Oyeneyin ◽  
Yakubu Balogun
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Polymer Flooding ◽  
Mobility Control ◽  
List Type ◽  
Motor Oil ◽  
Flow Mechanism ◽  
Fractional Flow ◽  
Recovery Method ◽  
Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

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

2014 ◽  
Vol 18 (02) ◽  
pp. 273-283 ◽  
Author(s):  
W. R. Rossen ◽  
C. S. Boeije
Keyword(s):  
Steady State ◽  
Capillary Pressure ◽  
Oil Recovery ◽  
Water Saturation ◽  
Field Application ◽  
Model Parameters ◽  
Fractional Flow ◽  
Sweep Efficiency ◽  
Water Fraction ◽  
Foam Model

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.

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

SPE Journal ◽  
2017 ◽  
Vol 22 (05) ◽  
pp. 1402-1415 ◽  
Author(s):  
A. H. Al Ayesh ◽  
R.. Salazar ◽  
R.. Farajzadeh ◽  
S.. Vincent-Bonnieu ◽  
W. R. Rossen
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Gas Injection ◽  
Surfactant Solution ◽  
Model Parameters ◽  
High Permeability ◽  
Fractional Flow ◽  
Injection Method ◽  
Heterogeneous Reservoirs ◽  
Irreducible Water Saturation

Summary Foam 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.

scholarly journals Controlled Salinity-Biosurfactant Enhanced Oil Recovery at Ambient and Reservoir Temperatures—An Experimental Study

Energies ◽  
2021 ◽  
Vol 14 (4) ◽  
pp. 1077
Author(s):  
Tinuola Udoh ◽  
Jan Vinogradov
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Core Flooding ◽  
Improved Oil Recovery ◽  
Rock Samples ◽  
Recovery Potential ◽  
System Temperature ◽  
High And Low Temperatures ◽  
First Time ◽  
Increased Oil Recovery

In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relative to injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 °C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.

Synergy of Polymer for Mobility Control and Surfactant for Interface Elasticity Increase in Improved Oil Recovery

2021 ◽  
Author(s):  
Taniya Kar ◽  
Abbas Firoozabadi
Keyword(s):  
Oil Recovery ◽  
Sea Water ◽  
Synergistic Effects ◽  
Water Injection ◽  
Mobility Control ◽  
Residual Oil ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Low Salinity Waterflooding

Abstract Improved oil recovery in carbonate rocks through modified injection brine has been investigated extensively in recent years. Examples include low salinity waterflooding and surfactant injection for the purpose of residual oil reduction. Polymer addition to injection water for improvement of sweep efficiency enjoys field success. The effect of low salinity waterflooding is often marginal and it may even decrease recovery compared to seawater flooding. Polymer and surfactant injection are often effective (except at very high salinities and temperatures) but concentrations in the range of 5000 to 10000 ppm may make the processes expensive. We have recently suggested the idea of ultra-low concentration of surfactants at 100 ppm to decrease residual oil saturation from increased brine-oil interfacial elasticity. In this work, we investigate the synergistic effects of polymer injection for sweep efficiency and the surfactant for interfacial elasticity modification. The combined formulation achieves both sweep efficiency and residual oil reduction. A series of coreflood tests is performed on a carbonate rock using three crude oils and various injection brines: seawater and formation water with added surfactant and polymer. Both the surfactant and polymer are found to improve recovery at breakthrough via increase in oil-brine interfacial elasticity and injection brine viscosification, respectively. The synergy of surfactant and polymer mixed with seawater leads to higher viscosity and higher oil recovery. The overall oil recovery is found to be a strong function of oil-brine interfacial viscoelasticity with and without the surfactant and polymer in sea water and connate water injection.

CO 2 -sensitive and self-enhanced foams for mobility control during CO 2 injection for improved oil recovery and geo-storage

2017 ◽  
Vol 120 ◽  
pp. 113-120 ◽  
Author(s):  
Dexiang Li ◽  
Shaoran Ren ◽  
Panfeng Zhang ◽  
Liang Zhang ◽  
Yunjun Feng ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Improved Oil Recovery

Novel Insight Into Foam Mobility Control

SPE Journal ◽  
2013 ◽  
Vol 18 (03) ◽  
pp. 416-427 ◽  
Author(s):  
M.. Simjoo ◽  
Y.. Dong ◽  
A.. Andrianov ◽  
M.. Talanana ◽  
P.L.J.. L.J. Zitha
Keyword(s):  
Oil Recovery ◽  
Surfactant Concentration ◽  
Field Application ◽  
Reduction Factor ◽  
Mobility Control ◽  
Injection Velocity ◽  
Alpha Olefin Sulfonate ◽  
Liquid Saturation ◽  
Nitrogen Foam ◽  
Foam Propagation

Summary A detailed laboratory study of nitrogen-foam propagation in natural sandstones in the absence of oil is reported. The goal of this study was to elucidate further the mechanisms of foam mobility control. The C14–16 alpha-olefin sulfonate (AOS) surfactant was selected to stabilize foam. X-ray computed-tomography (CT) images were taken during foam propagation to map liquid saturation over time. Effects of surfactant concentration and of total injection velocity were examined in detail because these are key parameters for controlling foam strength and foam propagation under field conditions. The experiments revealed that foam mobility decreases in two steps: During initial forward foam propagation, foam mobility decreases by an order of magnitude compared with water mobility; during a secondary backward liquid desaturation, it decreases further by one to two orders of magnitude for sufficiently high surfactant concentrations. The steady-state mobility-reduction factor (MRF) increases considerably with both surfactant concentration and total injection velocity. A hysteresis was observed for a cycle of increasing/decreasing surfactant concentration or total injection velocity. The observed effects could be interpreted mechanistically in terms of surfactant adsorption and foam rheology. Implications for field application of foam for immiscible and miscible gas enhanced oil recovery (EOR) are discussed.

Impact of Viscous Fingering on the Prediction of Optimum WAG Ratio

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 486-495 ◽  
Author(s):  
Ruben Juanes ◽  
Martin Julian Blunt
Keyword(s):  
Oil Recovery ◽  
Viscous Fingering ◽  
Mobility Control ◽  
Displacement Efficiency ◽  
Fractional Flow ◽  
Solvent Injection ◽  
Solvent Front ◽  
Water Solvent ◽  
Effective Mobility ◽  
Fractional Flow Theory

Summary In miscible flooding, injection of solvent is often combined with water to reduce the mobility contrast between injected and displaced fluids and control the degree of fingering. Using traditional fractional-flow theory, Stalkup estimated the optimum water-solvent ratio (or WAG ratio) when viscous fingering effects are ignored, by imposing that the solvent and water fronts travel at the same speed. Here we study how the displacement efficiency and the mobility ratio across the solvent front vary with the WAG ratio when fingering is included in the analysis. We do so by computing analytical solutions to a 1D model of two-phase, three-component, first-contact miscible flow that includes the macroscopic effects of viscous fingering. The macroscopic model, originally proposed by Blunt and Christie (1993, 1994), employs an extension of the Koval fingering model to multiphase flows. The premise is that the only parameter of the model—the effective mobility ratio—must be calibrated dynamically until self-consistency is achieved between the input value and the mobility contrast across the solvent front. This model has been extensively validated by means of high-resolution simulations that capture the details of viscous fingering and carefully-designed laboratory experiments. The results of this paper suggest that, while the prediction of the optimum WAG ratio does not change dramatically by incorporating the effects of viscous fingering, it is beneficial to inject more solvent than estimated by Stalkup's method. We show that, in this case, both the pore volumes injected (PVI) for complete oil recovery and the degree of fingering are minimized. Introduction Solvent flooding is a commonly used technology for enhanced oil recovery in hydrocarbon reservoirs, which aims at developing miscibility, thereby mobilizing the residual oil and enhancing the mobility of the hydrocarbon phase (Stalkup 1983; Lake 1989). Despite its high local displacement efficiency, the overall effectiveness of solvent injection may be compromised by viscous fingering, channeling, and gravity override, all of which contribute negatively to sweep efficiency (Christie and Bond 1987; Christie 1989; Christie et al. 1993; Chang et al. 1994; Tchelepi and Orr 1994). In this paper, we focus on the effect of viscous fingering; that is, the instability that occurs when a low-viscosity fluid (solvent) is injected into a formation filled with more viscous fluids (water and oil). Mobility control of the injected solvent can be achieved by simultaneous coinjection of water—typically in alternating water and solvent slugs (WAG) (Caudle and Dyes 1958). In this way, the mobility contrast between the injected and displaced fluids is reduced, thereby limiting the degree of fingering. There is an optimum ratio of water to solvent that maximizes recovery—in the sense of minimizing the number of pore volumes injected—while providing effective mobility control. For linear floods in homogeneous media, and without consideration of viscous fingering effects, a graphical construction of the optimum WAG ratio was given by Stalkup (1983) for both secondary floods (water/solvent injection into a medium filled with mobile oil and immobile water) and tertiary floods (water-solvent injection into a medium filled with mobile water and immobile oil). The design condition imposed in Stalkup's method is that the velocity of the water and solvent fronts be the same. Walsh and Lake (1989) performed an interesting analysis of the WAG ratio (the ratio of injected water to solvent) on the displacement efficiency for secondary and tertiary floods, using fractional-flow theory. They did not include the effects of viscous fingering, but they estimated the mobility contrast across the solvent front as a measure of the severity of fingering.

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