Long-Time Diversion in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery From a Field Test

Rossen, W.R.; Ocampo, Alonso; Restrepo, Alejandro; Cifuentes, H.; Marin, Jefferson

doi:10.2118/170809-pa

Cited by 17 publications

(8 citation statements)

References 8 publications

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“…Liquid follows 1-GPV gas injection-Peaceman equation Liquid follows 10-GPV gas injection-Peaceman equation Liquid follows 20-GPV gas injection-Peaceman equation Liquid follows 1-GPV gas injection-radial-flow model Liquid follows 10-GPV gas injection-radial-flow model Liquid follows 20-GPV gas injection-radial-flow model Liquid follows 1-GPV gas injection-skin factor Liquid follows 10-GPV gas injection-skin factor Liquid follows 20-GPV gas injection-skin factor especially problematic in this regard. In fitting the effect of long-time gas injection on foam mobility near a gas-injection well in a field test, Rossen et al (2017) found that the Zanganeh model (Zanganeh et al 2011) did a reasonable job of representing foam mobility after many PVs of gas injection. In any event, a model fit with more-abrupt foam collapse at the limiting water saturation would have come closer to the predictions of the radial-flow model during gas injection in this study.…”

Section: Gpv Of Liquid Injectedmentioning

confidence: 99%

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

et al. 2019

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Surfactant alternating gas (SAG) is often the injection strategy used for injecting foam into a reservoir. However, liquid injectivity can be very poor in SAG, and fracturing of the well can occur. Coreflood studies of liquid injectivity directly following foam injection have been reported. We conducted a series of coreflood experiments to study liquid injectivity under conditions more like those near an injection well in a SAG process in the field (i.e., after a period of gas injection). Our previous experimental results suggest that the injectivity in a SAG process is determined by propagation of several banks. However, there is no consistent approach to modeling liquid injectivity in a SAG process. The Peaceman equation is used in most conventional foam simulators for estimating the wellbore pressure and injectivity. In this paper, we propose a modeling approach for gas and liquid injectivity in a SAG process on the basis of our experimental findings. The model represents the propagation of various banks during gas and liquid injection. We first compare the model predictions for linear flow with the coreflood results and obtain good agreement. We then propose a radial-flow model for scaling up the core-scale behavior to the field. The comparison between the results of the radial-propagation model and the Peaceman equation shows that a conventional simulator based on the Peaceman equation greatly underestimates both gas and liquid injectivities in a SAG process. The conventional simulator cannot represent the effect of gas injection on the subsequent liquid injectivity, especially the propagation of a relatively small region of collapsed foam near an injection well. The conventional simulator's results can be brought closer to the radial-flow-model predictions by applying a constant negative skin factor. The work flow described in this study can be applied to future field applications. The model we propose is based on a number of simplifying assumptions. In addition, the model would need to be fitted to coreflood data for the particular surfactant formulation, porous medium, and field conditions of a particular application. The adjustment of the simulator to better fit the radial-flow model also would depend, in part, on the grid resolution of the near-well region in the simulation.

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Section: Gpv Of Liquid Injectedmentioning

confidence: 99%

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

et al. 2019

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“…In interpreting the foam pilot in the Cusiana field, Rossen et al (2017) discussed foam dry-out as an important factor in foam weakness. Simulations performed for the foam pilot in WFB showed sensitivity to (1) foam strength (2) foam dry-out (3) oil tolerance and (4) adsorption.…”

Section: Foam Stabilitymentioning

confidence: 99%

Foam Generation, Propagation and Stability in Porous Medium

et al. 2019

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There have been several foam field applications in recent years. Foam treatments targeting gas mobility control in injectors as well as gas blocking in production wells have been performed without causing operational problems. The most widely used injection strategy of foam has been injecting alternating slugs of surfactant in brine with gas injection. This procedure seems to be beneficial as injection is easy to perform and control below fracturing pressure. Simultaneous injection of surfactant solution and gas may give difficulties, especially with interpretation of the tests, if fracturing pressure are exceeded during the injection period. This paper reviews critical aspects of foam for reservoir applications and intends to motivate for further field trials. Key parameters for qualification of foam are: foam generation, propagation in porous medium, foam strength and stability of foam. Stability is discussed, especially in the presence of oil at reservoir conditions. Data on each of these topics are included, as well as extracted summary of relevant literature. Experimental studies have shown that foam is generated at low surfactant concentration even below the CMC (critical micelle concentration). Results indicate that in situ foam generation in porous medium may depend on available nucleation sites. In situ generation of foam is complex and has been found to be especially difficult in oil wet carbonate rocks. Foam propagation in porous medium has been summarized, and propagation rate for a given experiment seems to be constant with time and distance. Laboratory studies confirm a propagation rate of 1-3 m/day. Field tests performed have not given reliable information of foam propagation rate, and future field pilots are encouraged to include observation wells in order to gain information of field-scale foam propagation. Foam strength is generally high with all gases. The exception is CO 2 at high pressure where CO 2 becomes supercritical. Stability of foam has been studied in laboratory and field tests, and has confirmed long-term stability of foam.

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“…Fractional-flow theory, or the method of characteristics, has proved useful for understanding a variety of processes for enhanced oil recovery (EOR) (de Nevers 1964; Claridge and Bondor 1974;Pope 1980;Lake 1989;Noh et al 2004;Lake et al 2014;Borazjani et al 2016;Farajzadeh et al 2019). Fractional-flow theory has been applied to foam EOR by Zhou and Rossen (1995), Rossen et al (1999Rossen et al ( , 2011Rossen et al ( , 2017, Namdar Zanganeh et al 2011, Boeije and Rossen (2018), Al Ayesh et al (2017), and Salazar Castillo (2019a). Its predictions are not rigorous because of the number of simplifying assumptions made, but they provide valuable insights, even if the assumptions are not strictly satisfied.…”

Section: Fractional-flow Theorymentioning

confidence: 99%

“…2015; Cheng et al 2000). However, this version of the dry-out function can underestimate the injectivity observed in the field during gas injection in a SAG (Rossen et al 2017). Therefore, in this study, we use the Namdar-Zanganeh modification of this model, which assumes complete foam collapse at residual water saturation S wr (Namdar-Zanganeh et al 2011;Rossen et al 2016).…”

Section: Applicationmentioning

confidence: 99%

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

et al. 2019

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Foam can improve sweep efficiency in gas-injection-enhanced oil recovery. Surfactantalternating-gas (SAG) is a favored method of foam injection. Laboratory data indicate that foam can be non-Newtonian at low water fractional flow f w , 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 f w 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 f w. 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 fractionalflow 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.

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Long-Time Diversion in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery From a Field Test

Cited by 17 publications

References 8 publications

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

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

Foam Generation, Propagation and Stability in Porous Medium

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

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