Modeling of Low-Tension Surfactant-Gas Flooding Process in a Four-Phase Flow Simulator

2015 ◽  
Author(s):  
Hamid R. Lashgari ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad
Keyword(s):  
Phase Flow ◽  
Gas Flooding ◽  
Low Tension ◽  
Flow Simulator

Low Tension Gas Flooding as a Novel EOR Method: An Experimental and Theoretical Investigation

2016 ◽  
Author(s):  
Stephen Jong ◽  
Nhut M. Nguyen ◽  
Calvin M. Eberle ◽  
Long X. Nghiem ◽  
Quoc P. Nguyen
Keyword(s):  
Theoretical Investigation ◽  
Gas Flooding ◽  
Low Tension

Multiphase Dispersion and Relative Permeability Experiments

1985 ◽  
Vol 25 (04) ◽  
pp. 524-534 ◽  
Author(s):  
M. Delshad ◽  
D.J. MacAllister ◽  
G.A. Pope ◽  
B.A. Rouse
Keyword(s):  
Relative Permeability ◽  
Single Phase ◽  
Phase Flow ◽  
Single Phase Flow ◽  
Relative Permeabilities ◽  
High Concentration ◽  
High Tension ◽  
Three Phase ◽  
Phase Saturation ◽  
Low Tension

Summary Experiments in both Berea sandstone and sandpacks have been conducted to measure dispersion and steady-state relative permeabilities. Measurements have been made on both high-tension brine/oil and a low-tension, three-phase, brine/oil/surfactant/alcohol mixture. One interesting aspect of these experiments is the amount of microemulsion phase trapping. The endpoint microemulsion saturations for both the oil/microemulsion and brine/microemulsion phase pairs were high even at 10–3 dyne/cm [10–3 mN/m] interfacial tension (IFT). The dispersion was measured for each phase with radioactive and chemical tracers. The dispersivity was found to be a strong function of phase, phase saturation, porous medium, and IFT. Values of the dispersivity varied by two orders of magnitude over conditions investigated to data. Extremely early breakthrough of the tracer used in the oil phase (carbon 14) at high tension is especially remarkable. The brine tracer (tritium) curves were similar to that for 100% brine saturation except for a shift caused by material balance reasons. The classical solution to the convection-diffusion equation for single-phase flow has been generalized to multiphase flow and was used to aid in interpreting these data. This combination of relative permeability and dispersion in each phase of the experiment with a high-concentration, three-phase-microemulsion sulfonate formulation is believed to be new, and more directly applicable to commercial surfactant flooding than previously reported experimental results. Introduction In this paper we report the initial results of a project1 to investigate the transport in porous media of several chemicals used in EOR. Specifically, we are studying the behavior of high-concentration, three-phase micellar formulations in beadpacks, sandpacks, and sandstone. The rheology, relative permeabilities, and dispersion coefficients have been the primary focus of this study to date. In this paper, we report on the last two parameters for a single polymer-free micellar formulation. These results are based on the theses of Delshad2 and MacAllister.3 The rheology of this and other EOR fluids is reported in Ref. 4. Oil recovery and history matching was done by Lin.5 A unique feature of this work was the way in which the relative permeabilities and dispersion experiments were combined into essentially the same experiment (see the section on procedures and materials). Since trapping has a profound effect on the efficiency of micellar/polymer flooding, another important feature is the measurement of microemulsion phase trapping at each relative permeability endpoint. These are believed to be the first direct measurement of this type. Literature Review No attempt will be made here to review the numerous high-tension relative permeability studies reported during the past several decades. Also, only a few of the classical single-phase flow dispersion studies will be mentioned. Low-tension data are much less extensive. Leverett,6 Mungan,7 du Prey,8 Talash,9 Bardon,10 Batycky,11 Klaus,12 and Amaefule and Handy13 are among the few who have reported results as a function of IFT. All of these results were for two-phase fluids. Furthermore, apparently only Talash, Klaus, and Amaefule and Handy used fluids containing sulfonates such as we are primarily concerned with, and then only at very low sulfonate concentrations. The general observations are that the relative permeability curves tend to increase and have less curvature as the IFT decreases or the capillary number increases. The residual saturations decrease simultaneously. Consistent with the capillary desaturation curves and theory reported by others,14–16 the nonwetting-phase saturation decreases first, then the residual wetting phase. It has been speculated for a long time that these curves will eventually become straight lines, but few if any of these experiments attained the ultralow IFT typical of optimal micellar fluids that would be necessary to test this idea.

Laboratory Investigation of Low-Tension-Gas Flooding for Improved Oil Recovery in Tight Formations

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 851-866 ◽  
Author(s):  
S.M.. M. Szlendak ◽  
N.. Nguyen ◽  
Q.P.. P. Nguyen
Keyword(s):  
Crude Oil ◽  
Oil Recovery ◽  
Mobility Control ◽  
Fractional Flow ◽  
Tight Sandstone ◽  
Secondary Recovery ◽  
Gas Flooding ◽  
Tertiary Recovery ◽  
Low Tension

Summary This paper establishes low-tension gas (LTG) as a method for submiscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of surfactant and gas to mobilize and then displace residual crude after waterflood at a greatly reduced oil/water interfacial tension (IFT). This method allows extending surfactant enhanced oil recovery (EOR) in sub-20-md formations in which polymer is impractical because of plugging, shear, or the requirement to use a low-molecular-weight polymer. The proposed strategy is tested through the coinjection of nitrogen and a slug/drive surfactant solution. Results indicate favorable mobilization and displacement of residual crude oil in both tight-carbonate and tight-sandstone reservoirs. Tertiary recovery of 75−90% of residual oil in place (ROIP) was achieved for cores with 2- to 15-md permeability. High LTG tertiary recovery is contrasted with results from reference surfactant (no gas) flooding (28% ROIP tertiary recovery) and immiscible gas coinjection (no surfactant) flooding (13% ROIP tertiary recovery). In addition, high initial oil saturation was tested to determine the process tolerance to oil and to evaluate the potential for application during secondary recovery. Under such conditions, this method achieved a recovery of 84% of oil originally in place (OOIP), suggesting the potential application of this process at secondary recovery. To better understand the physical mechanisms that affect mobilization and displacement, the early production of an elongated oil bank at reduced fractional flow of oil was shown to be an attribute of high crude-oil relative mobility and low pore volume (PV) available to mobile oil. This should favorably affect economics during chemical flooding by accelerating the production of an oil bank. Next, by application of salinity as a conservative tracer and oil material balance, gas saturation during LTG floods was calculated to be 18 to 22%. By comparing effluent salinity profiles across floods, a qualitative understanding of in-situ fluid dispersion associated with macroscopic displacement stability is developed. The results indicate that in-situ foaming was present, which enabled mobility control, and that stable displacement of in-situ fluids was achieved during flooding.

State-of-the-art adaptive mesh generator implementation for dynamic asphaltene deposition in four-phase flow simulator in near well-bore region

2016 ◽  
Vol 65 ◽  
pp. 242-255 ◽  
Author(s):  
Forough Ameli ◽  
Mahdi Hosseinzadeh ◽  
Abdolhossein Hemmati-Sarapardeh ◽  
Marziyeh Salehzadeh ◽  
Bahram Dabir
Keyword(s):  
State Of The Art ◽  
Adaptive Mesh ◽  
Phase Flow ◽  
Well Bore ◽  
Mesh Generator ◽  
Asphaltene Deposition ◽  
Flow Simulator
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