scholarly journals Relative permeability and the microscopic distribution of wetting and nonwetting phases in the pore space of Berea sandstone

1994 ◽  
Author(s):  
E.M. Schlueter ◽  
N.G.W. Cook ◽  
P.A. Witherspoon ◽  
L.R. Myer
Keyword(s):  
Relative Permeability ◽  
Pore Space ◽  
Berea Sandstone ◽  
Microscopic Distribution

scholarly journals Formation factor and the microscopic distribution of wetting phase in pore space of berea sandstone

1993 ◽  
Author(s):  
E. M. Schlueter ◽  
L. R. Myer ◽  
N. G. W. Cook ◽  
P. A. Witherspoon
Keyword(s):  
Pore Space ◽  
Berea Sandstone ◽  
Formation Factor ◽  
Microscopic Distribution

scholarly journals Measurements of CO2-brine relative permeability in Berea sandstone using pressure taps and a long core

2016 ◽  
Vol 7 (2) ◽  
pp. 370-382 ◽  
Author(s):  
Xiongyu Chen ◽  
Amir Kianinejad ◽  
David A. DiCarlo
Keyword(s):  
Relative Permeability ◽  
Berea Sandstone

Three-Phase Relative Permeability of Berea Sandstone

1990 ◽  
Vol 42 (08) ◽  
pp. 1054-1061 ◽  
Author(s):  
M.J. Oak ◽  
L.E. Baker ◽  
D.C. Thomas
Keyword(s):  
Relative Permeability ◽  
Berea Sandstone ◽  
Three Phase

Multiphase-Flow and Reactive-Transport Validation Studies at the Pore Scale by Use of Lattice Boltzmann Computer Simulations

SPE Journal ◽  
2017 ◽  
Vol 22 (03) ◽  
pp. 940-949 ◽  
Author(s):  
Edo S. Boek ◽  
Ioannis Zacharoudiou ◽  
Farrel Gray ◽  
Saurabh M. Shah ◽  
John P. Crawshaw ◽  
...  
Keyword(s):  
Porous Media ◽  
Multiphase Flow ◽  
Capillary Pressure ◽  
Computer Simulations ◽  
Relative Permeability ◽  
Lattice Boltzmann ◽  
Reactive Transport ◽  
Pore Space ◽  
Processing Unit ◽  
Space Images

Summary We describe the recent development of lattice Boltzmann (LB) and particle-tracing computer simulations to study flow and reactive transport in porous media. First, we measure both flow and solute transport directly on pore-space images obtained from micro-computed-tomography (CT) scanning. We consider rocks with increasing degree of heterogeneity: a bead pack, Bentheimer sandstone, and Portland carbonate. We predict probability distributions for molecular displacements and find excellent agreement with pulsed-field-gradient (PFG) -nuclear-magnetic-resonance (NMR) experiments. Second, we validate our LB model for multiphase flow by calculating capillary filling and capillary pressure in model porous media. Then, we extend our models to realistic 3D pore-space images and observe the calculated capillary pressure curve in Bentheimer sandstone to be in agreement with the experiment. A process-based algorithm is introduced to determine the distribution of wetting and nonwetting phases in the pore space, as a starting point for relative permeability calculations. The Bentheimer relative permeability curves for both drainage and imbibition are found to be in good agreement with experimental data. Third, we show the speedup of a graphics-processing-unit (GPU) algorithm for large-scale LB calculations, offering greatly enhanced computing performance in comparison with central-processing-unit (CPU) calculations. Finally, we propose a hybrid method to calculate reactive transport on pore-space images by use of the GPU code. We calculate the dissolution of a porous medium and observe agreement with the experiment. The LB method is a powerful tool for calculating flow and reactive transport directly on pore-space images of rock.

Factors That Affect Gas-Condensate Relative Permeability

2014 ◽  
Vol 18 (01) ◽  
pp. 5-10 ◽  
Author(s):  
Subhash Kalla ◽  
Sergio A. Leonardi ◽  
Daniel W. Berry ◽  
Larry D. Poore ◽  
Hemant Sahoo ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Pore Space ◽  
Gas Condensate ◽  
Reservoir Rock ◽  
Fluid Type ◽  
Reservoir Conditions ◽  
Condensate Reservoir ◽  
House Design ◽  
Permeability Data

Summary When the pressure in a gas-condensate reservoir falls below the dewpoint, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements were conducted on reservoir rock at a variety of conditions. The goal was to determine the sensitivity to interfacial tension (IFT) (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an IFT sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that are applicable to a specific reservoir, we conclude that laboratory measurements must be conducted at reservoir conditions with actual reservoir fluids. The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium.

The Effects of Water Injection on Miscible Flooding Methods Using Hydrocarbons and Carbon Dioxide

1975 ◽  
Vol 15 (03) ◽  
pp. 217-226 ◽  
Author(s):  
J.L. Shelton ◽  
F.N. Schneider
Keyword(s):  
Carbon Dioxide ◽  
Relative Permeability ◽  
Flow Rate ◽  
Water Saturation ◽  
Miscible Displacement ◽  
Berea Sandstone ◽  
Mobile Water ◽  
Displacement Front ◽  
Miscible Flooding ◽  
First Contact

Abstract The effects of mobile water saturations on oil recovery and solvent requirements were studied in miscible displacement tests on sandstone cores. it was found thatoil, if trapped by mobile water, cannot be easily contacted by solvent, and the amount of oil is directly related to measurable relative-permeability characteristics;miscible displacement Performances for secondary and tertiary conditions are equivalent;long-core tests describe the movement of fluid banks that would occur in field floods; andflooding response for solvent developed from multiple contact of crude oil with carbon dioxide or rich gas in long cores is the same as that for liquid solvents with first-contact miscibility. Introduction Miscible flooding is receiving increasing interest as a means of recovering tertiary oil left after waterflooding. Mobile water is a factor in tertiary flooding, and can also be a factor in secondary operations where alternate water and solvent injection is used to improve the low sweep efficiency of miscible flooding with hydrocarbon and acid gases. Several publications have reported a reduction in displacement efficiency when mobile water is present at the displacement front. Stalkup present at the displacement front. Stalkup summarized this information and also reported increased mixing caused by the mobile water. However, more information is needed to implement recovery operations where mobile water conditions can occur. The purpose of this paper is to provide information about the displacement behavior in those portions of a reservoir that may contain a high water saturation and that are contacted by a solvent. Factors examined arethe relationship of oil trapping by water to relative permeability and wettability,the development and growth of fluid banks,a comparison of first-contact and multiple-contact miscible displacement, before and after waterflooding,the effect of flow rate and system length on multiple-contact miscible displacement, andthe displacement of oil by the simultaneous injection of solvent and water. The experiments performed were in laboratory cores and are not scaled to field conditions in some respects. The study provides insight into some of the pertinent mechanisms of the displacement process rather than data that is directly applicable to a field situation. MATERIALS AND PROCEDURE OIL-TRAPPING TESTS Drainage and imbibition water-oil relative-permeability data were obtained on a water-wet Berea sandstone core using the steady-state test procedure. The dimensions of the Lucite-encased Berea core are given in Table 1. Two series of first-contact miscible-displacement test, one series involving the displacement of water and the other involving the displacement of oil, were performed at various levels of oil and water saturation on the same core. Saturations during the relative-permeability tests and miscible - displacement tests were determined using an X-ray absorption technique. The recovery performance was calculated by refractive index analyses of the produced fluids. To provide for these analyses, two bones and two refined oils were prepared for the tests. TABLE 1 - TRAPPING-ENVELOPE MISCIBLE-DISPLACEMENT TESTS, 2.1-IN.-DIAMETER BY 5.1-IN.-LONG BEREA SANDSTONE CORE Residual In-Place Saturation Solvent Liquid Test Flowing percent PV Flow Rate Saturation Number WOR Oil Water (PV/hour) (percent PV) ------ ------- --- ----- --------- ------------- Drainage Tests - 1.0-cp Nal brine displace by 0.95-cp brine D-1 oo 0 100 2.84 0 D-2 2 29 71 1.79 0 D-3 0.1 45 55 0.284 0.5 Imbibition Tests - 1.48-cp oil displaced by 1.42-cp oil containing iodobenzene I-1 0 74 26 2.85 0 I-2 0.2 43 57 2.28 7 I-3 1 34 66 0.78 13 I-4 5 32 68 2.72 17 I-5 1 35 65 1.21 10 SPEJ P. 217

Injectivity Characteristics of EOR Polymers

2009 ◽  
Vol 12 (05) ◽  
pp. 783-792 ◽  
Author(s):  
Randall S. Seright ◽  
J. Mac Seheult ◽  
Todd Talashek
Keyword(s):  
Porous Media ◽  
Relative Permeability ◽  
Polymer Solutions ◽  
Mechanical Degradation ◽  
Polymer Rheology ◽  
Residual Oil ◽  
Berea Sandstone ◽  
Porous Rock ◽  
Oil Saturation ◽  
Polymer Properties

Summary For applications in which enhanced-oil-recovery (EOR) polymer solutions are injected, we estimate injectivity losses (relative to water injectivity) if fractures are not open. We also consider the degree of fracture extension that may occur if fractures are open. Three principal EOR polymer properties are examined that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. An improved test was developed to measure the tendency of EOR polymers to plug porous media. The new test demonstrated that plugging tendencies varied considerably among both partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers. Rheology and mechanical degradation in porous media were quantified for a xanthan and an HPAM polymer. Consistent with previous work, we confirmed that xanthan solutions show pseudoplastic behavior in porous rock that closely parallels that in a viscometer. Xanthan was remarkably resistant to mechanical degradation, with a 0.1% xanthan solution (in seawater) experiencing only a 19% viscosity loss after flow through 102-md Berea sandstone at a pressure gradient of 24,600 psi/ft. For 0.1% HPAM in both 0.3% NaCl brine and seawater in 573-md Berea sandstone, Newtonian behavior was observed at low to moderate fluid fluxes, while pseudodilatant behavior was seen at moderate to high fluxes. No evidence of pseudoplastic behavior was seen in the porous rock, even though one solution exhibited a power-law index of 0.64 in a viscometer. For this HPAM in both brines, the onset of mechanical degradation occurred at a flux of 14 ft/d in 573-md Berea. Considering the polymer solutions investigated, satisfactory injection of more than 0.1 pore volume (PV) in field applications could only be expected for the cleanest polymers (i.e., that do not plug before 1,000 cm3/cm2 throughput), without inducing fractures (or formation parts for unconsolidated sands). Even in the absence of face plugging, the viscous nature of the solutions investigated requires that injectivity must be less than one-fifth that of water if formation parting is to be avoided (unless the injectant reduces the residual oil saturation and substantially increases the relative permeability to water). Since injectivity reductions of this magnitude are often economically unacceptable, fractures or fracture-like features are expected to open and extend significantly during the course of most polymer floods. Thus, an understanding of the orientation and growth of fractures may be crucial for EOR projects in which polymer solutions are injected. Introduction Maintaining mobility control is essential during chemical floods (polymer, surfactant, alkaline floods). Consequently, viscosification using water soluble polymers is usually needed during chemical EOR projects. Unfortunately, increased injectant viscosity could substantially reduce injectivity, slow fluid throughput, and delay oil production from flooded patterns. The objectives of this paper are to estimate injectivity losses associated with injection of polymer solutions if fractures are not open and to estimate the degree of fracture extension if fractures are open. We examine the three principal EOR polymer properties that affect injectivity:debris in the polymer,polymer rheology in porous media, andpolymer mechanical degradation. Although some reports suggest that polymer solutions can reduce the residual oil saturation below values expected for extensive waterflooding (and thereby increase the relative permeability to water), this effect is beyond the scope of this paper.

Effects of pore and differential pressure on compressional wave velocity and quality factor in Berea and Michigan sandstones

Geophysics ◽  
1997 ◽  
Vol 62 (4) ◽  
pp. 1163-1176 ◽  
Author(s):  
Manika Prasad ◽  
Murli H. Manghnani
Keyword(s):  
Quality Factor ◽  
Wave Velocity ◽  
Pore Space ◽  
Confining Pressure ◽  
Compressional Wave ◽  
Differential Pressure ◽  
Berea Sandstone ◽  
Compressional Wave Velocity ◽  
Stress Coefficient ◽  
Space Deformation

Compressional‐wave velocity [Formula: see text] and quality factor [Formula: see text] have been measured in Berea and Michigan sandstones as a function of confining pressure [Formula: see text] to 55 MPa and pore pressure [Formula: see text] to 35 MPa. [Formula: see text] values are lower in the poorly cemented, finer grained, and microcracked Berea sandstone. [Formula: see text] values are affected to a lesser extent by the microstructural differences. A directional dependence of [Formula: see text] is observed in both sandstones and can be related to pore alignment with pressure. [Formula: see text] anisotropy is observed only in Berea sandstone. [Formula: see text] and [Formula: see text] increase with both increasing differential pressure [Formula: see text] and increasing [Formula: see text]. The effect of [Formula: see text] on [Formula: see text] is greater at higher [Formula: see text]. The results suggest that the effective stress coefficient, a measure of pore space deformation, for both [Formula: see text] and [Formula: see text] is less than 1 and decreases with increasing [Formula: see text].

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