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

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.

Sign in / Sign up

Export Citation Format

Share Document