Summary One primary goal of any enhanced recovery project is to maximize the ability of the fluids to flow through a porous medium (i.e., the reservoir). This paper discusses the effect of capillary number, a dimensionless group describing the ratio of viscous to capillary forces, on two-phase (oil-water) relative permeability curves. Specifically, a series of steady-state relative permeability measurements were carried out to determine whether the capillary number causes changes in the two-phase permeabilities or whether one of its constituents, such as flow velocity, fluid viscosity, or interfacial tension (IFT), is the controlling variable. For the core tests, run in fired Berea sandstone, a Soltrol 170™ oil/calcium chloride (CaCl2) brine/isopropyl alcohol (IPA)/glycerin system was used. Alcohol was the IFT reducer and glycerin was the wetting-phase viscosifier. The nonwetting-phase (oil) relative permeability showed little correlation with the capillary number. As IFT decreased below 5.50 dyne/cm [5.50 N/m], the oil permeability increased dramatically. Conversely, as the water viscosity increased, the oil demonstrated less ability to flow. For the wetting-phase (water) relative permeability, the opposite capillary number effect was shown. For both the tension decrease and the viscosity increase (i.e., a capillary number increase) the water permeability increased. However, the water increase was not as great as the increase in the oil curves with an IFT decrease. No velocity effects were noted within the range studied. Other properties relating to relative permeabilities were also investigated. Both the residual oil saturation (ROS) and the imbibition-drainage hysteresis were found to decrease with an increase in the capillary number. The irreducible water saturation was a function of IFT tension only. A relative permeability model was developed from the experimental data, based on fluid saturations, IFT, fluid viscosities, and the residual saturations, by using regression analysis. Both phases were modeled for both the imbibition and the drainage processes. These models demonstrated similar or better fits with experimental data of other water- and oil-wet systems, when compared with existing relative permeability models. The applicability of these regression models was tested with the aid of a two-phase reservoir simulator. Introduction As world oil reserves dwindle, the need to develop EOR techniques to maximize recovery is of great importance. Methods such as chemical flooding, miscible flooding, and thermal recovery involve altering the mobility and/or the IFT between the displacing the displaced fluids. Recovery efficiency was found to be dependent on the capillary number, defined asEquation 1 The viscous forces were defined as the fluid viscosity, flow velocity, and the flow path length. Capillary forces vary with the fluid IFT and the pore geometry of the medium.1 Taber defined the capillary number in terms of the pressure drop between two points, the flow length, and the IFT.2Equation 2 He concluded that as this ratio increased to a value of 5 psi/ft/dyne/cm [0.2 kPa/m/N/m] the ROS was reduced significantly. By decreasing the IFT by using surface-active agents, or by decreasing the path length by altering the field geometry, the capillary number could be increased. Others have shown similar results. Melrose and Brandner,3 for example, indicated that as the capillary number rose to a value of 10–4, the microscopic displacement efficiency, which accounts for the residual saturations to both oil and water, increased. The effects of the capillary number on the recovery of residual oil are given by Chatzis and Morrow4 and by other authors5 (Fig. 1). Few studies, however, have shown the effect of the capillary number on the two-phase flow between the residuals. The variables within this group have been researched, but their combined effect on relative permeabilities has been largely ignored. Several authors have noted that the viscosity ratio of oil and water alters the oil relative permeability but has little effect on that of water.6–8 Few or no changes by fluid flow velocity were observed, provided that no boundary effects were present during the core tests.9–11
It has been customary, in predicting saturation changes, to use the Leverett "fractional flow formula", obtained by eliminating the unknown pressure gradient from the generalized Darcy equations for the separate phases. The formula presents difficulties in the case of counterflow, since the "fractional" flow may be negative, greater than unity, or, in the case of a closed system, infinite. Recently, it has been shown by several authors that the corresponding equations (with capillary pressure and gravity terms) for actual flow of the phase may be used just as well. These equations are in agreement with Pirson's statement that, if the two mobilities differ considerably from each other in a closed system, the flow is largely governed by the lower value. The present study was undertaken because of an apparent lack of experimental data on gravity counterflow with which to test the theory. A 4-ft sandpacked tube in a vertical position was employed. Electrodes for determining saturations by resistivity were spaced along the tube, one phase being always an aqueous salt solution. Air, heptane, naphtha, or Bradford crude oil was used for the other phase. A reasonably uniform initial saturation was set up by pumping the phases through the system, after which the tube was shut in and saturation profiles obtained at definite intervals. Cumulative flows over certain horizontal levels were obtained by integration of the distributions; hence, differentiation of the cumulative flows with respect to time gave instantaneous flow rates. To compare experimental and theoretical flow values, capillary pressures were assumed given by the final saturation-distribution curve. The upper part corresponds to the "drainage" region and the lower part to the "imbibition" region, where trapping of the nonwetting phase occurred. While calculations indicated that the capillary pressure saturation function and, probably, the relative permeability saturation functions changed during the segregation, the relation of the measured rates to saturation distributions are in general accord with the frontal-advance equation. It appears that the Darcy equations, as modified for the separate phases, are generally valid for counterflow due to density differences. The usual method of predicting saturation changes, which involves a continuity equation and the elimination of the unknown pressure gradient from the flow equations, should therefore be applicable. However, the need for advance knowledge of drainage and imbibition "capillary pressures" and relative permeabilities during various stages presents difficulties. Introduction The present study was undertaken because of a seeming lack of experimental data relating to vertical counterflow of fluids of different densities in porous media. In particular, it was desired to determine whether data obtained from these laboratory tests were in accordance with certain mathematical treatments of counterflow which have been proposed. The gravity "correction" has been incorporated into the flow equations (and, hence, into displacement theory) nearly as long as both have been used. Field and laboratory data have generally borne out the validity of the theory as applied, for instance, to downward displacement by gas, with all fluids moving downward. However, the modifications for counterflow have only recently been pointed out. It has been customary to use fractional flow rates instead of actual flow rates in displacement calculations. In the case of counterflow, this results in negative values, values greater than unity and, when rates are equal and opposite, in infinite values. As pointed out by Sheldon, et al, and by Fayers and Sheldon, actual flow rates may be used just as well. The fact that these may be of opposite signs for the two fluids does not present any difficulty. SPEJ P. 185^
This paper gives an overview of method development in quantitative risk analysis for marine terminals and transportation that have been applied to several of the planned LNG and LPG transportation projects in North America. The growth in natural gas production in North America has renewed interest in exporting natural gas, mostly in the form of LNG or LPG. However, this growth comes with transportation challenges as suppliers, and operators move products and equipment, to and from an expanding number of sites (many of them in remote locations). Maintenance of safety and security practices is increasingly important as operations become geographically dispersed and more diverse. Analyses of reliability and risk are potentially most valuable during the early stages of marine terminal projects in guiding the decision on siting, design, and operative risk controls to reduce the risk as low as reasonably practical in final development. An important development in quantitative risk analysis for marine transport is the ability to utilize "big data" resources like Automatic Identification System (AIS) tracking. Utilizing AIS data provides the best available picture of existing traffic in a waterway. Quantitative risk analysis applies historical data as the basis for estimating risk of future accidents. This paper gives examples of how to combine historical data and advanced failure mode modeling to better estimate risk for loss of containment from LNG and LPG carriers. Quantification of accidental release frequencies and consequences of a release are demonstrated in this paper. The risk level for gas terminals and transportation area expressed in terms of individual risk at the terminal and along the transportation route. Newly developed methods make it possible to show the risk along the sailing route, accounting for the variation in traffic and environmental parameters along the route. Understanding of the key drivers of risk is important for the decision-makers to establish adequate risk controls for new energy export projects.
This invest igation was made to e val~ate tbe comparative effects of the viscosity and the phase bebcrvior of the bu{fer fluid in the composite solvent displacement of Bradford crude from water flooded sandstone cores. Buffer slugs of propane, naphtha and other re/ined hydrocarbons exhibiting increasingly favorable viscosity ,ratios and decreasing volubility relationships, respectively, witb Brad/ord crude, were used in long Berea sandstone cores. The secimdary slug was isopropyl alcohol, The resultsindicate tkt higher oil recoveries are obtained for increasingly f avorable p base relationsbips even when these are accompanied by unfavor. able viscosity rattos within the range studied. Moreover, when propane is uked as a buffer slug with an adverse uiscosity ratio of 36, it gives higher oil recoven"es t ban at a similar size slug of an amyl alcohol having a viscosity ratio of L09. Tbe investigation was extended to the study of the effect of flooding rate on oil recovery. ResidualBradford crude was-displaced from a 6-ft Berea sandstone core at rates varying from 0.3 to 30 /t/ day. The results show that as flooding rates were increased above or decreased below a minimum range of 1 to .2 ft/day, displacemeti efficiency increased cormiderably.
This investigation focused on developing an efficient chemical flooding process by use of dilute surfactant/polymer slugs. The competing roles of interfacial tension (1FT) and equivalent weight (EW) of the surfactant used, as well as the effect of different types of preflushes on tertiary oil recovery, were studied. Volume of residual oil recovered per gram of surfactant used was examined as a function of these variables and slug size.Tertiary oil recovery increased with an increase in the dilute surfactant slug size and buffer viscosity. However, low 1FT does not ensure high oil recovery. An increase in surfactant EW used actually can lead to a decrease in oil recovery. Tertiary oil recovery was also sensitive to preflush type. Reasons for the observed behavior are examined in relation to the surfactant properties as well as to adsorption and retention.
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