Parity violating target asymmetry in electron - proton scattering

We analyze the parity-violating (PV) components of the analyzing power in elastic electron-proton scattering and discuss their sensitivity to the strange quark contributions to the proton weak form factors. We point out that the component of the analyzing power along the momentum transfer is independent of the electric weak form factor and thus compares favorably with the PV beam asymmetry for a determination of the strangeness magnetic moment. We also show that the transverse component could be used for constraining the strangeness radius. Finally, we argue that a measurement of both components could give experimental information on the strangeness axial charge.Comment: 24 pages, Latex, 5 eps figures, submitted to Phys.Rev.

Relative Permeabilitties In Two-Phase Flow Through Porous Media: An Application Of Effective Medium Theory

Abstract A mathematical model of immiscible two-phase (oil/water) flow through a porous medium is proposed. The model is composed of a simple cubic lattice of cylindrical tubes having a distribution of cross-sectional radii. It is assumed that the wetting fluid (water) flows through tubes of radii less than a and the nonwetting fluid (oil) flows through tubes of radii greater than a, where a depends on saturation. Using effective-medium theory (E.M.T.), the relative permeabilities of both fluid phases are determined as functions of saturation. The permeabilities become zero at saturations which correspond to the residual saturation of the non-wetting phase and the irreducible saturation of the wetting phase. The model is extended in an appendix to include an intermediate range of tube radii through which both oil and water flow. This extended model predicts that at fixed saturation the relative permeability of the oil increases with viscosity ratio whereas that of the water is independent of this ratio. The dependence on temperature of the cutoffs in the relative permeabilities (at residual oil and irreducible water saturations) is interpreted as a variation with temperature of the range of tube radii carrying both oil and water. Introduction In constructing a mathematical model of the transport properties of disordered materials, such as porous media, a random conductance (e.g. electrical or hydraulic) network is often used to simulate these properties. Perhaps the simplest approximate theory of the transport phenomena is the so-called effective medium theory (E.M.T.), applied to such a model. In E.M.T., a uniform effective network, that is one having the same conductance for each element of the network, is assumed. One then requires the same average local field to be obtained from the average transport parameter as from the original random transport parameter. The E.M.T. has been applied with considerable success to various electrical and optical phenomena in random mixtures. We base our theory on the work or Kirkpatrick(1) who used E.M.T. to derive the electrical conductance of a mixture or materials, interspersed at random on a regular three dimensional lattice. The model or the mixture is a connected regular network of resistors. A typical resistor has a conductance g, with a normalized distribution f(g), i.e., f(g)dg is the probability that a resistor located anywhere in the network has a conductance in the range g, g + dg. This model or random resistors is replaced by an effective medium consisting or the same network but of equal conductances, gm given by the relation Equation (1) (Available in full paper) where z is the coordination number of the lattice network. Consider the special case where a fraction, p, of the resistors have a given conductance which we take as unity and the remaining (1-p) zero conductance. This means Equation (2) (Available in full paper) where δ denotes the Dirac delta function. Equation (1) now reduces to Equation (3) (Available in full paper) The relation between gm and p is therefore a straight line in which gm goes to zero where p = 2/z. </jats:sec

Steam Corefloods With Concurrent X-Ray Ct Imaging

Abstract A series of steam corefloods has been performed utilizing X-ray CT imaging to monitor phase saturations during the floods. A numerical simulator was used to analyze the experimental results. The steamfloods of initially water-filled sand packs were carried out at low enough flow rates that capillary pressure was comparable in magnitude with viscous pressure drop. Numerically marching the observed pressure drops provided a significant test of the assumed steam-water capillary relationship. A capillary pressure curve of Leverett j-function form was found suitable for the simulations. The steam relative permeability curve was found by numerically matching both pressure drop and CT saturation data. The expected steam frontal behaviour was seen in the CT images, but the images also revealed unexpectedly large variations in water saturation transverse to the steam propagation direction. Although core porosity derived from the CT images showed no significant variation across the core, it was hypothesized that small variations in steam-water capillary pressure could have resulted from more subtle core packing variations. The expected type of core heterogeneity was subsequently confirmed by subjecting the core to petrographic image analysis. Numerical simulations embodying a realistic degree of core heterogeneity were able to reproduce the transverse saturation variations as a consequence of capillary crossflow. Introduction The steam displacement or ‘steam drive’ method is one of the major techniques for thermal recovery and has been intensively studied both theoretically and experimentally. Particularly important from a theoretical standpoint was the work of Miller(1) showing that the frontal propagation of steam was far more stable than that of a non-condensible gas. Although many analytic methods have been developed and used for simplified predictions(2, 3, 4), in most practical situations a numerical simulator is employed to model steam processes. A fundamental physical property required for the simulation of steam-based processes is the relative permeability of steam. Customarily, numerical models treat steam flow in the same manner as the flow of any ocher reservoir gas. As noted by Sanchez and Schechter(5) there is little direct evidence to support this assumption. Indeed, the issue of steam relative permeability has generated debate in the literature right up to the present. For example, Sanchez and Schechter(5) and Closmann and Vinegar(6) present experimental results confirming the similarity between steam and non-condensible gas relative permeabilities. Verma et al.(7) however, find that steam relative permeability is significantly higher than that of a non-condensible gas. The latter authors further argue that it is reasonable to expect such differences because of the possibility of phase transformation in the flow channels. Because of the diversity of opinion surrounding the basic issue of relative permeability, it is important to investigate steam flow using a range of tools. In particular, the technique of X-ray computed tomography (CT) provides the possibility of monitoring fluid saturations while processes are taking place in a laboratory coreflood experiment. This relatively new technique in petroleum research has already proven itself to be very useful in a wide range of experimental studies(6, 8, 9, 10). </jats:sec

A Multidisciplinary Approach To Reservoir Characterization: The Provost Upper Mannville B Pool

Abstract The Provost Upper Mannville B Pool of the heavy oil belt in east central Alberta is contained in McLaren Formation sands of Upper Mannville (Lower Cretaceous) age. The reservoir is up to 35 m thick and contains local areas of underlying water, a water-in-oil transition zone and patches of overlying gas. The reservoir sands were deposited in fluvial environments filling the McLaren valley as it was aggraded during a sea level rise. The sands are mineralogically mature and composed predominantly of quartz. The reservoir pore systems are being characterized using petrographic image analysis techniques. Actual pore images obtained from thin sections are used to provide petrophysical data and to correlate the pore systems with geological facies. An important feature of the reservoir is the presence of zones of shale clasts in a sand matrix. These zones vary in thickness from several centimetres to several metres. Shale clasts constitute as much as 85% by volume in some zones and thus represent a significant barrier to vertical fluid flow. In order to numerically simulate the impact of the shale clast zones on recovery processes, parameters such as kh and kv have to be estimated. To arrive at realistic parameters, small-scale numerical models, based on actual clast distributions from core, have been constructed and equivalent alues for kh and kv have been obtained at the core and grid block scale. Introduction The oil sands and heavy oil deposits of western Canada with their impressive (471.6 × 109 m3(1–3)) resources represent Canada's "ace-in- the-hole" for future energy resources. Of these resources only a small portion is recoverable by mining methods. The greatest percentage must be recovered by in situ techniques. The oil sands and heavy oil reservoirs are complex and heterogeneous, and an integrated team of geologists, petrophysicists, reservoir engineers and numerical modellers is needed to develop processes specific to particular reservoirs for the recovery of these resources. These recovery processes need to be based on a detailed characterization of the reservoir. It was with this in mind that the Alberta Geological Survey, in its Joint Oil Sands Geology Program with the Alberta Oil Sands Technology and Research Authority (AOSTRA) and the Alberta Department of Energy, initiated a project to characterize oil sands/heavy oil reservoirs. The objective is to develop and evaluate techniques for the detailed characterization of oil sands and heavy oil reservoirs for use in numerical process simulations. This paper reports on studies carried out in the Provost Upper Mannville B Pool In this project a detailed geological characterization of the reservoir has served as a basis on which specific aspects of the reservoir description (or characterization) are focussed on, using novel techniques. The pore systems of the more "uniform" portions of the reservoir have been characterized at the pore scale using petrographic image analysis techniques and relating geology to permeability. </jats:sec

Investigation of the VAPEX Process Using CT Scanning and Numerical Simulation

Abstract The "VAPEX" process, a solvent analogue of Steam Assisted Gravity Drainage, has attracted considerable attention as a recovery method for heavy oil. However, to date, there are still many questions about the nature and magnitude of basic process mechanisms, and whether the process can produce economic oil rates. The experiments discussed in this paper were aimed at quantifying some of the basic mechanisms, in particular the dispersive mixing mechanism. We have performed a series of topdown solvent injection experiments under varying conditions, utilizing a CT scanner to monitor fluid movements. All of the displacements we have observed are gravity-unstable in the early stages, and characterized by viscous fingering of the solvent into the 5,500 cP oil. After solvent breakthrough, the displacements become stable, dominated by a single solvent finger which has many of the features of a VAPEX solvent chamber. The "mixing parameter" we infer for these experiments using the Butler/Mokrys analytic model is higher than that reported for Hele-Shaw VAPEX experiments. An analysis of localized fluid velocities in the experiments using numerical simulation shows that the enhanced mixing parameter can be understood as a consequence of convective dispersion in the porous medium. By adjusting the amount of physical dispersion, the simulations can match breakthrough time, post-breakthrough oil rates, and the general character of the fingering. A novel type of "quasi-pore scale" simulation grid appears to provide advantages in simulating the unstable period at the beginning of the displacements. Introduction Compared with steam-based processes such as Steam Assisted Gravity Drainage (SAGD) for recovery of heavy oil, solventbased processes offer the possibility of reduced energy consumption and greenhouse gas production. However, they are mechanistically complex, and questions remain regarding their expected performance. To date, no field data are publicly available to answer these questions. One solvent-based process that has been proposed is the Vapour Extraction (VAPEX) process(1, 2). This solvent analogue of SAGD utilizes gravity as the driving agent, and solvent dilution of the heavy oil as the mobilization mechanism. The concept of the process is illustrated in Figure 1. A practical, solvent-based recovery process will depend for its success on the interplay of a number of phenomena. Some of the most important of these are: diffusion/dispersion, viscous fingering, capillary-driven mixing (in the case of a gaseous solvent), and the effects of reservoir heterogeneity. The first three are accessible for study in the laboratory, and understanding their interplay at the laboratory scale is a first step toward predicting their effects in a field process. Numerical simulation is required both to extrapolate laboratory experience to the field scale, and to incorporate the effects of reservoir heterogeneity. The study described in this paper addresses the phenomena of diffusion/dispersion and viscous fingering based on a series of laboratory experiments, combined with numerical simulation. Our initial experiments utilized a liquid solvent; therefore capillary mixing effects were absent. Future work will extend the results to gaseous solvents. </jats:sec