The stresses that evolve in a thermally shocked liquid were examined. The magnitude and time duration of stress transients generated by a Q-switched ruby laser were measured in the absence of a phase change and compared with results calculated from a simplified thermodynamic model. It is shown that the model agrees with experimental data over a wide range of incident electromagnetic intensity and for large variations of liquid properties. Results are also presented to show the effect of liquid vaporization on the stress transients and the parameters associated with formation of a gas phase.

An investigation of equivalent pore entry radii in typical samples of petroleumreservoir rock and the pore volume associated with each value of pore entryradius has been made. Theoretical discussions together with experimentalprocedures for obtaining pore entry radii and the distribution of pore volumewith pore entry radii are presented. Experimental results on a number of coresamples, along with typical distribution curves, are shown. Data on the percent of the pore volume filled by mercury at a pressure of 1500 psi areincluded. The results of re-runs of samples, made possible by regenerativeapparatus, show the repeatability of the data and indicate the amount ofphysical change in the samples by mercury penetration. Theoretical equationsfor calculating permeability from pore size distribution data were derived andthe results of such calculations are compared with measured gas permeabilitydata. The effect of the shape, surface area, and weight of the sample on thepore size distribution of reservoir rocks was investigated experimentally.Mercury capillary pressure curves are compared with those obtained by theporous diaphragm method using gas to displace water. Introduction Standard core analysis techniques, in general, lead to quantities which arestatistical averages of the varying properties of the samples underexamination. Although such statistical information has real value in predictingthe gross performance of porous bodies, it fails to provide fundamentalinformation concerning the properties of the porous medium itself or anyprocesses which may be occurring in it. For example, a gas permeabilitymeasurement on a core sample is an indirect way of determining an average poreradius for that particular sample. Since there are many combinations of poreradii that will give the same radius, and, hence, the same permeability, noinformation is obtained on the pore size distribution. Furthermore, similarvalues in permeability do not imply similarity in other properties of a porousmedium. For instance, it is possible to have two core samples with identicalpermeability which would have different residual oil contents at the end of anair-oil drive, or even different amounts of interstitial water. It has been recognized for some time by the petroleum industry that adetermination of pore size distribution for porous reservoir rocks offeredpromise of increased understanding of fundamental flow processes in the porousmatrix, and therefore of petroleum reservoir performance in general. T.P. 2893

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 36–43. Abstract The effect of fluid-flow rate and fluid viscosity on oil-water relative permeability determinations was studied using the "dynamic flow technique." In this work relative permeability curves were obtained for homogeneous small core samples from several sandstone outcrop formations. Radio-tracers were used for the determination of fluid saturation and for the detection of saturation gradients. Cobalt–60 in the form of cobaltous chloride was used as a water-phase tracer in some of the experiments. Iodine–131 in the form of iodobenzene and Mercury–203 in the form of mercury diphenyl were used as oil-phase tracers in other experiments. Flow rates for each phase were varied within a range of 2.5 to 140.6 ml/hr. Oil-phase viscosities under flowing conditions were varied from 0.398 to 1.683 cp. The relative permeabilities obtained were found to be solely a function of saturation and independent of flow rate, provided there was no saturation gradient induced in the core sample by "boundary effect." Even though equilibrium with respect to flowing conditions was obtained at the lower flow rates, where a saturation gradient exists, this equilibrium is of a "contingent" -type rather than the "steady-state" equilibrium implicit in the relative permeability concept. The only effect of increasing the oil or non-wetting phase viscosity was to decrease the flow rate required for the elimination of the boundary effect. Fairly good agreement between experimentally determined and calculated values of the boundary effect was obtained when the non-wetting oil phase was the only flowing phase. Introduction In the characterization of reservoir rock, as well as in the solution of reservoir production problems, it is most desirable to have reliable relative permeability measurements for the rock and fluids of interest. Many techniques have been developed for the laboratory determination of the relative permeability of both large and small core samples. In varying degree, difficulties attend the use of all of the methods. Each of the methods requires the metered flow of fluids of known viscosity through the core sample under conditions wherein the pressure drop in the individual flowing phases can be measured or closely approximated. Since the relative permeability is a function of the saturation and distribution of the flowing fluids, some means of obtaining such information is also required.

Use of the borehole gravity meter (BHGM) to measure remaining oil saturation is a method new to the industry. The technique is described, and its applicability to Middle East reservoirs is discussed. Results of an extensive error analysis are presented. The method, which we call log-produce-log, consists of running a base BHGM before significant production, and a later BHGM after production. The remaining oil saturation is computed from the difference of the two BHGM measured bulk densities. The Middle East oil fields are ideal for application of this method. Porosities are high, crude is light, and connate water is dense (saline). The method is independent, for all practical purposes, of hole size, rugosity, number of casing strings, shale content, and acidization. The method also has a very large radius of investigation, 50 feet plus, which enables it to sense a far larger volume of the reservoir than any other method. As reservoirs are often heterogeneous in both porosity and fluid saturations, the remaining oil saturation thus determined would be more representative of the reservoir as a whole than any other technique. The disadvantages of the method are the need for a base BHGM log prior to significant production from the zone of interest, and a poor vertical resolution of about 10 feet. Results of a comprehensive and realistic error analysis are presented and show this technique as possibly the most accurate Sor method.

No abstract