Conventional core data and analyses of sidewall samples have been compared with data derived from well logs in reservoir rocks of varying lithologies. Correlation of porosity, hydrocarbon and water saturation, and permeability variations makes it possible to use one data set-taking special precautions when only sidewall samples are available-in the absence of other measurements. Introduction The comparison of core data from both conventional and sidewall samples with log-derived data makes possible a more realistic and reliable evaluation of possible a more realistic and reliable evaluation of the reservoir. Unfortunately, published comparisons of rock properties obtained from core and sidewall samples are scarce. Included in the many generalized conclusions in those papers are thatpercussion sample porosities in softer, looser sands are only slightly higher than those of conventional cores;sidewall sample permeabilities are decreased in higher permeability formations; andwater saturations of the sidewall cores are higher and oil saturations slightly lower than those of conventional cores. Although similar conclusions can be drawn from this study, our investigation uncovered additional complications. Comparison of Conventional and Sidewall Samples An example from Offshore Louisiana shows the comparison between conventional cores using a rubber-sleeved core barrel and sidewall samples (Figs. 1 and 2) in a Pliocene sand. Handling of this Pliocene reservoir rock was complicated by its semiconsolidated nature and by the presence of hydratable clays, which gave up water even at room temperatures if exposed for long periods of time. Since the core-gamma ray log showed multiple sand and shale partings corresponding to lithology variations over short distances, it was difficult in many cases to find comparable porosities within a 6-in. interval of the original core sample. Windows were cut in the rubber sleeve, test plugs were removed and the rubber sleeve was plugs were removed and the rubber sleeve was rescaled to preserve the remaining core. As the study progressed it became apparent that the Dean-Stark extraction method for determining saturations was releasing clay-bound water along with pore water, resulting in too high a measurement of water saturation; using the summation-of-fluids method with varying water plateaus gave more reasonable results. Finally, the plateaus gave more reasonable results. Finally, the remaining rubber sleeve was slit lengthwise and a continuous colored photographic log was taken of the core. Such photographs show clearly the varying degrees of both lenticularity and consolidation. The effect of these two core analyses on the porosity and permeability data in this shaly pay sand as reported permeability data in this shaly pay sand as reported by a commercial core laboratory are shown in Tables 1 and 2. We do not mean to imply by the tables that fluid saturations by "summation of fluid" (SOF) is generally or usually better than the Dean-Stark method. In fact, we prefer the latter method over the SOF method almost exclusively. However, in this particular case, the SOF method under closely controlled particular case, the SOF method under closely controlled conditions (not routine procedures) resulted in data that were reasonable and acceptable. A Miocene Gulf Coast formation was also cored using rubber-sleeve coring equipment. JPT P. 1409

INTRODUCTION Historically, downhole production surveys have been run through tubing, after pump and rods have been pulled and the well swabbed, or through the tubing-casing annulus after replacing existing tubing with a small diameter string. In both cases, normal well pumping conditions have been altered to the extent that many production surveys probably have not been representative. Running a production survey while a well is pumping under stabilized conditions allows observation of normal pumping fluid inflow performance. To this extent, a small diameter (7/8 in. oD) combination production logging tool is being used successfully to determine the following:Temperature ProfileInflow Velocity ProfileFluid Density The configuration of the tool allows it to be used in small tubing-casing annulus sizes such as 5 1/2 in. OD casing and 2 7/8 in. EUE tubing. This paper discusses the tool's specifications and configuration, applications and results which are illustrated by field examples. TOOL DESCRIPTION The combination production logging tool has four basic modules that can be run in tandem: a) casing collar locator; b) radioactive tracer section; c) temperature probe; and d) fluid density section (see Figure 1). The outside diameter of the tool is 7/8 in with a total length of approximately 20 feet. Construction is very clear with no protrusions in the tool case that will cause snagging or hanging up on tubing collars.

This evaluation was conducted in connection with an experiment in stimulating formations with multiple nuclear explosions. The values for reservoir properties were obtained by core and computerized log analyses for the nuclear stimulated well and by analysis of pressure buildup tests on another well nearby. Gas production was predicted on the basis of the values obtained. Introduction The existence of major volumes of gas in thick, low-permeability sandstone reservoirs in Colorado, Wyoming, and Utah has tantalized producers for decades. Conventional efforts to obtain commercial production from these resources have been generally production from these resources have been generally unsuccessful, not only because the permeabilities are extremely low (on the order of several microdarcies to several tens of microdarcies) but also because the gas-bearing sandstone beds are generally scattered throughout sand/shale intervals greater than 1,000 ft thick. Typical tight gas reservoirs are found in the Tertiary Fort Union and the Cretaceous Mesaverde formations of the Piceance Basin in northwestern Colorado. These formations have been drilled and conventionally fractured in Rio Blanco County without successfully obtaining commercial production. New gas production operations in this area have been sparked, however, by the potential for successfully stimulating gas production with multiple nuclear explosions. The 94,000-acre Rio Blanco Unit area (Fig. 1) has been established and a nuclear stimulation treatment has been carried out in Well RB-E-01 with three 30-kt explosives. Emplaced at depths of 5,839, 6,230, and 6,690 ft, these explosives should have effectively fractured a 1,300-ft gross section of the Fort Union and Mesaverde formations from 5,530 to 6,830 ft, subsurface. The evaluation of a stimulation treatment's effectiveness is, of course, dependent upon a knowledge of reservoir characteristics, particularly permeability and net pay thickness. The development of such knowledge for conventionally commercial reservoirs is facilitated by a rather extensive base of proved empirical and theoretical relationships. The extent to which this base is applicable to low-porosity and low-permeability reservoirs, such as those in the Fort Union and Mesaverde formations, is uncertain. Because of this uncertainty, greater than normal effort was made to evaluate cores, logs, and production tests. This report presents the reservoir property values obtained and the predictions of gas production based upon these values. production based upon these values. Area Geology The Piceance basin is a northwest trending structural downwarp (Fig. 1). It contains a sedimentary section dating from lower Paleozoic to Tertiary with a maximum thickness of about 30,000 ft. The east-west cross-section (Fig. 2) shows the asymmetric nature of the basin, with gentle dips on the west and steep dips on the east. The surface rock throughout the unit area is the Tertiary Green River formation, which is composed of oil shales, marlstones, and sandstones. The Wasatch formation, consisting of brightly colored clays and shale with minor sandstone, underlies the Green River formation and overlies the Fort Union formation.