Routine permeabilities of tight gas sands are shown to be greater than under reservoir conditions, often by more than a hundred-fold, because of the great relief of stress, absence of connate water, and increased gas slippage. Correlations are presented that can be used to estimate in-situ permeability from routine data. Introduction Yearly compilations of U.S. oil and gas reserves by the American Gas Assn.1 show that U.S. gas reserves reached a maximum in 1967 of nearly 290 Tcf (8×1012 m3). With the exception of the year 1970 when Prudhoe Bay reserves were added, gas reserves have declined at a near-constant rate of 10 Tcf (2.8×1011 m3) per year since then. To help moderate or reverse this trend, the industry is extending its exploration and development efforts to include horizons with permeabilities in about the same range as common cement - i.e., microdarcies. The design of stimulation treatments to achieve commercial rates of production and reliable assessment of potential reserves in such low-permeability rocks demands accurate knowledge of their permeability, porosity, and flow properties. Though meager, there is sufficient information already available in the literature to suggest that some of the flow properties of these rocks differ markedly from those of more permeable rocks and, thus, require closer study. Results of several different studies of the properties of low-permeability gas-producing horizons have been published previously. A study by Thomas and Ward2 showed that the permeability of cores from the Pictured Cliffs and Fort Union formations were affected significantly by confining pressure. Porosities, however, were not altered greatly. They also reported that the presence of a simulated connate water saturation (about 500(0) reduced gas permeabilities to only 10% to 20% of the specific gas permeability. Vairogs et al.3 concluded that very low-permeability rocks are affected by stress to a greater degree than those having higher levels of permeability. This agreed with results reported earlier by McLatchie et al.4 Tannich5 mathematically studied liquid removal from fractured gas wells in low-permeability horizons and concluded that in very low-permeability rocks, cleanup times could be extensive but that permanent formation damage was not likely. The study, however, provided no measured experimental data of the flow properties of low-permeability rocks.

A knowledge of the preferential wetting characteristics of a reservoir can frequently be of assistance to the field or reservoir engineer, particularly in such areas as (1) assessing the particularly in such areas as (1) assessing the applicability of restored state data; (2) interpreting electric logs; (3) selecting well workover fluids; (4) applying laboratory capillary pressure data; and (5) applying special fluid injection processes. Because of this broad usefulness, wettability information was gathered on more than 50 oil-producing reservoirs from many areas of the world. One-half of the reservoirs studied, however, were located in West Texas and Wyoming. The reservoirs studied ranged in depth from 1,700 to 13,000 ft, in temperature from 80 deg. to 240 deg. F; the reservoir oils ranged from 14 deg. to 50 deg. APl gravity. Contact angle measurements in a glass-teflon cell using uncontaminated samples of the reservoir crudes provided a quantitative indication of the ability of the various crudes to wet reservoir rock minerals in the presence of water. The minerals used were selected from petrographic studies of cores fro the reservoirs of interest. For many of the reservoirs studied, flow data on native-state or fresh cores were available to provide a qualitative comparison of the reservoir wetting preference. The results obtained in the contact angle cell tests indicated that for approximately 27 percent of the reservoirs studied, water wets the rock mineral surfaces more strongly than oil; for about 66 percent of the reservoirs, oil wets the rock mineral surfaces more strongly than water; and in the remaining 7 percent of the reservoirs, the mineral surfaces were percent of the reservoirs, the mineral surfaces were not wet strongly by either water or oil. Excellent agreement was found between these results and the qualitative indication of rock wettability obtained from native-state or fresh core relative permeability tests. The tests further showed that contamination by air and certain metallic ions can seriously alter the wetting properties of many reservoir crude oils. Introduction The relative preference of reservoir rock pore surfaces to be wet by water or oil has long been of concern, and perhaps some bewilderment to the oil industry. Several early investigator of the relative wetting tendencies of solids by water and various hydrocarbons found that some solid surfaces exhibited a definite affinity to be wet preferentially by hydrocarbons. Other early research demonstrated that many crude oils contain natural surface-active agents that are readily adsorbed at solid-liquid interfaces to render the solid surface oil-wet. numerous subsequent studies of flow in porous media have demonstrated the porous media have demonstrated the significant effect of rock wetting preference on oil displacement by water. Some of the more recent studies would appear to provide rather conclusive evidence that reservoir rock wetting preference may cove a broad spectrum. however, preference may cove a broad spectrum. however, there is still a strong tendency by some in the industry to accept the implications of research conducted by Leverett and others that all reservoirs are preferentially water-wet. If reservoir rock wetting preference were not an important factor in many aspects of oil production, further elucidation on the subject would be on little practical importance. its real significance, however, practical importance. its real significance, however, can perhaps best be demonstrated by a few examples.1. The quantitative interpretation of water saturation from electric log response by Archie's method requires a numerical value of the saturation exponent, n, which is directly related to wettability.2. In well completions or workovers, it is desirable that the kill fluid or wellbore fluid itself not have a prolonged adverse effect on the well productivity. If a formation is oil-wet, microscopic productivity. If a formation is oil-wet, microscopic trapping of water (as a nonwetting phase), which may have invaded the formation furring its use as a well control fluid, could result in serious, prolonged reduction in formation oil flow rates after putting the well on production. SPEJ p. 531

Oil-water relative permeabilities measured by a steady-state method are given for a broad range of rock wetting conditions. The data show that the degree to which a porous medium is wetted preferentially by oil or water significantly affects the measurement of flow properties and the calculation of reservoir waterflood oil recovery performance. Introduction Calculations of reservoir waterflood performance are frequently based upon oil-water relative permeability relationships measured on cores in the laboratory. Inherent assumptions in such applications of laboratory data are thatthe test samples are representative of the reservoir or some part thereof, andthe core handling and test procedure or conditions do not prevent obtaining representative flow relationships. Of the many factors that can influence the validity of these assumptions, the degree to which the reservoir wetting condition is reproduced in the laboratory flow tests is perhaps the most difficult to assess. Numerous investigators have reported upon the factors that can cause wetting conditions in laboratory core tests to be different from those in the reservoir. Welge perhaps was among the first to recognize that restored-state test procedures may not provide flow characteristics representative of the reservoir. Studies by other researchers have revealed that the important factors that can contribute to changes in core-wetting behavior can be divided into two general categories: those influencing the core-wetting condition before testing, and those influencing them during testing. The factors grouped in the first category arethe well coring fluid,the techniques used in handling, packaging, and preserving cores andthe laboratory packaging, and preserving cores andthe laboratory procedures for cleaning and preparing the cores. procedures for cleaning and preparing the cores. In the second category aretest temperature,test fluids, andthe test technique. These published research efforts have demonstrated the difficulty of retaining reservoir wetting properties in a core sample during laboratory testing. However because of the varied procedures used to detect changes in core-wetting properties, those studies do not show plainly the influence of these changes on core flow behavior. Thus, with perhaps few exceptions, it has not been made clear how these changes affect calculated predictions of reservoir waterflood performance. Our purpose here is to present performance. Our purpose here is to present laboratory experimental flow data that show that the preferential wetting characteristics prevailing in a preferential wetting characteristics prevailing in a core during testing have a marked and qualitatively predictable effect on oil-water relative permeability predictable effect on oil-water relative permeability relationships. Through the use of data covering a range of wetting conditions, we shall demonstrate the significant effect of rock wettability on calculations of reservoir waterflood performance. Test Materials and Procedures The data presented in this paper were obtained on a fired sample of Torpedo outcrop sandstone, 3/4 in. in diameter and 1 3/4 in. long. Additional data were obtained on unfired samples of Berea and Torpedo sandstone and on one fired Berea core, but because of the general similarity of results obtained, data from those tests are not included. The purpose of firing the core (in an electric furnace at 1,600 degrees F for 6 hours) was to stabilize any clay minerals present in the rock pore space and to provide an internal rock surface of as near constant properties as possible. JPT P. 873

Laboratory studies of several factors affecting measurements of relativepermeability were made using the three-section plastic-covered core technique.Results show that the core assembly, properly constructed, will perform as asingle unit, and that the testing technique will, under suitable conditions ofpressure gradient, gas expansion, and migration of partial water saturation, permit measurement of flow characteristics not affected by technique.Wettability equilibrium is readily established in cores exhibiting strongwetting preference to water or oil when initially saturated with water.Laboratory tests must be conducted so that saturation changes represent thosethat occur in the reservoir. Immediate implications of saturation history arethat the possibility exists of increasing the displacement efficiency ofsolution gas drive reservoirs over the natural process, andresidual gassaturations following water flooding in gas or gas condensate reservoirs willbe 15 to 50 per cent pore space rather than 1 to 11 per cent as generallybelieved. Introduction Solutions of petroleum reservoir problems pertaining to productionperformance require the use of true relative permeability characteristics. Thisrelationship of fluid conductivity and saturation has been obtained byreservoir engineers in four ways, namely:From past gross reservoir performance and the extrapolation of this databased on experience,By using published fluid flow relationships obtained in laboratory studieson general type porous materials,By attempting a mathematical derivation of flow behavior, using someexperimentally obtained characteristics of reservoir rocks, andBy laboratory flow tests using representative rock samples of areservoir. The first three methods listed above have shortcomings which make their uselimited or questionable. Production characteristics of only certain processesare obtained from field data and these are not available at the beginning of areservoir's producing life, at which time they are desirable. It is fortuitousif general fluid flow characteristics obtained experimentally have accurateapplication to specific field problems. Also, it is felt that at this timethere is not sufficient knowledge of the flow behavior of oil, water, and gasin porous materials to enable applicable analytical description of this to bemade based on other measured rock characteristics. Measurement of relative permeability in the laboratory offers the only directmethod subject to adequate checking for determination of flow characteristicsapplicable to field problems. Primarily, this paper deals with laboratoryexperiments to establish the effects of several factors on the measurement ofrelative permeability and the practical significance of this knowledge. T.P. 3053

Means for increasing tertiary oil recoveries from previously waterflooded viscous oil reservoirs are receiving added attention today as a result of industry-wide efforts to improve U.S. oil producing rates and reserves. Injection of a bank of polymer solution that precedes injection of a miscible slug (e.g., a micellar fluid) can reduce reservoir permeability contrasts and result in improvement of the sweep efficiency of the process. To evaluate the potential magnitude of improved recovery and economics of prior polymer slug injection, there is a need for basic polymer/oil relative permeability data for use in performance evaluation calculations. Such relative permeability data were measured by steady-state procedures on a suite of 18 out-crop and formation core samples ranging, in permeability from about 50 to 1,200 md. Six different polyacrylamide polymers were tested, and resistance and residual resistance data were obtained on each. Data were obtained in both oil-wet and water-wet systems. The observation in these studies was that the presence of polymers in the water phase had a significant and consistent effect, lowering water relative permeability over the entire water saturation range. In many of the tests, the presence of flowing polymer or its residual effect during subsequent brine flow had no effect on oil relative permeability. In several tests, polymer contact actually improved oil mobility through increases in oil relative permeability at all levels of oil saturation. Permeability level and polymer type produced no clear-cut differences in flow behavior. The obvious differences in core wettability resulted in widely varying relative permeability characteristics, but again the effect of polymer contact was about the same, qualitatively, as obtained on the water-wet cores. Introduction The steady decline of U.S. oil reserves and rapidly, increasing, prices obtained for each barrel of crude produced are strong incentives to maximize recoveries for all reservoirs. Various enhanced oil recovery techniques are being tested and used for recovering some of the oil left behind after conventional waterflooding. The added recovery achievable with such processes, however, is influenced to a large degree by one of the same factors leading to inefficient waterflooding - i.e., reservoir heterogeneity. Numerous laboratory studies using, both physical and mathematical models, plus numerous field projects, have shown that when contrasts in reservoir permeability increase, recovered by any external injection recovery process decreases as a result of reduced sweep efficiency. Thus, if recoveries from the more heterogeneous reservoirs are to be maximized, procedures must be developed for reducing the permeability contrasts before application of an EOR process or by mobility adjustment within the process itself. Preinjection of polymers in advance of a micellar flood has been proposed as a means for improving reservoir sweep efficiency by reducing permeability contrasts. Laboratory tests of this process demonstrated that, in both linear and five-spot stratified systems, the residual resistance effect achieved by preinjection of poly-acrylamide polymers resulted in improved sweep and additional recovery by subsequent micellar flooding. In the one reported field test of this process, tertiary oil was mobilized and recovered, but insufficient data are available to indicate whether the preinjected polymer resulted in improved sweep efficiency. Mathematical model studies provide a reliable means for evaluating potential benefits of polymer preinjection. However, such studies require input data that permit the model to simulate the physical processes that may occur in the reservoir. This laboratory study was conducted to provide such data. SPEJ P. 79^