Relative permeability hysteresis has been measured for a water-wet outcrop rock sample and a mixed-wet reservoir core. For the oil phase, imbibition and drainage relative permeability curves differed significantly. The difference was much less pronounced for the water phase. Scanning curves, which characterize transitions between imbibition and drainage curves, were also measured. A notable characteristic of the oil relative permeability scanning curves is their reversibility; along most of the length of a scanning curve, oil relative permeability exhibits no hysteresis. A proposed mechanism for the reversible behavior is pinning of water-oil interfaces on surfaces of rock grains. Pinned interfaces remain anchored at fixed positions on grains despite changes in interface curvature and contact angle. In water-wet samples, pinning can occur as a result of contact angle hysteresis. In mixed-wet rock, pinning can occur at the boundaries between water-wet and oil-wet grain surfaces. As long as interfaces remain pinned, pore-level fluid geometry is a function of saturation only, and does not depend on the direction of saturation change. Introduction Relative permeability curves, which characterize simultaneous multi-phase flow in porous rock, are important in understanding and predicting the performance of immiscible displacement processes in oil and gas reservoirs. Hysteresis in both relative permeability and contact angle has long been recognized. In the case of relative permeability, two-phase flow properties of a porous medium depend on which phase is increasing in saturation, For contact angle, measured values depend on which phase is advancing over a solid surface, Numerous studies have reported hysteresis data for either relative permeability or contact angle, but little work has been done to link the two phenomena. This paper attempts to make such a linkage by showing that relative permeability data exhibit a hysteresis pattern that would be expected if fluid geometries are controlled by contact angle hysteresis. For the two water-oil systems investigated here, relative permeability scanning curves, which describe flow when the direction of saturation change is reversed, are shown to be reversible over limited saturation ranges. Under these conditions, we propose that contact angles will change between maximum and minimum values while water-oil interfaces remain pinned at fixed positions on grain surfaces. As long as the interfaces remain pinned, changes in fluid geometry are reversible. Outside the range of reversibility, contact angles are at their limiting values, interfaces move along grain surfaces, and fluid geometries are controlled by processes that result in hysteresis. Terminology Processes in porous media that involve decreases in the saturation of the wetting phase are commonly referred to as "drainage". We use that term here to refer to decreases in water saturation for a water-oil system regardless of rock wettability. "Primary drainage" relative permeability curves are those measured while decreasing the water saturation from 100%, while "secondary drainage" curves involve a decrease from the high water saturation occurring when immobile oil is present.

Gas shales have gained significant attention in recent years as a source of natural gas, resulting in significant focus on storage and flow mechanisms in these rocks. The permeability of shale reservoirs is a key control that determines the producibility and profitability of the resource. In contrast to conventional reservoir rocks, gas shales have significant organic content and, often, most of the pores are in the organic matter. Furthermore, most pores are in the 1–100 nanometer size range, and gas can be stored in these pores as sorbed gas as well as free gas, which has raised concerns such as deviation of the flow mechanism from Darcy flow, and the effect of sorption on permeability in shales. The common industry practice of measuring permeability using crushed rock samples and helium as test gas at room conditions has been found to have a number of shortcomings, including inconsistent results reported by different laboratories using such methods. In this paper we present the results of steady-state permeability measurements on shale samples conducted at reservoir conditions, and demonstrate the effect of stress, pressure, temperature, sorption, and type of gas utilized for measuring permeability of intact shale samples. The results presented in this paper show that net stress, pore pressure, and temperature have strong effects on permeability of shales. Additionally, we show that the type of gas utilized for measurements, and sorption phenomenon can have a significant influence on the measured permeability, particularly for organic rich samples such as gas shales. We also demonstrate through examination of Klinkenberg flow model, that currently, with the exception of the effect of pressure on permeability, no existing model accurately predicts the effects of other factors such as temperature and type of gas on permeability of shale samples in the absence of actual experimental measurements. This paper documents that there may be significant errors associated with measurements that are conducted at room conditions using non-reservoir or non-sorbing gas, and accurate permeability measurements require tests to be conducted at conditions that are close to the in-situ conditions. Accurate permeability measurements conducted at reservoir conditions enable superior characterization, supporting sound business decisions in the development phase of a project, and more accurate production forecasting in the production phase.

Determination of permeability of unconventional reservoirs is critical for reservoir characterization, forecasting production, determination of well spacing, designing hydraulic fracture treatments, and a number of other applications. In many unconventional reservoirs, gas is produced from tight rocks such as shale. Currently the most commonly used industry method for measuring permeability is the Gas Research Institute (GRI) technique, or its variants, which involve the use of crushed samples. The accuracy of such techniques, however, is questionable because of a number of inadequacies such as the absence of reservoir overburden stress while conducting these measurements. In addition to questionable accuracy of crushed rock techniques, prior studies have indicated that there is significant variability in results reported by different laboratories that utilize crushed-rock technique to measure permeability on shale samples. Alternate methods are required to obtain accurate and consistent data for tight rocks such as shales. In this paper we discuss a robust steady-state technique for measuring permeability on intact tight rock samples under reservoir overburden stress. Permeability measurement standards for low permeability samples are critical for obtaining consistent results from different laboratories making such measurements, regardless of the method used for measuring permeability. In this paper we present permeability measurement standards developed based on first principles that serve as the "ground-truth" for permeability in the 10 -10,000 nanoDarcy range. These standards can be used to calibrate any permeability measurement apparatus used to measure permeability on intact tight rock samples such as shales, to enable delivery of consistent results across different laboratories conducting measurements on intact tight rock samples.

A steady-state technique for measuring oil-water relative permeability curves is presented. The technique allows measurements to be made on preserved core samples at reservoir temperature and pressure, using reservoir fluids. Live oil and brine are circulated simultaneously through the core in a closed system, and relative permeability data are taken when conditions in the core have stabilized. A series of five to ten flow rate ratios is normally used, providing data at saturations ranging from irreducible water to residual oil. Saturations are determined by monitoring the oil content of a high-pressure oil-water separator in the system. The technique is particularly useful for heterogeneous cores and cores with mixed wettability, where dynamic displacement tests can give inaccurate relative permeability data. The use of reservoir conditions and live fluids is preferred because the true wettability of reservoir rocks may not be preserved in tests performed with dead crude or at room temperature. Data is presented which demonstrates the application of this steady-state technique to the study of relative permeability hysteresis.

An unusual complication of cancer metastasis to the central nervous system is subdural hematoma due to obstruction of dural vessels by tumor cells. Such a case is presented to call attention to this rare but treatable entity which should be included in the differential diagnosis in any cancer patient with unexplained neurologic signs or fluctuations in state of consciousness.