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.

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An overview is given of the development and field testing of a non-thermal, viscous oil recovery technology that injects into a reservoir oil-external solids-stabilized emulsions (SSE) as a displacement fluid. The emulsion is generated on site using produced crude oil and water. Small amounts of added mineral fines are used to enhance the performance of naturally present surface-active components in the oil. Gas is dissolved into the oil to adjust the viscosity of the injected emulsion to be similar to that of the in situ oil. SSE fluid displaces viscous oil in a miscible-like manner with favorable mobility, which leads to to improved displacement and recovery. SSE is generally applicable to reservoirs with in situ oil viscosities of up to approximately 3000 cP and permeabilities on the order of one Darcy or more.A series of laboratory tests were conducted to confirm the effectiveness of solids-stabilized emulsions as displacing agents. Specialized coreflood were used to measure emulsion stability, confirm process understanding, and to determine displacement efficiencies. After lab testing and reservoir modeling, a field pilot of the SSE process was designed, constructed, and operated. The field piloting confirmed the ability to generate and sustain injection of a solids-stabilized emulsion in the field and to propagate stabilized emulsions in the reservoir. IntroductionRecovery is challenging for viscous-but-mobile oils that have in situ oil viscosities of tens to several thousands of centipoise. Cold-flow primary recovery and waterflooding are often proven, cost-effective ways to recover viscous oils. Unfortunately, these recovery methods may leave the majority, and sometimes the vast majority, of the viscous oil in the reservoir. Without aquifer support, primary recovery of viscous oils typically suffers from limited drive energy. Waterfloods provide drive energy, but the unfavorable mobility ratio between the injected water and in situ oil usually leads to inefficient displacement and low recoveries. Polymer flooding, which adds a water-soluble polymer to injected water to increase its viscosity, can sometimes be used to improve viscous oil displacement and recovery, but economic application is typically limited to reservoirs of moderately low salinity and temperature. Steam-based methods can be used for improved recovery of viscous oils, but these methods may be costly to implement, especially in thin reservoirs, and may be impractical in deep reservoirs.

A theoretical model has been developed to predict the thermal performance of inert, direct-fired, woven-metal fiber-matrix porous radiant burner. The local chemical heat release was modeled by a detailed mechanism, and convection heat transfer between the gas and the solid phases in the burner was described by an empirical heat transfer coefficient. The solid matrix was modeled as a gray medium, and the discrete ordinates method was used to solve the radiative transfer equation to calculate the local radiation source/sink in the energy equation for the solid phase. The fully coupled nature of the calculations without external specification of flame location represents a key advance over past efforts towards modeling of porous radiant burners, because for a given mass flow rate the actual heat loss from the flame determines its position and is not a free parameter. The calculated results for the burner surface temperature, the gas exhaust temperature and the radiation efficiency for a single layer Fecralloy burner were compared with experimental data from this laboratory and reasonable agreement was obtained for a range of operating conditions.