No abstract

This work addresses the problem of estimating Klinkenbergcorrected permeability from single-point, steady-state measurements on samples from low permeability sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability (i.e., referred to as the Klinkenbergcorrected permeability) has been under investigation since the early 1940sin particular, using the application of "gas slippage" theory to petrophysics by Klinkenberg. 1 In the first part of our work, the applicability of the Jones-Owens 4 and Sampath-Keighin 5 correlations for estimating the Klinkenberg-corrected (absolute) permeability from singlepoint, steady-state measurements is investigated. We also provide an update to these correlations using modern petrophysical data. In the second part of our work, we propose and validate a new "microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work is based on a more detailed application of similar concepts employed by Klinkenberg. In fact, we can obtain the Klinkenberg result as an approximate form of our result. Our theoretical "microflow" result is given as a rational polynomial in terms of the Knudsen number (the ratio of the mean free path of the gas molecules to the characteristic flow length (typically the radius of the capillary)). The following contributions are derived from this work: •Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for low permeability samples. •Development and validation of a new "microflow" model which correctly represents gas flow in low permeability core samples. This model is also applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model, although our new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction model.

We measured Mercury Injection Capillary Pressure (MICP) profiles on tight shale samples with a variety of sample sizes. The goal was to optimize the rock preparation and data reduction workflow for determining the storage properties of the rock, particularly porosity, from MICP measurements. The rock material was taken from a whole core in the Cretaceous Eagle Ford Formation in the form of a puck or disc. A horizontal 1 inch core plug was cut from this disc and the remaining material was subsequently crushed and sieved through various mesh sizes. MICP profiles up to 60,000 psia were then measured on the 1 inch plug and all of the various crushed and sieved rock particle sizes. In parallel we subsampled the plug material to measure bulk volume, grain volume, and porosity using a crushed rock helium pycnometry method. These additional measurements provided a comparison set of standard petrophysical properties from which we could compare the MICP results. In general our MICP profiles show a very strong dependence on sample size due to two reasons: pore accessibility and conformance. We verify the conformance correction approach of Bailey (2009) which specifically accounts for the pore volume compression of the sample before mercury has been injected into the largest set of interconnected pore throats. This new method is preferred over the traditional method of conformance correction when compared to crushed rock helium porosity since the latter is performed at unstressed conditions. Our results using Bailey’s (2009) method reveals that the -20+35 sample size is optimal for determining porosity in the Eagle Ford, and potentially other tight oil and gas shales. We use mercury injection for determining the various storage properties of tight shale because helium porosimetry is not always possible on fine cuttings samples. There are many instances when limited cuttings may be the only source of rock information available before a whole core is taken. Cuttings profiles also provide a key insight over long formation intervals that may not be available from whole core. Cuttings and core profiles for use in calibrating well logs have proven to be a requirement in these ultra-low perm systems.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis work addresses the problem of estimating Klinkenbergcorrected permeability from single-point, steady-state measurements on samples from low permeability sands. The "original" problem of predicting the corrected or "liquid equivalent" permeability (i.e., referred to as the Klinkenbergcorrected permeability) has been under investigation since the early 1940s -in particular, using the application of "gas slippage" theory to petrophysics by Klinkenberg. 1 In the first part of our work, the applicability of the Jones-Owens 4 and Sampath-Keighin 5 correlations for estimating the Klinkenberg-corrected (absolute) permeability from singlepoint, steady-state measurements is investigated. We also provide an update to these correlations using modern petrophysical data.In the second part of our work, we propose and validate a new "microflow" model for the evaluation of an equivalent liquid permeability from gas flow measurements. This work is based on a more detailed application of similar concepts employed by Klinkenberg. In fact, we can obtain the Klinkenberg result as an approximate form of our result. Our theoretical "microflow" result is given as a rational polynomial in terms of the Knudsen number (the ratio of the mean free path of the gas molecules to the characteristic flow length (typically the radius of the capillary)).The following contributions are derived from this work:• Validation and extension of the correlations proposed by Jones-Owens and Sampath-Keighin for low permeability samples. • Development and validation of a new "microflow" model which correctly represents gas flow in low permeability core samples. This model is also applied as a correlation for prediction of the equivalent liquid permeability in much the same fashion as the Klinkenberg model, although our new model is substantially more theoretical (and robust) as compared to the Klinkenberg correction model.

A series of experiments to measure the water solubility in supercritical nitrogen and carbon dioxide have been conducted at experimental conditions up to 483 K and 134 MPa. The accuracy of the experimental procedure is verified by comparing the water content data of methane in the literature and our experimental data for the methane−water system. In addition, a fugacity−fugacity approach including the cubic-plus-association equation of state (CPA EoS) and a fugacity−activity approach based on the Peng−Robinson EoS and the Henry’s law model are incorporated to predict the water content data of methane, nitrogen, and carbon dioxide. A comparison between our experimental data, literature data, and the results of the fugacity−activity approach shows the reliability of the PR-Henry’s law model for the phase behavior studies of the nitrogen−water system over a wide range of pressure and temperature conditions. However, the CPA equation is not capable of reproducing the high pressure vapor and liquid phase compositions of the water−nitrogen system. The concept of cross-association satisfactorily improves the performance of the CPA equation of state in predicting the water content data of supercritical methane. On the basis of the literature and new measured data in this study, it has been found that the CPA equation better represents the phase behavior of the water−carbon dioxide system if carbon dioxide is considered as a self- and cross-associating molecule.