Schlumberger Technology Corporation

University of Texas System

E-spectrum Technologies, Incorporated

Carlos Torres-Verdin

Ian D Bryant

Metin Karakas

Dean M Homan

John C Rasmus

Min-Yi Chen

David J Rossi

Mukul Mani Sharma

Eric Van Oort

Vladimir L'vovich Druskin

Siddharth Misra

Alberto Malinverno

Thomas David Hosbach

Roman Shor

Jeffrey Gabelmann

Ali Yilmaz

Erich Schneider

Sheng Fang

Mark Allen Oerkfitz

Brian Spies

Systems and methods are disclosed that provide highly accurate and controllable measurements of rock formation properties in a wellbore. The systems and methods utilize a prescribed input signal to mechanically perturb a drill string in contact with a rock formation in order to elicit a mechanical response. Based on the input signal and the mechanical response, a transfer function is computed and analyzed, wherein the analysis uses estimates of the drill string resonances to identify rock formation resonances, which are used, in turn, to determine the rock formation properties.

Sensing formation properties during wellbore construction

Systems and methods for assessing physical properties of a geological formation are disclosed. The systems and methods may use electrodes that include two conductive portions separated by an isolation gap positioned along a casing in a wellbore in the formation. The electrodes may be sequentially energized to provide excitation stimulus into the formation while the remaining, non-energized electrodes may substantially simultaneously receive excitation responses to the excitation stimulus from the formation. The excitation responses may be assessed to determine one or more physical properties of fractures in the formation.

Modular electrode tool for improved hydraulic fracture diagnostics

A method for determining a level of organic maturity of a shale gas formation includes inverting multifrequency complex conductivity data to estimate a volume fraction of graphite, turbostatic carbon nanostructures, and pyrite. The inversion is validated using estimates of the volume fraction of graphite, turbostatic carbon nanostructures, and pyrite. The volume fraction of graphite and turbostatic carbon nanostructures is correlated to a level of organic maturity log of the shale gas formation. The level of organic maturity log is validated using sulfur content obtained from pyrolysis or vitrinite reflectance. A variation of an electromagnetic response due to the volume fraction of graphite, turbostatic carbon nanostructures, and pyrite is quantified. The electromagnetic response is modified by removing the quantified variation to obtain resistivity and permittivity values.

Subsurface estimation of level of organic maturity

Disclosed herein methods for determining a property of a formation, for example, when well logging, by feeding a gadolinium tracer fluid into the formation, applying an emitted radiation to the formation to thereby produce a signal, such as a neutron signal, and capturing the signal from the formation.

Tracers for formation analysis

Methods for locating an oil-water interface in a petroleum reservoir include taking resistivity and pressure measurements over time and interpreting the measurements. The apparatus of the invention includes sensors preferably arranged as distributed arrays. According to a first method, resistivity and pressure measurements are acquired simultaneously during a fall-off test. Resistivity measurements are used to estimate the radius of the water flood front around the injector well based on known local characteristics. The flood front radius and fall-off pressure measurements are used to estimate the mobility ratio. According to a second method, resistivity and pressure measurements are acquired at a variety of times. Prior knowledge about reservoir parameters is quantified in a probability density function (pdf). Applying Bayes' Theorem, prior pdfs are combined with measurement results to obtain posterior pdfs which quantify the accuracy of additional information. As new measurements are acquired, posterior pdfs, updated for expected temporal variations, become prior pdfs for the new measurements. According to a third method, uncertainty about the reservoir parameters is represented by Gaussian pdfs. The relationship between measurements and reservoir parameters is locally approximated by a linear function. Uncertainties are quantified by a posterior covariance matrix.

Methods and apparatus for dynamically estimating the location of an oil-water interface in a petroleum reservoir

Inception of hydrocarbon extraction from a reservoir causes the oil-water interface to warp and cusp toward the extraction gates along a well. This invention proposes time-lapse DC/AC measurements with an array of permanently deployed sensors in order to detect and estimate the change in geometry and proximity of the oil-water interface as a result of production, and therefore as a function of time. The estimation is carried out with a parametric inversion technique whereby the shape of the oil-water interface is assumed to take the form of a three-dimensional surface describable with only a few unknown parameters. A nonlinear optimization technique is used to search for the unknown parameters such that the differences between the measured data and the numerically simulated data are minimized in a least-squares fashion with concomitant hard bound physical constraints on the unknowns. The proposed estimation procedure is robust in the presence of relatively high levels of noise and can therefore be used to anticipate deleterious water breakthroughs, as well as improve the efficiency with which the oil is produced from the reservoir.

Method for sensing and estimating the shape and location of oil-water

Growing community of inventors

Austin, TX, United States of America

Carlos Torres-Verdin