Schlumberger Technology Corporation

Other

Charles Flaum

Robert L Kleinberg

James E Galford

Lalitha Venkataramanan

Martin D Hurlimann

Michael Lynn Evans

Darwin V Ellis

Austin Boyd

Mark Flaum

Robert Allen Badry

Oliver Clinton Mullins

Christian Stoller

Abdurrahman Sezginer

Peter Speier

Terizhandur S Ramakrishnan

Yi-Qiao Song

Robert Freedman

Xu Wu

Anthony R H Goodwin

Chanh Cao Minh

Nicholas J Heaton

Richard J Radtke

Raghu Ramamoorthy

Martin D Hürlimann

Hubert D Scott

Shawn David Taylor

Christopher Edward Morriss

Steven F Crary

Christian Straley

Naoki Saito

Olivier Faivre

Charles Franklin Morris, Jr

Steven V Ducket

Steven W Ducket

Steven W Duckett

Methods and apparatus for the characterization of formation fluids are disclosed. A downhole tool disposed in a borehole penetrating a subterranean formation obtains a NMR measurement, effects a change in a characteristic of the formation fluid, and obtains another NMR measurement subsequent to the change. Alternatively, the downhole tool effects a radial gradient of a characteristic of the formation and obtains NMR measurements at two or more selected radial distances from the wellbore wall. A parameter representative of the subterranean formation or the formation fluid is further determined from the NMR measurements.

Methods and apparatus for monitoring a property of a formation fluid

A drilling operation wherein a borehole can be drilled through earth formations with a drill bit at the end of a drill string, using recirculating drilling mud that flows downward through the drill string, exits through the drill bit, and returns to the earth's surface in the annulus between the drill string and the borehole wall, at least a portion of which has a mudcake thereon, and a surface pumping system for pumping the mud to recirculate. Determining true formation pressure, including the following steps: providing a measurement device, having a probe, on the drill string; controlling the mud flow rate to obtain a first measured borehole pressure and measuring, with the probe of the measurement device, as a corresponding first probe pressure, the pressure in the formation adjacent the mudcake; controlling the mud flow rate to obtain a second measured borehole pressure and measuring, with the probe of the measurement device, as a corresponding second probe pressure, the pressure in the formation adjacent the mudcake; and deriving the true formation pressure from the first and second measured borehole pressures and the first and second probe pressures.

Determination of formation pressure during a drilling operation

A tool for formation logging includes a support configured for movement in a borehole; a source mounted on the support, the source configured to emit neutrons and gamma rays; and at least one sensor mounted on the support and spaced apart from the source, wherein the at least one sensor is configured to detect at least one selected from the group consisting of gamma rays and neutrons. A method for formation logging in accordance with one embodiment of the invention includes emitting neutrons and gamma rays into a formation, using a source on a logging tool disposed in a borehole penetrating the formation; and detecting gamma-ray signals and neutron signals scattered by the formation, using at least one detector on the logging tool.

Apparatus and methods for interlaced density and neutron measurements

For use in logging downhole in an earth borehole, a method for determining a characteristic of oil, includes: providing and determining the viscosity of a plurality of crude oil samples; performing test measurements, using a predetermined operating mode, on media including the crude oil samples to obtain test data; applying a test processing procedure to the test data to obtain an output test parameter relating to the test data and the predetermined operating mode; deriving, for the plurality of crude oil samples, a correlation relating the output test parameter to the viscosities of the crude oil samples; performing downhole measurements in the measurement region with a logging device, operated with substantially the predetermined operating mode, to obtain logging data, and applying a measurement processing procedure to the logging data to obtain an output logging parameter; and determining the oil characteristic using the output logging parameter and the correlation.

Logging method for determining characteristic of fluid in a downhole measurement region

A method for determining thermal capture cross-sections of formations surrounding an earth borehole, including the following steps: providing a logging device that is moveable through the borehole; transmitting, from the logging device, bursts of neutrons into the formations; detecting, at the logging device, resultant gamma ray counts, and deriving a measurement spectrum from the gamma ray counts; deriving a forward model comprising a combination of model exponential components having respective model decay times and model amplitudes; deriving an error function that depends on comparison between the forward model and the measurement spectrum; and determining, by regularized inversion, optimized exponential components of the model that substantially minimize the error function; the optimized exponential components being indicative of the thermal capture cross-sections of the formations.

Well logging method for determining formation characteristics using pulsed neutron capture measurements

System and method for formation logging using a gamma-ray detector. The techniques including acquiring gamma-ray signals using the gamma-ray detector, the acquired gamma-ray signals having energies that span at least a first-energy region and a second-energy region, wherein the first-energy region includes energies higher than a selected threshold and the second-energy region includes energies lower than the selected threshold; determining interference signals based on the acquired gamma-ray signals in the first-energy region; and correcting the acquired gamma-ray signals in the second-energy region based on the interference signals to provide corrected gamma-ray signals.

Corrections of gamma-ray responses

The present invention discloses a diffusion edited pulse technique that allows information about a fluid to be extracted, comprising: a) obtaining a fluid sample; b) generating a sequence of magnetic field pulses in the fluid, the sequence comprising an initial magnetic field pulse, a first portion that follows the initial magnetic field pulse, and a second portion that follows the first portion; c) detecting magnetic resonance signals using the second portion of the sequence; d) modifying the first portion of the sequence, and repeating steps (b) and (c); and e) extracting information about the fluid by determining relaxation and diffusion characteristics and their correlation based on the signals detected in steps (c) and (d). Also disclosed is a logging tool equipped with a processor to implement the diffusion edited pulse technique.

Nuclear magnetic resonance method and logging apparatus for fluid analysis

In one embodiment of the present invention, a method of measuring the molecular displacement of a fluid is disclosed comprising: (a) applying a strong magnetic field gradient to the fluid; (b) applying a sequence of oscillating magnetic field pulses to the fluid wherein the sequence includes a first portion followed by a second portion, wherein the first portion spatially modulates the magnetization state of the fluid and the second portion monitors the evolution of the modulation; (c) detecting magnetic resonance signals from the fluid; and (d) analyzing the detected signals to determine the molecular displacement of the fluid. This method may be used to determine the diffusion of the fluid or the restricted diffusion of the fluid through the porous media if the fluid is within a porous media (such as earth formation, bone, wood or other material). Also disclosed is a logging tool configured to implement this methodology.

Method and apparatus for rapid characterization of diffusion

A method that is usable with an NMR measurement apparatus includes averaging first spin echo trains acquired from different regions of a sample to form a second spin echo train. The first spin echo trains are used to produce a first estimate of a property of the sample, and the first estimate has a first resolution and a first accuracy. The second spin echo train is used to produce a second estimate of the property, and the second estimate has a second resolution that is lower than the first resolution and a second accuracy that is higher than the first accuracy. The first and second estimates are combined to produce a third estimate of the property. The third estimate has a third resolution near the first resolution of the first estimate and a third accuracy near the second accuracy of the second estimate.

Method for improving resolution of nuclear magnetic resonance measurements by combining low resolution high accuracy measurements with high resolution low accuracy measurements

NMR methods for extracting information about a fluid in rock and logging apparatuses for implementing such methods in a borehole environment are provided. The methods involve generating at least two different magnetic field pulse sequences. The magnetic field pulse sequences include a first portion and a second portion. A magnetic field pulse sequence is generated, and magnetic resonance signals are detected using the second portion of the sequence. The first portion of the sequence is modified, and again the sequence generated and magnetic resonance signals detected using the second portion. The magnetic resonance signals are analyzed, and information about, for example, diffusion coefficient, viscosity, composition, saturation in a rock, pore size, pore geometry and the like, extracted from the analyzed signals.

Nuclear magnetic resonance method and logging apparatus

Methods and apparatuses for investigating formations surrounding a borehole involve acquiring a fluorescent signal over a portion of the borehole and analyzing the signal to detect the presence of crude oil. Analyzing the signal to detect the presence of crude oil may involve distinguishing mineral fluorescence from oil fluorescence. The signal may be analyzed further to distinguish characteristics of the crude oil, such as its grade (light, medium or heavy), and to indicate a physical property correlated with the fluorescence, such as the presence of laminations or formation permeability. In some embodiments, fluorescence signals from illuminating the portion of the borehole with at least two different wavelengths of light are analyzed.

Method and apparatus for interpreting fluorescence logging data

The present invention provides methods for determining the bound fluid volume (BFV) of a formation utilizing nuclear magnetic resonance (NMR) techniques in which less than full polarization occurs and in which less than a complete NMR distribution is acquired. The effect of the polarizing static magnetic field is shortened in time by applying a shortened wait time between NMR measurements so that only the bound fluid of the formation is polarized. The shortened wait time is effectuated by early application of the oscillating magnetic field to the formation which, in conjunction with a limited number of refocusing pulses, induces signals in the formation that are measured by the NMR tool. The peak amplitude of these signals corresponds to the BFV. The present invention provides information so that a partial polarization calculation curve in T,lies almost equally between an empirical tapered cutoff curve and a theoretical tapered cutoff curve. Moreover, because no T,information must be acquired, the method is especially suited for logging-while-drilling operations, where the drill string moves uncontrollably during the NMR measurement.

Method for obtaining NMR bound fluid volume using partial polarization

A method and apparatus for determining gas corrected porosity using nuclear magnetic resonance (NMR) and density measurements is disclosed. The total porosity (TCMR) or an earth formation is determined using an NMR tool. A log output is generated that indicates the density of the formation. The density porosity of the formation is determined from the log output. The difference between the TCMR-density porosity log accurately indicates the presence of gas. A gas corrected porosity, .phi., and gas saturation, S.sub.g, are determined based upon the density porosity and TCMR.

Method and apparatus for measuring total nuclear magnetic resonance

Technique and apparatus are disclosed for identifying characteristics of hydrocarbons, such as distinguishing light and heavy formation oil, in formations surrounding an earth borehole. The technique and apparatus can also be used for determining residual oil saturation, permeability, and bound water volume. An embodiment of the method of the invention includes the following steps: providing a nuclear magnetic resonance logging device that is moveable through the borehole; providing, from the logging device, a polarizing magnetic field and cycles of a magnetic pulse sequence, and receiving magnetic resonance spin echoes from the formations; processing the received spin echoes to produce a T.sub.2 distribution; computing a magnetic resonance porosity from the T.sub.2 distribution; deriving a measure of total porosity of the formations; and comparing the magnetic resonance porosity with the total porosity.

Magnetic resonance well logging method and apparatus

A technique is disclosed for determining the gas-filled porosity and oil-filled porosity in a region of investigation of earth formations surrounding a borehole including the following steps: (a) providing a logging device that is moveable through the borehole; (b) generating, from the logging device, a static magnetic field in the region of investigation of the formations, the static field having a magnetic field gradient that is not constant in the region of investigation; (c) determining the gradient distribution of the static magnetic field in the region of investigation, and determining a first function of the gradient distribution and the diffusion coefficient of oil, and a second function of the gradient distribution and the diffusion coefficient of gas; (d) generating a first sequence of magnetic field pulses in the region of investigation of the formations using a first wait time, and detecting a first sequence of nuclear magnetic resonance spin echoes from the formations; (e) generating a second sequence of magnetic field pulses in the region of investigation of the formations using a second wait time, and detecting a second sequence of nuclear magnetic resonance spin echoes from the formations; (f) producing, from differences of respective echoes of the second and first sequences of spin echoes, an echo difference signal; and (g) determining the gas-filled porosity and oil-filled porosity in the region of investigation of earth formations from: the echo difference signal, a response function which depends on the first function, and a response function which depends on the second function.

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Ridgefield, CT, United States of America

Charles Flaum