Schlumberger Technology Corporation

Saudi Arabian Oil Company

Saudi Aramco Oil Company

Raghu Ramamoorthy

Terizhandur S Ramakrishnan

Cosan Ayan

Fikri John Kuchuk

Andrew John Carnegie

Thomas J Neville

Shouxiang Mark Ma

Edward Harrigan

James A Grau

Charles Flaum

Harold Pfutzner

David Linton Johnson

Bernard Montaron

Jean-Pierre R Delhomme

Ronald E Plasek

William F Murphy

Edward Alan Clerke

Naoki Saito

Ashok Srivastava

David C Bradley

Hervé Anxionnaz

William Dean Gibson

Amr Essawi

Pablo Saldungaray

Methods and systems are described for using pulsed neutron ?-ray spectroscopy to measure formation water salinity from within a borehole. Through generating a cross-plot of database values of ratios of spectroscopically determined yields of hydrogen (H) and chlorine (Cl) from two detectors, deriving apparent salinities therefrom, formation and borehole water salinities can be determined.

Method for measuring formation water salinity from within a borehole

Measuring a parameter characteristic of a formation in an oil well with a device configured to generate a sensing field within a volume of the formation and cause a flow through the volume in the presence of the sensing field. The device also comprises sensors responsive to changes in the volume, which indicate existent amounts of fluid, such as hydrocarbon and water saturations and irreducible hydrocarbon and water saturations. Measurements may be made before the flow affects the measuring volume and after onset of the flow through the measuring volume.

Formation treatment evaluation

A method of measuring a formation parameter in the process of drilling a well penetrating the rock formation is disclosed. A section of the well is provided with a drill string comprising a drilling bit at its distal end; a first fluid is circulated through the drilling bit and invades the rock formation; a formation evaluation tool mounted onto the drill string is used to measure the formation parameter; the formation parameter is used to select the time at which a second fluid is circulated through the drilling bit; such that the second fluid alters the response of the rock formation to the formation evaluation tool; the second fluid is circulated through the drilling bit to start invading the formation; and the formation evaluation tool is used to repeat the measure of the formation parameter while circulating the second fluid.

Method of determining a formation parameter

An apparatus and method of measuring a parameter characteristic of a rock formation in an oil well is provided with a device for generating a sensing field within a volume of the rock formation and a device for causing a flow through the volume in the presence of the sensing field, further including sensors responsive to changes in the volume, wherein a sensor response is indicative of the amounts of fluid, particularly hydrocarbon and water saturations and irreducible hydrocarbon and water saturations. Measurements can be made before the flow affects the measuring volume and after onset of the flow through the measuring volume.

Tool and method for determining formation parameter

Evaluating a formation by lowering a downhole tool in a wellbore penetrating the formation, injecting a fluid into the formation at an injection zone via the downhole tool, and using a formation evaluation sensor to perform a measurement at each of a plurality of locations in the wellbore each proximate the injection zone. At least two of the plurality of measurements are compared, and a formation property is determined based on the comparison.

Formation testing and evaluation using localized injection

A method of measuring a parameter characteristic of a rock formation in an oil well is provided for evaluating a reservoir treatment applied to a subterranean formation including the steps of injecting from a tool body suspended into a well at an injection location a known volume of fluid into the formation, performing a logging operation sensitive to a change of fluid content at several measuring points below and above the injection location; and using results of the logging operation to determine a depth profile along said well of a parameter related to fluid content.

Method for determining formation parameter

A method of producing images of formations surrounding a borehole, comprises: obtaining values of a first parameter in the borehole as a function of depth and azimuth at a first resolution; obtaining values of a second parameter in the borehole as a function of depth only at a second resolution; establishing a relationship between the first and second parameters at a matched resolution; using the relationship to derive values of the second parameter as a function of depth and azimuth; and producing an image of the second parameter as a function of depth and azimuth using the derived values of the second parameter. A method of producing three dimensional images comprises obtaining values of a first parameter in the borehole as a function of depth and azimuth at a first resolution; obtaining values of a second parameter in the borehole as a function of depth only at a second resolution; establishing a relationship between the first and second parameters at a matched resolution; using the relationship to derive values of the second parameter in a three dimensional array; and producing an image of the second parameter in three dimensions using the derived values of the second parameter.

Methods of producing images of underground formations surrounding a borehole

A visualization application will generate a Virtual Core representing a compilation of any formation property data, the compilation being a 2 and 1/2 D representation of any formation property. The compilation is generated by creating, in response to an integrated formation evaluation in 1D, a 2 and 1/2 D representation of each 1D formation property in the 1D formation evaluation, when the 1D property can be related to the 2 and 1/2 D physical magnitude combining the 2 and 1/2 D physical magnitude image with the 1D facies log thereby generating a 2 and 1/2 D facies image. The Software will also generate a Virtual Plug representing an average estimate of all formation properties over a prescribed surface or volume in the vicinity of a selection made on the compilation (i.e., on the Virtual Core). When an interaction with the Virtual Core occurs, all results generated by those interactions will be restored.

Generating and displaying a virtual core and a virtual plug associated with a selected piece of the virtual core

An integrated interpretation methodology is described that evaluates carbonate reservoirs. The methodology consists of first classifying the rock facies. A geometrical model specific to the classification is then used to predict the response of the rock to a variety of stimuli. A reconstruction of the geometrical model is made by comparing the measurements with the model predictions. The model is then used to predict the resistivity and the hydraulic transport properties of the rock, thereby enabling computation of both the reserves and their production behavior.

Method for interpreting carbonate reservoirs

An acoustical method of determining the spherical, or vuggy, porosity in carbonate rock formations, as a function of shear modulus. Total porosity and shear modulus of the formation is measured. Then the intrinsic granular porosity, dry bulk modulus, and spherical porosity are calculated. The carbonate rock is modeled, consisting of a primary host medium composed of carbonate grains with intergranular porosity between them. The model is easily modified to account for the case of intercrystalline microporosity existing within the grains, in addition to the intergranular porosity between them.

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Pune, India

Raghu Ramamoorthy