Schlumberger Technology Corporation

Richard E Lewis

Erik Rylander

Ravinath Kausik Kadayam Viswanathan

Ridvan Akkurt

Oliver Clinton Mullins

Tarek M Habashy

Andrew Emil Pomerantz

Lalitha Venkataramanan

Colin Longfield

Indranil Roy

George Alan Waters

Vivek Anand

Badarinadh Vissapragada

Fred K Gruber

Chris Wilkinson

Mansoor Ali

Tianmin Jiang

Reza Taherian

Syed Afaq Ali

John C Rasmus

Robert L Kleinberg

Wael Abdallah

Mohammed Badri

Partha Ganguly

Dmitriy Ivanovich Potapenko

Rashmi Bhavsar

Tuanfeng Zhang

Paul Ryan Craddock

Philip M Singer

Frank Shray

Andrea Valori

Donald W Lee

Kamilla Fellah

David Handwerger

Jack LaVigne

Farhan Ali

Rita Esuru Okoroafor

Stacy Lynn Reeder Blanco

Helena Gamero Diaz

Paul George

Roderick Bovee

Chi Duru

A technique facilitates hydrocarbon fluid production. A well is formed in a subterranean region by drilling a borehole, e.g. a generally vertical wellbore. At least one tunnel is formed and oriented to extend outwardly from the borehole at least 10 feet into a formation surrounding the borehole. The orientation of the at least one tunnel is selected such that it extends at a desired angle with respect to a direction of horizontal stress in the formation. A fracture stimulation of the at least one tunnel is performed to create a network of fractures. The orientation of the at least one tunnel ensures that the network of fractures extends through a target zone in a hydrocarbon bearing region of the formation.

Reservoir stimulation comprising hydraulic fracturing through extended tunnels

Downhole fluid volumes of a geological formation may be estimated using nuclear magnetic resonance (NMR) measurements, even in organic shale reservoirs. Multi-dimensional NMR measurements, such as two-dimensional NMR measurements and/or, in some cases, one or more well-logging measurements relating to total organic carbon may be used to estimate downhole fluid volumes of hydrocarbons such as bitumen, light hydrocarbon, kerogen, and/or water. Having identified the fluid volumes in this manner or any other suitable manner from the NMR measurements, a reservoir producibility index (RPI) may be generated. The downhole fluid volumes and/or the RPI may be output on a well log to enable an operator to make operational and strategic decisions for well production.

Estimating downhole fluid volumes using multi-dimensional nuclear magnetic resonance measurements

Methods may include normalizing two or more wellbore logs obtained from the output of two or more wellbore tool surveys of a wellbore in a formation of interest; inputting two or more wellbore logs into a correlation matrix; assigning each of the two or more wellbore logs a positive or negative value based on the impact on a selected wellbore quality; performing a principal component analysis of the two or more wellbore logs to obtain one or more loading vectors; computing weighting factors for each of the two or more wellbore logs from the one or more loading vectors; and generating a quality index by linearly combining the two or more wellbore logs using the computed weighting factors.

Data fusion technique to compute reservoir quality and completion quality by combining various log measurements

A methods are provided for investigating a sample containing hydrocarbons by subjecting the sample to a nuclear magnetic resonance (NMR) sequence using NMR equipment, using the NMR equipment to detect signals from the sample in response to the NMR sequence, analyzing the signals to extract a distribution of relaxation times (or diffusions), and computing a value for a parameter of the sample as a function of at least one of the relaxation times (or diffusions), wherein the computing utilizes a correction factor that modifies the value for the parameter as a function of relaxation time for at least short relaxation times (or as a function of diffusion for at least large diffusion coefficients).

Methods of investigating formation samples using NMR data

A method for testing an unconventional core sample is provided. The method involves loading the unconventional core sample into a sample holder and introducing fluid into the sample holder at an elevated pressure such that fluid is injected into the internal pore space of the unconventional core sample in order to resaturate the unconventional core sample with the fluid, wherein the fluid is selected from the group including a hydrocarbon fluid and a water-based formation fluid. An apparatus and a system used in combination with the method are also provided.

Workflow for resaturation and analysis of unconventional core samples

A tool having a pump-out unit, pumping unit, and NMR unit is disposed in a wellbore. On a pump-up cycle, after removing borehole fluids, a fluid is injected into a region of investigation. NMR measurements are made while fluid migrates into the region of investigation. On a production cycle, pressure is removed, allowing fluid to exit the formation while NMR measurements are made. A rate of fluid production is estimated using the time-dependent NMR measurements. Alternatively, the mass of a sample is measured. Fluid is injected into the sample and the mass of the injected sample is measured. Pressure is removed and the mass of the injected sample as the fluid migrates out of the sample is measured. The change in mass of the injected sample as the fluid migrates out of the sample is determined and a rate of fluid production is estimated using the determined change in mass.

Prediction of gas production rates from time-dependent NMR measurements

Treatment methods and treatment fluids for increasing permeability of organic shale formations are described herein. The treatment method includes treating an organic shale formation with a treatment fluid. The treatment fluid includes a solvent that dissolves bitumen in the shale formation. After treating the shale formation with the treatment fluid, oil is recovered from the shale formation. By removing bitumen from pores and pore throats within the formation, the solvent increases permeability of the formation and allows mobile oil to flow more easily through the formation.

Method for removing bitumen to enhance formation permeability

A method and system for evaluation of a hydrocarbon-bearing shale formation employs a data processing system that defines a response model that relates first data representing measured petrophysical properties of the shale formation at a given location to second data representing volume fractions for a particular set of formation components at the given location. The first data includes hydrogen index at the given location, and the particular set of formation components of the second data include a number of mineral components and a number of hydrocarbon-bearing components. The hydrocarbon-bearing components include at least one kerogen component. A computation solver processes the response model along with the first data to solve for the second data. The solved second data representing the volume fraction of the at least one kerogen component is processed to derive at least one ratio that is indicative of kerogen maturity at the given location.

Method and apparatus for evaluation of hydrocarbon-bearing reservoirs

Techniques for calculating metrics for reservoir quality based on light oil and total organic carbon in tight oil reservoirs are described. The techniques include calculating quantities of light oil and total organic carbon from logging data and generating therefrom a continuous log for reservoir quality metric. Additionally new reservoir quality indices are presented that more accurately predict reservoir quality in tight oil plays.

Quality metrics for tight oil reservoirs

A method to detect presence of hydrocarbons in a subterranean formation. The method includes identifying a geological interval in the subterranean formation, analyzing a measurement of a rock sample obtained from the geological interval to generate a rock sample analysis result, wherein the rock sample analysis result indicates the presence of hydrocarbons in the geologic interval, analyzing, in response to the rock sample analysis result indicating the presence of hydrocarbons, a supplemental measurement different than the measurement of the rock sample to generate a supplemental analysis result, wherein the supplemental analysis result further indicates the presence of hydrocarbons in the geologic interval, performing, in response to the supplemental analysis result further indicating the presence of hydrocarbons, a logging operation to obtain azimuthal resistivity data of the geological interval, and presenting the rock sample analysis result, the supplemental analysis result, and the azimuthal resistivity data to a user.

Detecting and quantifying hydrocarbon volumes in sub-seismic sands in the presence of anisotropy

A method for characterizing one or more properties of a geological formation including brine, the method including inputting at least one first property of the geological formation into an equation of state (EOS) model, the EOS model accounting for a high temperature effect on the brine; solving the EOS model to determine at least one second property of the geological formation; and outputting the at least one second property to a display device.

Device and method to determine conductivity for high pressure-high temperature service

A method for characterizing one or more properties of a geological formation including brine and a dense vapor phase includes inputting at least one first property of the geological formation including resistivity of a vapor phase into a model including an equation of state (EOS) model, the model accounting for a high temperature effect on the dense vapor where that the dense vapor has a non-infinite resistivity. At least the EOS model is solves to provide data relating to at least one second property of the geological formation. The data relating to the at least one second property is output to a display device for visual inspection.

Method to predict dense hydrocarbon saturations for high pressure high temperature

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Longmont, CO, United States of America

Richard E Lewis