Schlumberger Technology Corporation

Other

Woods Hole Oceanographic' Institution

Schlumberger Technology Coporation

Oliver C. Mullins

Robert J. Schroeder

Tsutomu Yamate

Rogerio T. Ramos

Oliver Clinton Mullins

Youxiang Zuo

Chengli Dong

Christopher Harrison

Andrew Emil Pomerantz

Bhavani Raghuraman

Xu Wu

Go Fujisawa

Soraya Sofia Betancourt

Cosan Ayan

Toru Terabayashi

Albert Ballard Andrews

Li Jiang

Kang Wang

Michael O'Keefe

Gale Hyslip Gustavson

Adriaan Gisolf

Kentaro Indo

Denise E Freed

Vinay K Mishra

Rogerio Tadeu Ramos

Peter S Hegeman

Timothy Gareth John Jones

Andrew L Kurkjian

Ricardo Vasques

Hadrien Dumont

Shu Pan

Jimmy Lawrence

Julian J Pop

Matthew T Sullivan

Stephane Vannuffelen

Ronald E G Van Hal

Andrew John Carnegie

Anthony Goodwin

Kai Hsu

Robert J Schroeder

Lalitha Venkataramanan

Felix K Chen

Elizabeth Jennings Smythe

Elizabeth B Dussan V

Thomas Pfeiffer

Christopher Del Campo

Kosta Ladavac

Andrew Speck

Ryan Sangjun Lee

Oleg Zhdaneev

Lennox Reid

Edward Harrigan

Nathan Scott Lawrence

Andrew Meredith

Anthony Robert Holmes Goodwin

Colin Longfield

Ahmed Hammami

Richard E Lewis

Indranil Roy

John Ratulowski

Marian Faur

Li Chen

Terizhandur S Ramakrishnan

Yi-Qiao Song

Peter D Wraight

Sandip Bose

Robert L Kleinberg

Henri-Pierre Valero

Gary Martin Oddie

Ricardo Reves Vasques

Wael Abdallah

Eric P Donzier

Jacques A Jundt

Anthony R H Goodwin

Benoit Couet

Joel Lee Groves

Chanh Cao Minh

Ashers Partouche

Charles Flaum

Vladimir Vaynshteyn

Douglas E Miller

William John Bailey

Partha Ganguly

John E Edwards

Shahnawaz Hossain Molla

Ralph Michael D'Angelo

David Linton Johnson

Rashmi Bhavsar

Paul Simon Hammond

Fabien Cens

Abdel Kharrat

Douglas W Grant

Akira Kamiya

Ridvan Akkurt

Ashley C Kishino

John Barry Fitzgerald

Hua Chen

Noriyuki Matsumoto

Christopher M Reddy

Michael Hayward Hodder

John Sherwood

Richard Guy Compton

Systems and methods presented herein generally relate to a formation testing tool configured to determine whether a formation fluid being tested is a bubble point fluid or a dew point fluid. For example, in certain embodiments, a method includes depressurizing a flowline of a formation testing tool. The flowline contains a formation fluid having a gas-to-oil ratio (GOR) within a predetermined GOR range. The method also includes determining, using a fluid analysis module of the formation testing tool, whether the formation fluid is a bubble point fluid or a dew point fluid by analyzing distribution of bubbles in the formation fluid that are caused by the depressurization of the flowline.

Systems and methods for differentiating bubble points from dew points

Methods and systems are provided for conducting formation analysis. Data from borehole logging tools is used to conduct a petrophysical analysis of the formation in order to determine (quantify) total porosity and formation matrix permittivity for an interval of the formation. Noninvaded zone water saturation and flushed zone water saturation for the interval of the formation is determined using a saturation model of the interval. The noninvaded zone water saturation is compared to the flushed zone water saturation, and the results of the comparison are used to determine that the interval of the formation contains movable hydrocarbon, immobile hydrocarbon or movable formation water.

Formation analysis incorporating identification of immovable and viscous hydrocarbons

Processes and systems for determining asphaltene equilibrium between two or more downhole geographic locations are provided. In some embodiments, the process can include measuring one or more fluid properties of a plurality of fluid samples at varying downhole depths to generate a one or more downhole fluid analysis measurement data points; selecting an asphaltene diameter distribution based on prior knowledge; utilizing the asphaltene diameter distribution to fit a first set of one or more equation of state curves to the one or more downhole fluid analysis measurement data points to define a first model of fitted equation of state curves and to determine one or more posterior distributions of asphaltene diameters; and determining if the varying downhole depths are in an asphaltene equilibrium by determining whether the one or more posterior distributions of asphaltene diameters is consistent with that of asphaltenes in equilibrium.

Processes and systems for determining if downhole fluids are in equilibrium or non-equilibrium

Systems and methods presented herein are configured to monitor gas storage in a well and, more specifically, to invert optical measurements to predict the fractional molar composition of an unknown composition of a gas mixture comprised of hydrogen, carbon dioxide, other gases, or combinations thereof, in any underground reservoir or salt dome where hydrogen, carbon dioxide, and/or the other gases are stored or exist.

Systems and methods for monitoring gas storage in underground reservoirs

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. A technique facilitates fluid analysis in situ at a downhole location. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. According to an embodiment, a sample of oil is obtained at the downhole location from oil in a reservoir. A downhole sampling system is used to determine whether a sample has contamination and other selected characteristics of the sample. The data obtained may be processed to provide a formation volume factor of the oil.

Methods and systems for estimation of oil formation volume factor

Embodiments of the disclosure can include systems, methods, and devices for determining saturation pressure of an uncontaminated fluid. Downhole saturation pressure measurements and downhole OBM filtrate contamination of a contaminated fluid may be obtained and a relationship may be determined between the saturation pressure measurements and OBM filtrate contamination. The relationship may be extrapolated to zero OBM filtrate contamination to determine the saturation pressure of the uncontaminated fluid. In some embodiments, OBM filtrate contamination may be determined from downhole saturation pressure measurements during pumpout of a fluid.

Methods and systems for correction of oil-based mud filtrate contamination on saturation pressure

Methods and downhole tools for operation within in a wellbore that extends into a subterranean formation. The operation includes simultaneously causing a change in a first parameter of fluid drawn into the downhole tool from the formation and determining a change in a second parameter of the fluid relative to the change in the first parameter. A third parameter of the fluid is determined based on the first and second parameter changes.

Determining asphaltene onset

A methodology that performs fluid sampling within a wellbore traversing a reservoir and fluid analysis on the fluid sample(s) to determine properties (including asphaltene concentration) of the fluid sample(s). At least one model is used to predict asphaltene concentration as a function of location in the reservoir. The predicted asphaltene concentrations are compared with corresponding concentrations measured by the fluid analysis to identify if the asphaltene of the fluid sample(s) corresponds to a particular asphaltene type (e.g., asphaltene clusters common in heavy oil). If so, a viscosity model is used to derive viscosity of the reservoir fluids as a function of location in the reservoir. The viscosity model allows for gradients in the viscosity of the reservoir fluids as a function of depth. The results of the viscosity model (and/or parts thereof) can be used in reservoir understanding workflows and in reservoir simulation.

Method for characterization of hydrocarbon reservoirs

A method, apparatus, and program product model address a modeling gap existing between basin and reservoir modeling through the use of a Reservoir Fluid Geodynamics (RFG) model usable for simulations conducted at a relatively fine spatial resolution and over a geological timescale.

Modeling of oil and gas fields for appraisal and early development

A method includes placing a downhole acquisition tool in a wellbore in a geological formation containing a reservoir fluid. The method includes performing downhole fluid analysis using the downhole acquisition tool to determine at least one measurement of the reservoir fluid. The method includes using a processor to estimate at least one fluid component property by using an equation of state based at least in part on the at least one measurement of the reservoir fluid and to simulate a diffusion process using a diffusion model that takes into account the at least one estimated fluid property to generate a composition path. The method includes using a processor to estimate one or more phase envelopes based in part on the at least one fluid property and compare the one or more phase envelopes with the composition path. The method includes outputting a visualization identify potential areas of asphaltene instability.

Asphaltene phase instability analysis in gas charges into oil reservoirs

A method for deriving VOI for a hydrocarbon-bearing reservoir fluid model based on DFA data ('true fluid model') versus an 'incorrect fluid model' includes calculating first, second and third objective functions that are based on NPV(s) of simulated production by a reservoir simulator with different configurations. For the first objective function, the simulator is configured with the incorrect fluid model and control variables that are optimized to derive a first group of control variable values. For the second objective function, the simulator is configured with the true fluid model and the first group of control variable values. For the third objective function, the simulator is configured with the true fluid model and control variables that are optimized to identify a second group of control variable values. The objective functions can be deterministic, or can include statistics that account for uncertainty. A visualization of such results with uncertainty is also described.

Methods and systems for calculating and evaluating value of information for reservoir fluid models derived from DFA tool data

A method includes receiving first fluid property data from a first location in a hydrocarbon reservoir and receiving second fluid property data from a second location in the hydrocarbon reservoir. The method includes performing a plurality of realizations of models of the hydrocarbon reservoir according to a respective plurality of one or more plausible dynamic processes to generate one or more respective modeled fluid properties. The method includes selecting the one or more plausible dynamic processes based at least in part on a relationship between the first fluid property data, the second fluid property data, and the modeled fluid properties obtained from the realizations to identify potential disequilibrium in the hydrocarbon reservoir.

Reservoir fluid geodynamic system and method for reservoir characterization and modeling

Systems and methods for identifying a likelihood that a reservoir of a geological formation received a secondary charge of hydrocarbons of relatively very different thermal maturity of composition are provided. One method includes positioning a downhole acquisition tool in a wellbore in a geological formation and testing one or more fluid properties of the formation fluid. Data processing circuitry may identify whether a relationship of the one or more fluid properties exceeds a first threshold that indicates likely asphaltene instability. When this is the case, data processing circuitry may be used to model the geological formation using a realization scenario in which multiple charges of hydrocarbons of substantially different thermal maturity or substantially different composition, or both, filled a reservoir of the geological formation over geologic time.

Systems and methods for identifying two or more charges into reservoir using downhole fluid analysis

A method includes identifying linearly behaving data within obtained data associated with fluid obtained from a subterranean formation. Shrinkage factor is determined based on the linearly behaving data. A function relating GOR data of the obtained fluid with the determined shrinkage factor is determined. A first linear relationship between optical density (OD) data of the obtained fluid and the function is determined. A second linear relationship between density data of the obtained fluid and the function is determined. An oil-based mud (OBM) filtrate contamination property of OBM filtrate within the obtained fluid based on the first linear relationship is determined. A native formation property of native formation fluid within the obtained fluid based on the second linear relationship is determined. A volume fraction of OBM filtrate contamination within the obtained fluid based on the OBM filtrate contamination property and the native formation property is estimated.

Downhole real-time filtrate contamination monitoring

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Ridgefield, CT, United States of America

Oliver Clinton Mullins