Halliburton Energy Services, Inc.

University of South Carolina

Megan Renee Pearl

William Cecil Pearl, Jr

Neal Gregory Skinner

Christopher Michael Jones

David L Perkins

Michael Thomas Pelletier

Samuel Jason Lewis

Bin Dai

Dingding Chen

James Martin Price

Michael L Myrick

Maria Paiva

Dale E Jamison

Li Gao

Anthony Herman Van Zuilekom

John L Maida

Michel Joseph LeBlanc

Jing Shen

Stephen L Morgan

Heather Brooke

William Ceceil Pearl, Jr

Timothy J Shaw

Tammi L Richardson

Katrina S Akita

Laura S Bruckman

Joseph A Swanstrom

Alexandre Jaime Mello Vieira

William C Pearl, Jr

Luiz Alexandre Sacorague

Ralph Piazza

Juliana Midori Matsushita

William Ceceil Pearl

A method comprises determining an adaptive fluid predictive model calibrated with a plurality of types of sensor data, wherein the plurality of types of sensor responses comprise a first type of sensor response associated with a synthetic parameter space and a second type of sensor response associated with a tool parameter space. The method comprises applying the adaptive fluid predictive model to one or more fluid samples from field measurements obtained from a tool deployed in a wellbore formed in a subterranean formation and determining a value of a fluid answer product prediction with the applied adaptive fluid predictive model. The method comprises facilitating a wellbore operation with the tool based on the value of the fluid answer product prediction.

Optical sensor adaptive calibration

A method and system can obtain real time property measurements of a fluid comprising a formation fluid downhole, real time measurements of an amount of an interactive component of the fluid downhole, and real time measurements of an amount of a non-interactive component of the fluid downhole. The method and system further includes determining a total amount of the interactive component in the fluid or a contamination level of the formation fluid at a time of interest based on the real time property measurements of the fluid downhole and the real time measurements of the amounts of the interactive component and non-interactive component downhole. The real time measurements of the amount of the interactive component downhole are real time measurements of the amount of the interactive component in its free form downhole, and the property can be scaled with the contamination level.

Determination of downhole formation fluid contamination and certain component concentrations

The subject disclosure provides for a method of optical sensor calibration implemented with neural networks through machine learning to make real-time optical fluid answer product prediction adapt to optical signal variation of synthetic and actual sensor inputs integrated from multiple sources. Downhole real-time fluid analysis can be performed by monitoring the quality of the prediction with each type of input and determining which type of input generalizes better. The processor can bypass the less robust routine and deploy the more robust routine for remainder of the data prediction. Operational sensor data can be incorporated from a particular optical tool over multiple field jobs into an updated calibration when target fluid sample compositions and properties become available. Reconstructed fluid models adapted to prior field job data, in the same geological or geographical area, can maximize the likelihood of quality prediction on future jobs and optimize regional formation sampling and testing applications.

Methods and systems for determining whether a base oil for use in drilling muds will be compatible with cement during subsequent cementing operations include: providing a drilling fluid that includes a base oil; using the drilling fluid to drill at least a portion of a wellbore penetrating at least a portion of a subterranean formation; measuring a compositional characteristic of the base oil using one or more analytical tests; determining whether the base oil is a compatible base oil or an incompatible base oil based at least in part on the compositional characteristic of the base oil; injecting an amount of spacer fluid into the wellbore, wherein the amount of spacer fluid is selected based on the determination of whether the base oil is a compatible base oil or an incompatible base oil; and injecting the one or more cementing or completion fluids into the wellbore.

Characterizing the base oil of a drilling mud for compatibility with subsequent subterranean operations

The disclosed embodiments include systems and methods to perform in-situ analysis of reservoir fluids. In some embodiments, the system includes a first vial containing a first insulating cylinder having a first internal cavity for storing electrolytes, a capillary tube, and a first sealable end having a first seal that prevents the electrolytes that are stored in the first internal cavity from flowing through the first sealable end while the first seal remains intact. The system also includes a second vial containing a second insulating cylinder having a second internal cavity for receiving the electrolytes that are stored in the first insulating cylinder, and a second sealable end having a second seal. The system further includes a tube positioned between the first vial and the second vial, where the tube provides at least one fluid flow path between the first vial and the second vial.

In-situ reservoir fluid analysis system

This disclosure provides a method of determining a pore throat size distribution of reservoir rock, comprising injecting a set of different-sized probe particles through a portion of reservoir rock and measuring retention volumes or times of each of the different-sized probe particles eluting from the portion of reservoir rock. This disclosure also provides a testing apparatus comprising a probe tube for receiving a set of different-sized probe particles in an elution fluid returning from a portion of reservoir rock and an analytical module connected to receive the elution fluid from the probe tube. The module includes a flow cell to receive the elution fluid from the probe tube, a radiation source positioned to direct a radiation beam though a window of the cell into the eluting fluid in the cell, and a sensor for detecting portions of the radiation beam that have interacted with the different-sized probe particles such that retention volumes or times each of the probe particles of one size class can be distinguished from all other size classes of the set.

Determination of pore size distribution of reservoir rock

Systems and methods are provided for determining a presence, type, or amount of an analyte in fluid. An analyte sensor can include a substrate that includes a chiral molecule for sensing the presence of the analyte in the fluid. A property of the chiral molecule may change in response to sensing the presence of the analyte. The change in the property of the chiral molecule can cause a change in polarization of a beam of light traveling through the substrate. The presence, type, or amount of the analyte can be determined based on the change in polarization of the beam of light. The analyte sensor, along with optical fibers, can be used to determine the presence, type, or amount of an analyte in a fluid sample from a wellbore.

Analyte-induced chiroptical changes

Optical analysis devices may be configured for optically interacting a set cement with a chemical filter and a detector that together are configured to detect a characteristic of the set cement, wherein optically interacting the set cement with the chemical filter comprises absorbing, by the chemical filter, at least a portion of an electromagnetic radiation having optically interacted with the set cement. Relative to cementing operations, such optical analysis devices may be useful in identifying fluids, analyzing compositions of cement slurries, investigating the status of a reaction occurring in a cement slurry, detecting and/or monitoring corrosion of a set cement, and the like.

In situ monitoring of cement slurry locations and setting processes

A composition includes a borehole or pipeline fluid and a delivery molecule, the delivery molecule stable under conditions external to a borehole or pipeline and including a precursor having an end terminating in degradable linkages bonding the precursor to bridged groups and another end terminating in a leaving group, where under in situ conditions in the pipeline or downhole from the borehole surface contact with an initiator acid catalyzes degradation of the degradable linkages and elimination of the leaving group, releasing the precursor and generating an additive from the precursor. A method includes placing the delivery molecule in the borehole or pipeline; and after the placing, contacting the composition with an initiator acid under in situ conditions.

In situ H2S scavenger additive generation

A method of treating a subterranean formation includes introducing a well cementing composition into a wellbore, said cementing composition comprising: a pumpable slurry of cement and at least one of hydrophobic material, a superhydrophobic material, and combinations; and allowing at least a portion of the cementing composition to cure. A composition includes a pumpable slurry of wellbore cement and at least one of hydrophobic material, a superhydrophobic material, and combinations thereof.

Superhydrophobic additive

A method of treating a subterranean formation includes introducing a well cementing composition into a wellbore, the cementing composition comprising: a pumpable slurry of cement and at least one of hydrophobic material, a superhydrophobic material, and combinations; and allowing at least a portion of the cementing composition to cure. A composition includes a pumpable slurry of wellbore cement and at least one of hydrophobic material, a superhydrophobic material, and combinations thereof.

Optical analysis devices may be configured for optically interacting a material of interest with a chemical filter and a detector that together are configured to detect a characteristic of the material of interest, wherein optically interacting the material of interest with the chemical filter comprises absorbing, by the chemical filter, at least a portion of an electromagnetic radiation having optically interacted with the material of interest. Relative to cementing operations, such optical analysis devices may be useful in identifying fluids, analyzing compositions of cement slurries, investigating the status of a reaction occurring in a cement slurry, detecting and/or monitoring corrosion of a set cement, and the like.

Systems and methods for in situ monitoring of cement slurry locations and setting processes thereof

Optical analysis systems and methods may be used for analyzing the characteristics, including compositions, of cement additives, which may be used in formulating a cement slurry. For example, a cement additive may be optically interacting with an integrated computational element ('ICE') configured to detect a characteristic of the cement additive. An output signal may then be generated corresponding to the characteristic of the cement additive detected by the ICE, which may be received and processed with a signal processor to yield a value for the characteristic of the cement additive. The value of the characteristic of the cement additive may then be used to determine an amount of the cement additive for use in producing a cement slurry.

Systems and methods for analyzing the characteristics and compositions of cement additives

Systems and methods for measuring a characteristic of a fluid are provided. The system includes a plurality of waveguides embedded in a substrate, and an exposed surface of the substrate comprising a portion of a side surface of at least one of the plurality of waveguides. The system also includes a sensitized coating in the at least one of the plurality of waveguides. The exposed surface is curved in a direction perpendicular to a light propagation in the waveguide. A method of fabricating a system as above is also provided.

Three-dimensional waveguide sensors for sample analysis

Optical sensors having one or more soluble coatings thereon are used to detect the presence of a degrading fluid. In a generalized embodiment, the fiber optic sensor includes a fiber optic cable having two strain sensor positioned therein. A soluble layer is positioned over one of the strain sensor. Due to the presence of the soluble layer, the covered strain sensor optically responds differently than the other strain sensor to changes in pressure, strain and temperature. In the presence of a degrading fluid, the soluble layer degrades and ultimately dissolves, thereby changing the optical response of the previously covered strain sensor. When the soluble layer is dissolved, the strain induced by the soluble layer relaxes, thus causing a wavelength shift in the signal of the grating. By monitoring the wavelength shifts of both strain sensors, the fiber optic sensor acts as a detector for the presence of the degrading fluid.

Growing community of inventors

Houston, TX, United States of America

Megan Renee Pearl