Halliburton Energy Services, Inc.

Mathew Dennis Rowe

Jon Troy Gosney

Shaun Patrick Lawrence

Clinton Cheramie Galliano

Walter Varney Andrew Graves

Walter Varney Graves

Ian David Campbell Mitchell

David Kirkpatrick Muirhead

Jhanvi Manishkumar Kevadiya

Michael Linley Fripp

Christopher Michael Jones

Dale E Jamison

Stephen Michael Greci

Michael Thomas Pelletier

John C Gano

Michael S Bittar

Prashant Shekhar

Charles Cutler Britton

Daniel Duncan Blue, Iii

Ian D Mitchell

Patrick Gregory McCormack

Bradly Shawn Hogan

W V Andrew Graves

Thuy Hanh Thi Blakey

Steven Robert Weiss

Kurt Adam Kronenberger

Hunter Terrance Guchereau

John Charles Gano

Wv Andrew Graves

Ian David Mitchell

Patrick Gregory Mccormack

Embodiments of multi-column gas chromatography for analysis of a formation sample are disclosed. In one embodiment, an apparatus comprises a gas chromatography instrument and a controller. The gas chromatography instrument comprises a sample injector; a primary column to separate out a hydrocarbon subset; a secondary column valve coupled to the primary column; a primary detector configured to analyze the hydrocarbons of the subset; a heart cutting unit coupled to the secondary column valve and configured to cut, from the subset, at least one isomer having a weight greater than a threshold; a secondary column coupled to an output of the heart cutting unit configured to separate out the at least one isomer; and a secondary detector configured to analyze the at least one isomer. The controller controls the secondary column valve to output the hydrocarbons to the heart cutting unit in response to at least one trigger event.

Multi-column gas chromatography for analysis of a formation sample

The disclosure provides for systems and methods for removing particle settlement in a heater system. The method includes introducing a fluid into a first heater of the heater system, wherein the first heater is operable to increase the temperature of the introduced fluid. The method further includes actuating a first air agitation unit to discharge a volume of compressed air into the first heater, wherein the compressed air is configured to provide mixing and suspension to particles settled within the first heater through the velocity and expansion of the compressed air to atmospheric pressure. The method further includes discharging a mixture from the first heater comprising the fluid and the particles from the first heater and directing the discharged mixture to a return point in a flow path.

Process heater anti-settling systems and methods

Described herein are systems and techniques for improving operation of a gas chromatograph or a computer that identifies compounds that correspond to peaks in a graph of gas chromatograph data (chromatogram). Each of the peaks included in the chromatogram may be associated with retention times that are measured amounts of time that correspond to how long it took for respective compounds included in a sample to move through the gas chromatograph. Measured retention times may be compared to standard retention times to identify retention time shifts. These retention times shifts may correspond to a function that may be used to predict retention times of other compounds that could be included in the sample. When a measured retention time that is associated with an unclassified peak in the chromatogram matches a predicted retention time of a specific compound to a threshold level, the unclassified peak may be identified the specific compound.

Predictive chromatograph peak detection

Disclosed herein are automated sample cleaning systems and processes after collection of the drilling cuttings from the shale shaker. These automated sample cleaning systems and processes help in delivering a drilling cutting sample that has been cleaned following the same procedure from one drill rig site to another providing consistency on its impact on the compositional analysis of the drilling cutting sample.

Automated sample cleaning

A concentration of at least one chemical reaction product in a drilling fluid is determined after the drilling fluid has interacted with a plasma discharge produced via one or more electrodes of a drill bit of a pulse power drill string disposed in a wellbore for drilling the borehole. The concentration of the at least one chemical reaction product is correlated to a relation between an arc and a spark of the plasma discharge. The relation between the arc and spark can subsequently be evaluated to determine updates to pulse power drilling parameters and/or to perform formation and drilling fluid evaluation.

Plasma chemistry derived relation between arc and spark for pulse power drilling

Systems and methods of the present disclosure generally relate to correcting isotope ratio calculations during wellbore operation. A method for correcting isotope ratios during a wellbore operation, comprising receiving a flow-in fluid sample from a wellbore; receiving a flow-out fluid sample from the wellbore; passing each sample to an analytical instrument operable to determine isotopes in each fluid sample; outputting a signal intensity or signal area; assigning a depth to the signal intensity or the signal area; and determining a corrected isotope ratio by subtracting a signal for the flow-in fluid sample from a signal for the flow-out fluid sample.

Recycled isotope correction

A system can flush a drilling fluid sample with a hydrocarbon blend, which includes a determined concentration of at least one chemical species to generate a flushed drilling fluid sample. The system can extract a dissolved gas from the flushed drilling fluid sample. The system can determine a concentration over time of at least one chemical species of the dissolved gas. The system can generate an area per concentration curve based on the concentration over time of the at least one chemical species. The system can determine at least one concentration value of the at least one chemical species. The system can modify the at least one concentration value based on the area per concentration curve. The system can then correct bias caused by the gas extractor and fluid sampling system.

Predicted bias correction for a gas extractor and fluid sampling system

A modular gas detection system includes a primary gas chromatograph, a constant volume extractor positionable to provide a continuous fluid sample to the primary gas chromatograph, and a total hydrocarbon analyzer. The modular gas detection system also includes a processing device and a memory device including instructions executable by the processing device for causing the processing device to perform operations. The operations include adjusting a detection scheme of the primary gas chromatograph to update a detection range for the continuous fluid sample to detect different hydrocarbons within a single column. Further, the operations include controlling routing of the continuous fluid sample from the constant volume extractor to the primary gas chromatograph and the total hydrocarbon analyzer.

Modular gas detection system for a wellbore

A drilling system for drilling a well. The drilling system may include a drillstring, a gas detector, and a computer system. The drillstring may include a downhole motor operable to rotate a drill bit and the downhole motor may include a stator and a rotor, at least one of the stator or the rotor comprising an elastomer compound. The gas detector may be operable to detect a gas indicative of deterioration of the elastomer compound. The computer system may be programmed to generate an indication based on the detection of the gas indicative of the deterioration by the gas detector.

Drilling system with gas detection system for use in drilling a well

The present disclosure generally relates to a standalone gas extraction and detection system comprising a gas extraction chamber operable to receive a wellbore fluid and a carrier gas; a gas detection chamber in fluid communication with the gas extraction chamber, the gas detection chamber comprising reflective surfaces operable to receive infrared radiation (IR) and an extracted gas sample from the gas extraction chamber; an open-path detector operable to detect the IR in the gas detection chamber; and a shaft extending through the gas extraction chamber and the gas detection chamber of the standalone gas extraction and detection system.

Gas detection integration into a gas extractor

A system including an image acquisition unit in optical communication with a flow pathway. The system may include at least one illumination source directable toward a shale shaker. The illumination source may emit a light output. A band-stop filter may be affixed to the image acquisition unit to filter out infrared light. The band-stop filter may also allow electromagnetic radiation of the light output to reach the image acquisition unit. An analysis device may be used to determine a volume of downhole particles on the shale shaker using deflections of the light output observed by the image acquisition unit.

Band-stop filter for volume analysis of downhole particles

A system includes a discharge tool positioned within a wellbore and configured to generate an electrical discharge that interacts with a rock formation proximate to the discharge tool, wherein the interaction of the electrical discharge with the rock formation vaporizes a portion of the rock formation to generate a discharge plasma. The system further includes an optical emission spectroscopy (OES) sub-system configured to determine an elemental composition of the portion of the rock formation based on optical emission generated by the discharge plasma, wherein at least a portion of the OES sub-system is positioned within the wellbore.

Downhole optical emission spectroscopy

An example method for determining downhole conditions in a subterranean formation during a drilling operation may include introducing non-formation gas into a flow of drilling fluid through a fluid conduit in fluid communication with a drill string disposed within a borehole in the subterranean operation. The non-formation gas may be received from the flow of drilling fluid through a return line in fluid communication with the borehole. A downhole condition may be determined based, at least in part, on the received non-formation gas.

Determination of downhole conditions using circulated non-formation gasses

Systems and methods of the present disclosure generally relate to reporting carbon and hydrogen isotopic ratios during a wellbore operation. A method for detecting isotopic ratios during the wellbore operation, comprises receiving a fluid sample from a wellbore during the wellbore operation; passing the fluid sample to an analytical instrument operable to determine isotopic ratios in the fluid sample; outputting data comprising isotopic ratios for at least carbon and hydrogen; assigning a depth to the data; and transmitting the data based on isotopic ratios encountered during the wellbore operation.

Carbon and hydrogen isotope detection and report while drilling

Systems and methods are described for determining the lag time and origin of particles in entrained in a mud stream. A size and shape of the particles may be evaluated at the surface with a visual inspection system, which permits a settling rate to be determined for each of the particles in a non-Newtonian mud stream. Together with an analysis of the pumping schedule, mud properties, trajectory of the wellbore and other fluid dynamics associated with a wellbore operation, an origin of the each of the particles from within the wellbore may be determined. At least one operational parameter for the wellbore operation may be adjusted based on the determined origin of the particles. For example, a clean-out procedure may be initiated if it is determined that particles are settling in an undesirable location in the wellbore.

Growing community of inventors

Lafayette, LA, United States of America

Mathew Dennis Rowe