US Pat. No. 9,587,159

ENZYMES FOR REMOVING SULFUROUS COMPOUNDS IN DOWNHOLE FLUIDS

Baker Hughes Incorporated...

1. A method comprising:
circulating a fluid composition into a subterranean reservoir wellbore; wherein the fluid composition comprises at least one
cysteine synthase that is at least 75% homologous to the cDNA sequence of SEQ ID NO:1 in an effective concentration to decrease
an amount of sulfur-containing compounds; and

decreasing the amount of sulfur-containing compounds in the subterranean reservoir wellbore and/or downhole fluids recovered
therefrom.

US Pat. No. 9,228,686

TRANSMISSION LINE FOR DRILL PIPES AND DOWNHOLE TOOLS

Baker Hughes Incorporated...

1. A wired pipe system comprising:
a wired pipe segment having a first end and a second end;
a first coupler in the first end and a second coupler in the second end; and
a transmission medium disposed in the wired pipe segment between the first and second ends and providing at least part of
an electrical path between the first and second couplers, the transmission medium comprising:

an assembly that includes an inner conductor surrounded over at least a portion of its length by an insulating material;
a fixation element surrounding and attached to the assembly at or near an end of the assembly; and
a wire channel surrounding at least a portion of a length of the assembly and the fixation element, the wire channel being
fixedly connected to the fixation element;

wherein the insulating material includes external threads that mate with internal threads of the fixation element.

US Pat. No. 9,545,037

SYSTEMS AND METHODS FOR COOLING ELECTRIC DRIVES

Baker Hughes Incorporated...

11. A sealed drive system for an electric submersible pump, the sealed drive system comprising:
an upper sealed compartment and a lower sealed compartment, wherein the upper sealed compartment prevents air external to
the upper sealed compartment from entering the upper sealed compartment and the lower sealed compartment prevents the air
external to the lower sealed compartment from entering the lower sealed compartment, wherein the upper sealed compartment
encloses a first set of electrical components and the lower sealed compartment encloses a second set of electrical components;

a duct adjacent the upper and lower sealed compartments and sharing a common wall with the upper and lower sealed compartments;
an upper heat exchanger positioned in the duct and mounted on the common wall, wherein a first portion of air internal to
the upper sealed compartment flows through the upper heat exchanger; and

a lower heat exchanger positioned in the duct and mounted on the common wall, wherein a second portion of the air internal
to the lower sealed compartment flows through the lower heat exchanger;

wherein each of the upper and lower heat exchangers is an air-to-air crossflow heat exchanger having a plurality of crossflow
passageways formed between a series of plates having substantially flat, parallel central portions.

US Pat. No. 9,212,528

LOCK ASSEMBLY WITH CAGELESS DOGS

Baker Hughes Incorporated...

18. A method of locking radially adjacent components, comprising:
positioning a lock assembly with respect to a radially adjacent structure, the lock assembly comprising a set of cageless
dogs and an extender body, each of the dogs having a load bearing surface, each dog being circumferentially adjacent to and
in contact with at least one other dog in the set without any structural components of the lock assembly axially extending
between opposite sides of the dogs or interspaced circumferentially between adjacent ones of the dogs;

maintaining the dogs on the extender body by a retainer concentric with the dogs and located at a same longitudinal location
as the dogs;

transitioning the plurality of dogs between a retracted configuration and an extended configuration with the extender body;
engaging the plurality of dogs with at least one shoulder in the radially adjacent structure; and
supporting the lock assembly at the radially adjacent structure with the load bearing surfaces of the dogs against the shoulder.

US Pat. No. 9,213,474

SYSTEM AND METHOD FOR DISPLAYING WELL DATA

Baker Hughes Incorporated...

1. A method of delivering data from an energy industry or formation operation, comprising:
receiving a data set representing parameter values generated during at least a portion of the operation;
generating at least one data structure on a display area, the at least one data structure providing a visual representation
of at least a portion of the data set;

selecting a visual indicator associated with each of the at least one data structure, the visual indicator including information
identifying an associated data structure;

iteratively determining a suitable location for placement of the visual indicator on the display area by a processor using
a probabilistic algorithm; and

generating the display including the visual indicator located at the suitable position, wherein determining the suitable location
includes, for each iteration, performing:

calculating a probability value based on at least a first cost value, a second cost value, and a time-varying parameter, the
first cost value based on a current position relative to the at least one data structure, the second cost value based on a
different position relative to the at least one data structure; and

moving the visual indicator from the current position to the different position in response to the probability value being
at least a selected value.

US Pat. No. 9,366,777

MEASUREMENT OF PERMEABILITY IN BOREHOLE IN THE PRESENCE OF MUDCAKE

Baker Hughes Incorporated...

1. A method of estimating a permeability of an earth formation, comprising:
generating at least one radial acoustic wave in a borehole fluid acoustically coupled to the earth formation;
measuring an attenuation of the at least one radial acoustic wave over time in the borehole fluid using an acoustic sensor;
and

estimating the permeability using the attenuation over time and at least one theoretical attenuation over time.

US Pat. No. 9,194,830

CORRECTION FOR GAIN VARIATION DUE TO FAST CHANGING NMR SENSOR GAIN

Baker Hughes Incorporated...

1. An apparatus for performing nuclear magnetic resonance (NMR) measurements of a material of interest, the apparatus comprising:
an NMR tool comprising:
a transmitter antenna configured to transmit pulses of electromagnetic energy into the material of interest for performing
NMR measurements;

a transmitter coupled to the transmitter antenna and configured to generate and control the pulses of electromagnetic energy
transmitted by the transmitter antenna;

a receiver antenna disposed at the tool and configured to receive NMR signals in response to the transmitted pulses of electromagnetic
energy, the NMR signals include at least a first signal; and

a processing circuit configured to:
receive the NMR signals;
receive a first system gain related to the first signal the first system gain being related to a system comprising the NMR
tool and the material of interest;

calibrate the NMR signals using the first system gain; and
provide calibrated NMR signals for evaluating the NMR measurements;
wherein:
the NMR signals further include a second signal, the first signal and the second signal being of a phase-alternated group
of signals; and

the processing unit is further configured (i) to receive a second system gain related to the second signal of the phase-alternated
group of signals, the second system gain being related to the system comprising the NMR tool and the material of interest,
and (ii) to calibrate the NMR signals using the second system gain.

US Pat. No. 9,261,622

ELEMENTAL CONCENTRATION DETERMINATION USING NEUTRON-INDUCED ACTIVATION GAMMA RADIATION

BAKER HUGHES INCORPORATED...

1. A method for estimating at least one parameter of interest of a formation, comprising:
estimating the at least one parameter of interest using information from at least one nuclear radiation detector in a borehole
in the formation representative of nuclear radiation from an activated volume of interest in the formation, and exposure time
information relating to exposure of the activated volume to at least one energy source, comprising:

estimating exposure time information using variations in speed of at least one of: i) motion of the at least one energy source;
and ii) motion of the at least one radiation detector.

US Pat. No. 9,217,103

WELL SERVICING FLUID

Baker Hughes Incorporated...

1. A method of treating a well formation with a wellbore servicing fluid, the method comprising:
providing the wellbore servicing fluid formulated with ingredients comprising:
a viscosifying polymer that is a crosslinked copolymer of an ethylenically unsaturated dicarboxylic anhydride and an alkyl
vinyl ether, or the di-acid thereof;

a pH adjuster capable of maintaining a pH of 5.5 or greater;
a non-emulsifier; and
a solvent containing a solution of alcohol and aqueous base, the solvent ranging from about 75% to about 95% by weight based
on the total weight of the well servicing fluid;

gelling the viscosifying polymer in the presence of the non-emulsifier; and
introducing the wellbore servicing fluid into a well.

US Pat. No. 9,243,468

EXPANDABLE ANNULAR ISOLATOR

Baker Hughes Incorporated...

1. A completion method, comprising:
supporting an existing tubular in a wellbore defined by a borehole wall;
delivering an additional tubular, having an initial drift diameter, through said existing tubular and into an overlapping
relation with said existing tubular such that a portion of said additional tubular extends beyond a lower end of the existing
tubular;

providing at least one external seal in a wall recess of said additional tubular;
extending said at least external seal beyond said recess before expansion;
expanding a substantial length of said additional tubular toward the borehole wall;
engaging said seal to a surrounding open hole for sealing therewith.

US Pat. No. 9,234,403

DOWNHOLE ASSEMBLY

Baker Hughes Incorporated...

1. A downhole assembly comprising:
a wave seal packer including a wave portion having a wave form shape in an un-expanded condition, the wave portion configured
to radially encircle a tubular with alternating and interconnected uphole and downhole portions, the packer having a substantially
uniform internal radius in the un-expanded condition, the wave seal packer further including axially extending fingers connected
to the wave portion and extending axially away from the wave portion with respect to a longitudinal axis of the downhole assembly;
and,

a liner hanger having a plurality of slips, wherein the packer is fixed relative to the liner hanger.

US Pat. No. 9,394,779

HYDRAULIC FRACTURING ISOLATION METHODS AND WELL CASING PLUGS FOR RE-FRACTURING HORIZONTAL MULTIZONE WELLBORES

BAKER HUGHES INCORPORATED...

1. A method for re-fracturing a location of a formation of a multizone horizontal wellbore, the method comprising:
hydraulically isolating a first location from a portion of the multizone horizontal wellbore uphole from the first location,
the first location having been previously hydraulically fractured at least once;

hydraulically re-fracturing the first location;
providing a first plug within the wellbore proximate to the first location after the first location has been hydraulically
re-fractured;

pumping fluid down the wellbore to bridge off the first plug within the wellbore to hydraulically isolate the re-fractured
first location from the multizone horizontal wellbore uphole of the first location, wherein the first plug comprises proppant
combined with crystalline silica

hydraulically isolating a second location from a portion of the multizone horizontal wellbore uphole of the second location;
hydraulically fracturing the second location;
providing a second plug within the wellbore proximate to the second location after the second location has been fractured;
and

pumping fluid down the wellbore to bridge off the second plug within the wellbore to hydraulically isolate the second location
from a portion of the multizone horizontal wellbore uphole of the second location, wherein the second plug comprises proppant
combined with crystalline silica.

US Pat. No. 9,303,454

SYSTEMS AND METHODS TO REDUCE OSCILLATIONS IN MAGNETIC COUPLINGS

BAKER HUGHES INCORPORATED...

6. A drilling system comprising:
a turbine;
a magnetic coupling coupled to the turbine including:
a rotor having a plurality of inner magnets disposed thereon in circular arrangement in an inner magnet region; and
an outer housing surrounding the inner magnet region and separated from the inner magnet region by a separator layer and including
outer magnets and arranged such that rotation of the outer housing causes the rotor to rotate about an axis of rotation; and

an alternator coupled to the magnetic coupling that provides electricity at an output;
a load coupled to the output; and
an electrical damping circuit coupled in parallel with the load and configured to cancel oscillations in the electricity at
a self excitation frequency of the magnetic coupling.

US Pat. No. 9,389,329

ACOUSTIC SOURCE WITH PIEZOELECTRIC ACTUATOR ARRAY AND STROKE AMPLIFICATION FOR BROAD FREQUENCY RANGE ACOUSTIC OUTPUT

Baker Hughes Incorporated...

1. An acoustic energy source for use with a downhole tool comprising:
a body mounted to a housing of the downhole tool;
a first cavity in the body having an elastomer;
a second cavity in the body having a fluid;
a diaphragm coupled with the body adjacent the first cavity, and that selectively reciprocates axially outward from the first
cavity and axially inward to the first cavity;

a dynamic yoke having an end projecting into the second cavity and an opposite end holding a pressure disk projecting into
the first cavity and embedded in the elastomer of the first cavity;

a plurality of electrically reactive stacks that are each selectively energized into an oscillatory extended and contracted
configuration;

a plurality of quill tips each having an end in contact with a one of the electrically reactive stacks and each is moved radially
inward when an associated electrically reactive stack is in the extended configuration, and each is moved radially outward
when an associated electrically reactive stack is in the contracted configuration, and each quill tip having an opposite end
profiled substantially complimentary with a recesses in the dynamic yoke, so that a film of the fluid in the second cavity
remains between each quill tip and the dynamic yoke when the electrically reactive stacks are in the extended configuration
and in the contracted configuration; and

a tuned resonant mount having an end attached to the body and an opposite end attached to the downhole tool, and that couples
dynamically with motion of the diaphragm to create resonant response of the acoustic output of the source at designated operational
frequencies and ranges.

US Pat. No. 9,354,348

METHOD OF MEASURING PARAMETERS OF A POROUS MEDIUM USING NANOPARTICLE INJECTION

BAKER HUGHES INCORPORATED...

1. A method of estimating a value of at least one parameter of interest of an earth formation, comprising:
applying an alternating magnetic field at a plurality of frequencies to an interface between the earth formation and a borehole
fluid using a magnet disposed on a tool configured to be conveyed through a borehole penetrating the earth formation;

injecting nanoparticles into the earth formation using an injector device disposed on the tool;
estimating a displacement velocity of the nanoparticles using a sensor disposed on the tool; and
estimating a value of the at least one parameter of interest using the estimated displacement velocity;
wherein estimating the value of the at least one parameter of interest further comprises estimating a characteristic frequency
defined by the formula


where k is the permeability of the earth formation, ? is a kinetic coefficient, ? is electrical conductivity, ? is density
of a continuum ?l is partial density of a saturated fluid continuum, and ? is fluid viscosity.

US Pat. No. 9,273,546

APPARATUS AND METHOD FOR PROTECTING DEVICES DOWNHOLE

BAKER HUGHES INCORPORATED...

1. An apparatus for conducting downhole measurement related operations in a borehole penetrating an earth formation, comprising:
a conveyance device configured for use in the borehole;
a downhole assembly connected to the conveyance device;
a module associated with the downhole assembly and configured to receive at least one device;
a housing disposed on an exterior of the module, the housing including at least one opening, the at least one device being
removable from the module through the at least one opening, wherein the housing is configured to move between a first position
that provides access to one of the at least one device from an exterior of the housing and a second position that isolates
the at least one device from the exterior of the housing, and wherein the housing is in the second position when the apparatus
is in the borehole;

a locking device surrounding the housing, the locking device including at least one fastener preventing rotational movement
between the first position and the second position; and

an overload protection member surrounding the housing, the overload protection member being separate from the locking device.
US Pat. No. 9,051,512

METHOD OF TREATING A SUBTERRANEAN FORMATION WITH NON-SPHERICAL PROPPANTS

Baker Hughes Incorporated...

1. A method of stimulating production of hydrocarbons from a subterranean formation penetrated by a wellbore, comprising introducing
into the wellbore a cylindrical ceramic proppant having an aspect ratio less than or equal to 5.0:1.0 and forming in the subterranean
formation a close-packed structure of particulates of the cylindrical ceramic proppant where the particulates are in communication
with each other.

US Pat. No. 9,045,943

COMPONENTS AND MOTORS FOR DOWNHOLE TOOLS AND METHODS OF APPLYING HARDFACING TO SURFACES THEREOF

Baker Hughes Incorporated...

8. A method of applying hardfacing to a surface of a hydraulic drilling motor, the method comprising:
mixing a plurality of hard particles, a plurality of metal matrix particles, a polymeric material, and a solvent to form a
paste;

removing the solvent from the paste to form a first hardfacing precursor including an at least substantially solid sheet comprising
the plurality of hard particles, the plurality of metal matrix particles, and the polymeric material;

applying the first hardfacing precursor on an outer surface of at least two lobes of a rotor;
forming a second hardfacing precursor having a composition different than the first hardfacing precursor;
disposing the second hardfacing precursor on the outer surface of the rotor between the at least two lobes; and
heating the first hardfacing precursor and the second hardfacing precursor to form a sintered hardfacing material on the outer
surface of the rotor, the sintered hardfacing material comprising a composite material having a relatively hard first phase
distributed within a second, continuous matrix phase, the second phase comprising a metal or a metal alloy, the sintered hardfacing
material comprising a first hardfacing material and a second hardfacing material, the second hardfacing material having a
composition different from a composition of the first hardfacing material.

US Pat. No. 9,303,200

POLYMER COMPOSITION, SWELLABLE COMPOSITION COMPRISING THE POLYMER COMPOSITION, AND ARTICLES INCLUDING THE SWELLABLE COMPOSITION

BAKER HUGHES INCORPORATED...

1. A sealing element for a flow channel comprising:
an expandable section; and
a swellable composition disposed in the expandable section and comprising:
a base polymer comprising polyethylenes, polypropylenes, poly(ethylene-co-propylene), polyamides, polyesters, polyurethanes,
polyvinylchlorides, ethylene-propylene-diene monomer rubber, butadiene rubber, styrene-butadiene rubber, natural rubber, or
a combination comprising at least one of the foregoing;

an acrylic copolymer comprising an acidic monomer and an amide monomer present in a weight ratio of 95:5 to 5:95; acrylic
copolymer being present in an amount of 30 to 200 parts by weight per hundred parts by weight of the base polymer; and

a refined oil in which the acrylic copolymer to form a liquid dispersed polymer;
wherein the swellable composition is configured to swell when treated with a swelling material which comprises an aqueous
medium, non-aqueous medium, or both.

US Pat. No. 9,273,522

STEERING HEAD WITH INTEGRATED DRILLING DYNAMICS CONTROL

Baker Hughes Incorporated...

1. A method of reducing a vibration of a drill string in a borehole, comprising:
coupling a first actuator and a second actuator to a steering pad of the drill string, wherein the first actuator and the
second actuator are driven by a hydraulic fluid flowing in a hydraulic circuit;

obtaining one or more measurements of a parameter of the vibration of the drill string; and
driving the hydraulic fluid to activate the first actuator and the second actuator to apply a first force and a second force,
respectively, at the steering pad against a wall of the borehole responsive to the obtained one or more measurements, wherein
the first actuator applies the first force at a first frequency and the second actuator applies the second force at a second
frequency different from the first frequency and a combination of the first force and the second force reduces the vibration
of the drill string.

US Pat. No. 9,267,821

COMBINED SWEPT-CARRIER AND SWEPT-MODULATION FREQUENCY OPTICAL FREQUENCY DOMAIN REFLECTOMETRY

Baker Hughes Incorporated...

1. An apparatus for obtaining a parameter of interest, the apparatus comprising:
an optical fiber;
an optical component that provides the parameter of interest, the optical component being in communication with the optical
fiber and configured to interact with light at a wavelength related to the parameter of interest; and

an optical interrogator in communication with the optical fiber and configured to:
illuminate the optical fiber with a series of light inputs, each light input in the series having a substantially constant
unique optical wavelength and swept-frequency amplitude modulation; and

receive a resulting light signal associated with each light input in the series;
wherein the resulting light signals associated with the series of light inputs are used to obtain the parameter of interest.

US Pat. No. 9,212,541

SYSTEM AND APPARATUS FOR WELL SCREENING INCLUDING A FOAM LAYER

Baker Hughes Incorporated...

1. An apparatus for screening earth formation components, comprising:
a base pipe configured to direct the passage of formation fluid; and
a foam layer disposed radially outwardly of the base pipe and configured to allow the passage of formation fluid therethrough
and minimize the passage of formation solids therethrough, the foam layer including a plurality of closed hollow structures
arranged to form interstices located between walls of adjacent ones of the hollow structures.

US Pat. No. 9,303,505

MULTI-PARAMETER BIT RESPONSE MODEL

BAKER HUGHES INCORPORATED...

1. A computer-implemented method of generating a directional response of a drill bit based on one or more drilling parameters,
the method comprising:
performing a plurality of tests with a drill bit in a test material having a strength under different experimental drilling
parameters;

recording the results of the plurality of tests;
forming a representation of an expected directional response of the drill bit based on the results;
receiving current drilling parameters at a computing device; and
generating the directional response based on the current drilling parameters by utilizing the representation;
wherein the representation is a matrix or a look-up table;
wherein if one of the current drilling parameter is between two of the experimental drilling parameters, directional response
is generated based on an interpolation between responses of the two experimental drilling parameters.

US Pat. No. 9,291,505

POLARIZATION SCRAMBLING IN INTERFEROMETER SYSTEMS

BAKER HUGHES INCORPORATED...

1. An interferometer-based sensor system, comprising:
a tunable laser configured to transmit a transmit signal;
a polarization scrambler configured to change a polarization state of the transmit signal prior to each scan such that the
polarization state of the transmit signal for one scan differs from the polarization state of the transmit signal for another
scan;

an interferometer configured to provide an output scan based on the transmit signal with the polarization state change for
each scan, the interferometer comprising one or more fiber Bragg gratings (FBGs) and a reference reflector and the output
scan resulting from interference between a reflection signal from the reference reflector with a reflection signal from one
of the one or more FBGs; and

a processor configured to process the output scan.

US Pat. No. 9,291,002

METHODS OF REPAIRING CUTTING ELEMENT POCKETS IN EARTH-BORING TOOLS WITH DEPTH-OF-CUT CONTROL FEATURES

Baker Hughes Incorporated...

1. A method of repairing an earth-boring tool, comprising:
removing a cutting element from a cutting element pocket in a body of the earth-boring tool;
inserting a temporary displacement member into the cutting element pocket in the body of the earth-boring tool;
providing a depth-of-cut control feature comprising a particle-matrix composite material over a portion of a surface of the
temporary displacement member, the depth-of-cut control feature bonded to the body of the earth-boring tool proximate the
temporary displacement member, including forming the depth-of-cut control feature to have a size and shape configured to limit
a depth-of-cut of another cutting element to be secured within the cutting element pocket;

removing the temporary displacement member from the cutting element pocket; and
securing the other cutting element within the cutting element pocket.

US Pat. No. 9,080,399

EARTH-BORING TOOLS INCLUDING RETRACTABLE PADS, CARTRIDGES INCLUDING RETRACTABLE PADS FOR SUCH TOOLS, AND RELATED METHODS

Baker Hughes Incorporated...

1. A cartridge for an earth-boring tool, the cartridge comprising:
a barrel wall defining a first bore;
a piston comprising at least one retractable pad positioned at least partially within the first bore;
a first reservoir within the first bore adjacent the piston;
an opening to the first reservoir;
a valve positioned and configured to regulate fluid flow through the opening; and
another barrel wall defining a second bore and having a second reservoir therein positioned for fluid communication with the
first reservoir through the valve, wherein the valve is positioned between the first reservoir and the second reservoir.

US Pat. No. 9,243,464

FLOW CONTROL DEVICE AND METHODS FOR USING SAME

BAKER HUGHES INCORPORATED...

12. A method for controlling flow of a fluid from a first section to a second section, comprising:
enclosing the first section and the second section in an enclosure;
forming a flow path conveying the fluid from the first section to the second section;
movably disposing a mandrel in the enclosure;
disposing a closure member and a biasing member on the mandrel, the mandrel having a bore, the flow path including the bore
of the mandrel;

positioning a sealing member, the biasing member, and the closure member in the second section and along a flow path of the
flowing fluid;

forming a fluid seal in the fluid conduit when the biasing member presses the closure member against the sealing member, wherein
the fluid seal blocks fluid flowing along the flow path from the first section to the bore of the mandrel;

fixing a piston to the mandrel such that the piston moves with the mandrel, wherein a cavity is formed between the piston
and the sealing member, and wherein the cavity receives the fluid from the first section when the closure member unseats from
the sealing member;

applying a compressive force on the sealing member using a biasing member; and
resisting a force applied to the closure member using a dampener positioned in the second section, and connected to the closure
member wherein the dampener includes a first chamber, and wherein movement of the mandrel and the piston in response to pressure
in the cavity reduces a volume of the first chamber.

US Pat. No. 9,068,411

THERMAL RELEASE MECHANISM FOR DOWNHOLE TOOLS

Baker Hughes Incorporated...

1. A release mechanism for actuating a downhole tool, the release mechanism comprising:
a first connector having a first material, the first material having a first coefficient of thermal expansion;
a second connector having a second material, the second material having a second coefficient of thermal expansion, the second
coefficient of thermal expansion being different from the first coefficient of thermal expansion, and the second connector
being releasably connected to the first connector;

a connector tension element securing a first end of the first connector to a first end of the second connector;
a heating element operatively associated with at least one of the first material or the second material; and
a power source operatively associated with the heating element,
wherein the first connector and the second connector have a secured position relative to each other and a released position
relative to each other, and

wherein activation of the heating element causes the first connector and the second connector to be move toward the released
position.

US Pat. No. 9,062,506

MULTI-PISTON HYDROSTATIC SETTING TOOL WITH LOCKING FEATURE OUTSIDE ACTUATION CHAMBERS FOR MULTIPLE PISTONS

Baker Hughes Incorporated...

1. A hydrostatically actuated setting tool for a subterranean tool for operation at a subterranean location using hydrostatic
pressure, comprising:
a mandrel;
a plurality of pistons disposed on said mandrel, said pistons formed to define a pair of opposed chambers adjacent each said
piston;

at least one lock assembly located on said mandrel and outside said opposed chambers associated with operation of each said
piston, said lock assembly selectively operated with hydrostatic pressure at the subterranean location to selectively release
said pistons to move to actuate the subterranean tool responsive to at least in part hydrostatic pressure in the subterranean
location adjacent said mandrel;

said pistons are in initial pressure balance from hydrostatic pressure in an annulus about the setting tool.

US Pat. No. 9,428,967

POLYCRYSTALLINE COMPACT TABLES FOR CUTTING ELEMENTS AND METHODS OF FABRICATION

Baker Hughes Incorporated...

11. A polycrystalline compact table for a cutting element, the table comprising:
a first plurality of discrete regions of first grains of a super hard material;
a second plurality of discrete regions of second grains of the super hard material, the second grains having a different property
than a property of the first grains; and

at least one discrete region of the first plurality vertically disposed between at least two discrete regions of the second
plurality.

US Pat. No. 9,290,998

ACTUATION MECHANISMS FOR DOWNHOLE ASSEMBLIES AND RELATED DOWNHOLE ASSEMBLIES AND METHODS

Baker Hughes Incorporated...

10. A method of using an actuation mechanism for downhole assemblies in earth-boring applications, comprising:
increasing flow rate of a fluid flowing through a flow path defined by an internal bore of a housing;
moving a movable sleeve biased toward a first position from the first position to a second position to align an upper selective
engagement member of the movable sleeve with a groove formed in an interior surface of the housing, the interior surface defining
the internal bore responsive to the increase in flow rate;

releasing an actuation member located in the actuation mechanism from engagement with the upper selective engagement member
responsive to aligning the upper selective engagement member with the groove to enable the actuation member to engage with
a lower selective engagement member of the movable sleeve responsive to the movable sleeve being located in the second position;

reducing flow rate of the fluid flowing through the flow path;
returning the movable sleeve to the first position by enabling a biasing member engaged with the movable sleeve to move the
lower selective engagement member into alignment with the groove responsive to the decrease in flow rate; and

releasing the actuation member from engagement with the lower selective engagement member responsive to aligning the lower
selective engagement member with the groove to enable the actuation member to travel along the flow path beyond the housing.

US Pat. No. 9,200,483

EARTH-BORING TOOLS AND METHODS OF FORMING SUCH EARTH-BORING TOOLS

Baker Hughes Incorporated...

16. A method of forming an earth-boring drill bit, comprising:
forming a bit body comprising blades extending radially over a face of the earth-boring drill bit;
attaching only cutting elements comprising nonplanar cutting faces to at least one of the blades;
attaching only cutting elements comprising planar cutting faces to at least another of the blades;
attaching only cutting elements comprising nonplanar cutting faces or only cutting elements comprising planar cutting faces
to each of the blades; and

attaching only cutting elements comprising nonplanar cutting faces to a number of blades different from a number of blades
to which only cutting elements comprising planar cutting faces are attached.

US Pat. No. 9,045,955

DETRITUS FLOW MANAGEMENT FEATURES FOR DRAG BIT CUTTERS AND BITS SO EQUIPPED

Baker Hughes Incorporated...

1. A cutting element for use in subterranean drilling, the cutting element comprising, as manufactured and prior to use in
subterranean drilling:
a cutter barrel comprising a supporting substrate having a superabrasive table directly secured to an end thereof; and
a side surface on the cutter barrel and extending longitudinally away from a cutting edge of the superabrasive table, the
side surface comprising at least one flow management feature positioned on a substrate portion of the side surface longitudinally
adjacent to a diamond table portion of the side surface and configured to lift rock detritus cut by an edge of the superabrasive
table from a subterranean formation away from the side surface of the cutter barrel extending substantially to the cutting
edge to enable the cutting edge to directly contact subterranean formation rock by substantially equalizing, when the cutting
element is used for subterranean drilling of a wellbore, hydrostatic pressure of drilling fluid immediately adjacent to the
supporting substrate portion of the side surface and the superabrasive table portion of the side surface and ambient hydrostatic
drilling fluid pressure in the wellbore.

US Pat. No. 9,439,277

ROBOTICALLY APPLIED HARDFACING WITH PRE-HEAT

BAKER HUGHES INCORPORATED...

1. A method for depositing hardfacing material on at least one surface of a tooth of a rolling cutter, comprising:
providing a pre-heating apparatus;
pre-heating a rolling cutter with the pre-heating apparatus;
providing a vertically oriented plasma transfer arc torch secured to a positioner having controllable movement in a vertical
plane;

securing the rolling cutter to a chuck mounted on an articulated arm of a robot;
positioning a surface of a tooth of the rolling cutter in a substantially perpendicular relationship beneath the torch;
moving the rolling cutter with the articulated arm of the robot in a plane beneath the torch in a manner providing a target
path on the surface of the tooth, the target path beginning near a crest portion of the tooth and ending near a base portion
of the tooth, the target path forming a first waveform about a centerline of the surface of the tooth, the target path having
a plurality of tooth traversing portions substantially parallel to the crest portion of the tooth, the target path having
a plurality of step paths interconnecting the plurality of tooth traversing portions, the step paths of the plurality of step
paths being located at opposite edges of the surface of the tooth in an alternating fashion between subsequent tooth traversing
portions of the plurality of tooth traversing portions, each step path of the plurality of step paths being parallel with
the edge of the surface of the tooth at which each step path is located;

oscillating the torch linearly on a horizontal axis while moving the rolling cutter with the articulated arm of the robot
in the plane beneath the oscillating torch so as to impose a second torch waveform onto the first waveform on the surface
of the tooth, wherein a midpoint of the torch oscillation substantially follows the target path, the second torch waveform
having an amplitude such that the second torch waveform on adjacent tooth traversing portions overlaps;

rotating the rolling cutter with the articulated arm of the robot in the plane beneath the torch and about the z-axis of the
midpoint of the torch oscillation while the midpoint of torch oscillation follows each tooth traversing portion of the plurality
of tooth traversing portions, such that:

the horizontal axis is parallel with each step path of the plurality of step paths when the torch follows each step path;
the horizontal axis is perpendicular to each tooth traversing portion of the plurality of tooth traversing portions when the
midpoint of the torch oscillation is coincident with a midpoint of each tooth traversing portion; and

the rolling cutter is rotated reciprocally at each subsequent tooth traversing portion of the of tooth traversing portions;
depositing a hardfacing material on the surface of the tooth of the rolling cutter with the torch at least along the second
waveform between step paths while performing the moving the rolling cutter with the articulated arm of the robot in the plane
beneath the torch, in the manner providing the target path, while performing the oscillating the torch linearly on the horizontal
axis and while performing the rotating the rolling cutter with the articulated arm of the robot to provide a pattern of overlapping
deposited hardfacing material; and

continuously heating a localized region of the rolling cutter to which hardfacing material is to be applied with a second
torch of the pre-heating apparatus while depositing the hardfacing material.

US Pat. No. 9,284,229

CARBON COMPOSITES, METHODS OF MANUFACTURE, AND USES THEREOF

BAKER HUGHES INCORPORATED...

1. A carbon composite comprising
a plurality of expanded graphite particles; and
a second phase comprising a carbide, a carbonization product of a polymer, or a combination thereof;
wherein the second phase bonds at least two adjacent basal planes of the same expanded graphite particle together.
US Pat. No. 9,267,070

MONO- AND POLYENOIC ACID AND METAL PARTICLE MIXTURES FOR BREAKING VES-GELLED FLUIDS

Baker Hughes Incorporated...

1. A method for breaking the viscosity of an aqueous fluid gelled with a viscoelastic surfactant (VES) comprising:
providing an aqueous fluid that is a brine comprising KCl, NaCl, CaCl2, or CaBr2;

adding to the aqueous fluid, in any order, components comprising:
a VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant, or a combination
thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles,

an unsaturated fatty acid comprising a monoenoic acid or a polyenoic acid; or a combination thereof; and
a plurality of metal particles to produce a mixture comprising dispersed metal particles in the gelled aqueous fluid, the
metal particles comprise coated metal particles comprising metal particle cores formed from a transition metal selected from
Group VA, VIA, VIIA, VIIIA, IB, IIB, IIIB or IVB of the Periodic Table, or an alloy thereof, or a combination thereof that
are configured for dissolution in the aqueous fluid to provide a source of transition metal ions and metal coating layers
that are configured to selectively control access of the aqueous fluid to the metal particle cores;

selectively controllable dissolution of the metal particles in the gelled aqueous fluid to provide the source of transition
metal ions; and

heating the gelled aqueous fluid to a temperature sufficient to cause the unsaturated fatty acid to auto-oxidize to products
that reduce the viscosity of the gelled aqueous fluid, wherein the transition metal ions comprise an auto-oxidation rate control
compound that controls an auto-oxidation rate of the unsaturated fatty acid.

US Pat. No. 9,080,416

SETTING TOOL, ANCHORING AND SEALING DEVICE AND SYSTEM

Baker Hughes Incorporated...

1. An anchoring and sealing device comprising:
at least one slip;
a seal; and
a tubular in operable communication with the at least one slip and the seal the anchoring and sealing device being configured
to cause radial movement of the at least one slip into anchoring engagement with a structure and to cause radial movement
of the seal into sealing engagement with the structure in response to longitudinal compression of the anchoring and sealing
device and to maintain anchoring and sealing engagement with the structure without additional components except for the at
least one slip, the seal and the tubular, the anchoring and sealing device including at least one seat receptive to a plug
run thereagainst wherein pressure built against a plug seat at the at least one seat increases at least one of sealing forces
between the seal and the structure and anchoring forces between the at least one slip and the structure.

US Pat. No. 9,316,089

SEAT APPARATUS AND METHOD

BAKER HUGHES INCORPORATED...

1. A downhole fracturing system comprising:
a seat assembly having a plurality of like-sized openings therein, each of the like-sized openings having a cross sectional
area complementary to a corresponding plurality of objects such that each of the objects is matable therewith to substantially
inhibit fluid flow through each like-sized opening, the objects having dimensions insufficient to mate with an opening in
a next adjacent upstream seat assembly, wherein a first opening of the plurality of like-sized openings is disposed on a first
plane and a second opening of the plurality of like-sized openings is disposed on a second plane off-set of the first plane
along an axis extending substantially longitudinally through the seat assembly.

US Pat. No. 9,279,302

PLUG COUNTER AND DOWNHOLE TOOL

Baker Hughes Incorporated...

12. A downhole tool comprising:
a housing having a support and one or more plug passage recesses;
a movable plug seat positionable to be supported by the support or aligned with the one or more plug passage recesses;
a helix sleeve rotatable relative to the movable plug seat and in response to movement of the movable plug seat, the helix
sleeve having a helical track including a plurality of consecutive turns; and,

a key responsive to movement of the helix sleeve and configured to prevent further movement of the helix sleeve and movable
plug seat after a selected number of movable plug seat movements.

US Pat. No. 9,279,317

PASSIVE ACOUSTIC RESONATOR FOR FIBER OPTIC CABLE TUBING

BAKER HUGHES INCORPORATED...

1. A method of utilizing a passive acoustic system in a subsurface borehole, the method comprising:
disposing the passive acoustic system in the borehole, the passive acoustic system including at least one passive acoustic
resonator;

monitoring a frequency of an acoustic signal at the at least one passive acoustic resonator and
determining properties of wellbore fluid, the determining including identifying an ingress of the wellbore fluid into the
passive acoustic system, based on the frequency of the acoustic signal and a known geometry of the at least one passive acoustic
resonator.

US Pat. No. 9,399,591

NITROGEN-CONTAINING COMPOUNDS FOR BACTERIAL CONTROL IN WATER BASED FLUIDS

Baker Hughes Incorporated...

1. A method comprising:
adding an effective amount of at least one nitrogen-containing composition to a wastewater stream within a water treatment
system; wherein the wastewater stream comprises an aqueous-based fluid, a first bacteria, a second bacteria, and at least
one organic acid; and wherein the first bacteria is selected from the group consisting of filamentous bacteria, Zoogloea bacteria, and combinations thereof; and whereby the second bacteria out-competes the first bacteria in consuming the at least
one organic acid;

at least partially reducing an amount of the at least one organic acid; and
at least partially reducing an amount of the first bacteria within the wastewater stream as compared to an otherwise identical
wastewater stream absent the at least one nitrogen-containing composition.

US Pat. No. 9,200,510

SYSTEM AND METHOD FOR ESTIMATING DIRECTIONAL CHARACTERISTICS BASED ON BENDING MOMENT MEASUREMENTS

Baker Hughes Incorporated...

1. A system for measuring directional characteristics of a downhole tool, the system comprising:
at least one bending moment (BM) measurement device disposed at a downhole component that is configured to be movable within
a borehole, the at least one BM measurement device configured to generate bending moment data, the bending moment data including
a bending vector of the downhole tool, a bending moment representing an amplitude of the bending vector, and a bending tool
face (BTF) angle representing an orientation of the bending vector relative to gravity high side, the BTF estimated using
a first calculation based on the downhole component being in a sliding mode, the BTF estimated using a second calculation
based on the downhole component being in a rotary mode; and

a processor in operable communication with the BM measurement device and configured to receive bending moment data from the
BM measurement device for a single selected depth, calculate a dogleg severity (DLS) from the bending moment measured only
at the single selected depth and a well tool face (WTF) angle from the BTF angle, and calculate a change in inclination at
the selected depth based on the DLS and the WTF angle.

US Pat. No. 9,187,959

AUTOMATED STEERABLE HOLE ENLARGEMENT DRILLING DEVICE AND METHODS

Baker Hughes Incorporated...

1. An apparatus for forming a wellbore in an earthen formation, comprising:
a drill bit;
a downhole drilling motor comprising a housing and an output shaft;
a controllable steering device comprising a housing connected to the drilling motor housing, the controllable steering device
including at least one pad extensible relative to the steering device housing to steer the drill bit in a selected direction
by application of lateral force to a wall of the wellbore; and

a hole enlargement device having selectively extendable cutting elements configured to automatically extend and retract to
selectively enlarge the diameter of the wellbore formed by the drill bit;

wherein the output shaft extends through the steering device housing, the hole enlargement device is operably coupled to the
output shaft on a side of the steering device opposite the drilling motor, and the drill bit is operably coupled, with no
intermediate components therebetween, to the hole enlargement device on a side thereof opposite the steering device.

US Pat. No. 9,187,961

PARTICULATE MIXTURES FOR FORMING POLYCRYSTALLINE COMPACTS AND EARTH-BORING TOOLS INCLUDING POLYCRYSTALLINE COMPACTS HAVING MATERIAL DISPOSED IN INTERSTITIAL SPACES THEREIN

Baker Hughes Incorporated...

1. An earth-boring drill bit, comprising:
a bit body; and
a plurality of cutting elements attached to the bit body, at least one cutting element of the plurality of cutting elements
comprising a hard polycrystalline material including:

a first plurality of grains having a first average grain size;
at least a second plurality of grains having a second average grain size at least one hundred fifty (150) times larger than
the first average grain size of the first plurality of grains, the first plurality of grains and the second plurality of grains
being interspersed and interbonded with one another to form a polycrystalline hard material; and

an interstitial material concentrated around the first plurality of grains in interstitial spaces between the interspersed
and interbonded grains of the polycrystalline hard material, the interstitial material comprising at least one material selected
from the group consisting of carbon nitride carbon boride metal carbonates and metal bicarbonates.

US Pat. No. 9,121,265

FULL FLOW GUN SYSTEM FOR MONOBORE COMPLETIONS

Baker Hughes Incorporated...

1. A perforating method for a borehole to a subterranean location, comprising:
locating a perforating gun assembly at a predetermined location with a running string;
firing said assembly when supported by said running string;
releasing said running string from supporting said gun assembly after said firing,
running in a production string with an isolation device extendable onto a borehole tubular at a spaced location from said
predetermined location of said gun assembly;

producing fluids through, around and beyond a length of said assembly from at least one surrounding formation with said assembly
remaining in place after said firing.

US Pat. No. 9,308,600

ARC GUIDING, GRIPPING AND SEALING DEVICE FOR A MAGNETICALLY IMPELLED BUTT WELDING RIG

BAKER HUGHES INCORPORATED...

1. An apparatus for connecting wellbore tubulars at a rig floor, comprising:
a magnetically impelled arc butt (MIAB) welding device positioned on the rig floor and configured to heat facing ends of a
pair of wellbore tubulars; and

a force application device configured to compressively engage the facing ends to form a welded joint.

US Pat. No. 9,255,461

REMOVABLE FRACTURING PLUG OF PARTICULATE MATERIAL HOUSED IN A SHEATH SET BY EXPANSION OF A PASSAGE THROUGH THE SHEATH

Baker Hughes Incorporated...

1. A plug for subterranean use between zones where flow between said zones is to be minimized, comprising:
a porous sheath having a toroidal shape said sheath defining a volume containing a fill material therein and said toroidal
shape further defining an interior void that forms a passage through said toroidal shape, said passage having a first and
second end and a longitudinal axis extending through said ends, said passage isolated from fill material contained in said
toroidal shape;

said sheath having a run in configuration when said first and second ends are spaced apart from each other with said passage
open to flow and a set position when a swage is moved through said passage increasing and then retaining the passage dimension
in a direction perpendicular to said axis by virtue of compaction of said fill material while pushing fluid through said sheath.

US Pat. No. 9,243,181

DUAL-FUNCTIONAL BREAKER FOR HYBRID FLUIDS OF VISCOELASTIC SURFACTANT AND POLYMER

BAKER HUGHES INCORPORATED...

1. A dual-functional breaker emulsion comprising:
an oil external phase comprising an oil-soluble surfactant, and
a water internal phase comprising a water-soluble polymer breaker.
US Pat. No. 9,193,879

NANO-COATINGS FOR ARTICLES

Baker Hughes Incorporated...

1. A composite comprising:
a substrate comprising a fluoroelastomer, a perfluoroelastomer, a hydrogenated nitrile butyl rubber, an ethylene-propylene-diene
monomer (EPDM) rubber, a silicone, an epoxy, a polyetheretherketone, a bismaleimide, a polyvinylalcohol, a phenolic resin,
a tetrafluoroethylene-propylene elastomeric copolymer, iron, steel, a chrome alloy, hastelloy, titanium, molybdenum, or a
combination comprising at least one of the foregoing;

a binder layer disposed on a surface of the substrate; and
a nanofiller layer comprising nanographene and disposed on a surface of the binder layer opposite the substrate, wherein the
nanographene is derivatized to have functional groups including epoxy, ether, ketone, amine, hydroxy, alkoxy, alkyl, lactone,
aryl, or a combination comprising at least one of the forgoing functional groups; and the binder layer is different than the
nanofiller layer;

wherein the binder layer is a positively charged binder layer, comprising a polyethyleneamine, a polyethyleneimine, a hyperbranched
polyamine, a dendrimeric polyamine, a polyaminoacrylate, a polyaminoacrylate copolymer, or combinations comprising at least
one of the foregoing polymers; or wherein the binder layer is a negatively charged binder layer comprising a polycarboxylic
acid, a salt of a polycarboxylic acid, a polycarboxylic acid copolymer, or combinations comprising at least one of the foregoing
polymers; and

wherein the nanofiller layer further comprises carbon black, mica, clays, or a combination thereof.

US Pat. No. 9,181,786

SEA FLOOR BOOST PUMP AND GAS LIFT SYSTEM AND METHOD FOR PRODUCING A SUBSEA WELL

Baker Hughes Incorporated...

1. A method for producing at least one subsea well, comprising:
(a) installing a pump and a gas/liquid separator on a sea floor and connecting a discharge of the pump to an inlet of the
separator,

(b) flowing a well fluid up the well;
(c) with the separator, separating gas from liquid in the well fluid;
(d) with the pump, pumping the liquid separated to a remote production facility;
(e) injecting at a selected depth in the well and into the well fluid flowing up the well at least some of the gas separated
by the separator;

(f) sensing a ratio of gas to liquid in the well fluid flowing to the pump; and
(g) injecting a non production gas into the well if the ratio is less than a desired amount.

US Pat. No. 9,127,683

HIGH TEMPERATURE RADIAL BEARING FOR ELECTRICAL SUBMERSIBLE PUMP ASSEMBLY

Baker Hughes Incorporated...

1. A submersible pump assembly, comprising:
a rotary pump having a longitudinal axis;
an electrical motor operatively connected to the pump for driving the pump;
a seal section connected between the motor and the pump for reducing a pressure differential between lubricant in the motor
and hydrostatic well fluid pressure;

a shaft assembly extending from the motor through the seal section and the pump;
a sleeve surrounding the shaft assembly;
a carrier body having an inner diameter surface;
an anti-rotation member on an exterior of the carrier body in static engagement with the inner diameter surface of the pump
assembly for preventing rotation of the carrier body; and

an annular metal radially deflectable spring located between and in contact with an outer diameter surface of the sleeve and
with the inner diameter surface of the carrier body for preventing the sleeve from rotating; wherein:

the spring comprises a wave spring having a circumscribed outer diameter that prior to insertion between the carrier body
and the sleeve is initially greater than the inner diameter surface of the carrier body; and

the wave spring has a circumscribed inner diameter that prior to insertion between the carrier body and the sleeve is initially
smaller than the outer diameter surface of the sleeve.

US Pat. No. 9,428,984

DRIVE OFF METHOD FROM SUBSEA WELL WITH PIPE RETENTION CAPABILITY

Baker Hughes Incorporated...

1. A method for shutting in a well in an emergency, comprising:
providing a pipe catcher adjacent a blowout preventer;
supporting a pipe with said pipe catcher;
stabilizing said pipe after said supporting by engaging said supported pipe with a pipe ram located adjacent and above said
pipe catcher;

cutting said now stabilized pipe with a shear ram located on an opposite side of said pipe ram from said pipe catcher after
said stabilizing;

sealing the well above the cut on said pipe.

US Pat. No. 9,353,590

DEBRIS CHAMBER WITH HELICAL FLOW PATH FOR ENHANCED SUBTERRANEAN DEBRIS REMOVAL

Baker Hughes Incorporated...

1. A debris removal device for subterranean use operable to remove debris using pumped fluid flow, comprising:
a housing having a lower end inlet tube defining an annular debris collection volume with said housing and an upper end outlet;
said housing having a tubular shape defining an outermost interior wall having a screen material for slowing the rotational
velocity of debris directed toward said screen by said inlet tube after exiting said inlet tube so that the debris in the
fluid flowing toward said outlet will drop into an open top of said debris collection volume;

said inlet tube configured to impart a spin to debris laden flow passing therethrough.

US Pat. No. 9,217,311

FLAPPER VALVE AND METHOD OF VALVING A TUBULAR

Baker Hughes Incorporated...

1. A flapper valve comprising:
a housing;
a seat movably disposed at the housing at least between a first position and a second position;
a flapper movably disposed at the seat at least between a seated position and an unseated position; and
a first biasing member being configured to bias the flapper toward the unseated position and a second biasing member configured
to bias the flapper toward the seated position.

US Pat. No. 9,341,737

MEASURING TOTAL, EPITHERMAL AND THERMAL NEUTRON FORMATION POROSITIES WITH ONE SINGLE SET OF NEUTRON DETECTORS AND A PULSED NEUTRON GENERATOR

BAKER HUGHES INCORPORATED...

1. An apparatus for estimating an epithermal neutron porosity and a thermal neutron porosity of an earth formation, the apparatus
comprising:
a carrier configured to be conveyed through a borehole penetrating an earth formation;
a pulsed neutron generator (PNG) disposed on the carrier and configured to emit a pulse of high energy neutrons during a PNG-on
time interval and to not emit neutrons during a PNG-off time interval that follows the PNG-on time interval;

a short spaced neutron detector disposed on the carrier, spaced a first distance from the pulsed neutron generator, and configured
to detect neutrons to provide a short spaced detector count rate as a function of time;

a long spaced neutron detector disposed on the carrier, spaced a second distance from the pulsed neutron generator that is
greater than the first distance, and configured to detect neutrons to provide a long spaced detector count rate as a function
of time;

a timing gate configured to synchronize a timing of neutrons detected by the short and long spaced detectors with respect
to the pulse of high energy neutrons; and

a processor configured to:
correct the short spaced detector count rate for a first time interval within the PNG-on time interval to provide a short
spaced detector epithermal neutron count rate that decreases count rate due to thermal neutrons;

correct the long spaced detector count rate that is with the first time interval to provide a long spaced detector epithermal
neutron count rate that decreases count rate due to thermal neutrons;

calculate a first ratio of short spaced detector epithermal neutron count rate to long spaced detector epithermal neutron
count rate;

calculate a second ratio of short spaced detector thermal neutron count rate to long spaced detector count rate for a second
time interval that is within the PNG-off time interval;

estimate the epithermal neutron porosity using the first ratio; and
estimate the thermal neutron porosity using the second ratio.

US Pat. No. 9,404,334

DOWNHOLE ELASTOMERIC COMPONENTS INCLUDING BARRIER COATINGS

BAKER HUGHES INCORPORATED...

1. An apparatus for performing a downhole operation, comprising:
a carrier configured to be disposed in a borehole in an earth formation;
a deformable component configured to be disposed in the borehole, the deformable component including an elastomeric material
and a barrier coating disposed on a surface of the elastomeric material, the barrier coating having a hardness that is greater
than a hardness of the elastomeric material, the barrier coating including a first layer of a diamond-like carbon (DLC) material
having properties configured to resist permeation of downhole gases from the borehole into the elastomeric material at downhole
temperatures and pressures and prevent explosive decomposition of the elastomeric material, the properties of the DLC material
including a percentage of sp3 bonds in the DLC material that is at least about seventy percent, the barrier coating including a second layer made from an
inorganic material that is different than the DLC material.

US Pat. No. 9,360,123

VALVE

BAKER HUGHES INCORPORATED...

1. A valve comprising:
a first member having a first port therethrough;
a second member in operable communication with the first member and having a sealing surface thereon on an inner radial surface
of the second member and a second port therethrough, the first member being movable relative to the second member;

a seal sealingly engaged with the first member and slidably sealingly engagable with the second member; and
a support member movably disposed relative to the first member and the second member having a support surface, the support
member being movable with the second member relative to the first member so that upon movement of the second member relative
to the first member the seal is continuously supported by at least one of the sealing surface and the support surface, while
the seal is passing over the second port.

US Pat. No. 9,322,250

SYSTEM FOR GAS HYDRATE PRODUCTION AND METHOD THEREOF

BAKER HUGHES INCORPORATED...

1. A system for gas hydrate production, the system comprising:
a tubular having a plurality of ports, the plurality of ports including:
a first port configured to automatically open at a first differential pressure between an interior of the tubular and a band
of gas hydrate, and to remain closed at differential pressures below the first differential pressure; and,

a second port configured to remain closed at the first differential pressure, and to automatically open at a second differential
pressure between the interior of the tubular and the band of gas hydrate, the second differential pressure greater than the
first differential pressure, the second port located uphole of the first port; and,

a pressure reducing mechanism within the tubular, the pressure reducing mechanism located uphole of the first and second ports,
the pressure reducing mechanism configured to reduce internal pressure within the tubular and across both the first and second
ports;

wherein the second differential pressure to open the second port is achieved via introduction of gas from the band of gas
hydrate through the first port, which lowers the internal pressure within the tubular.

US Pat. No. 9,285,497

POROSITY ESTIMATOR FOR FORMATE BRINE INVADED HYDROCARBON ZONE

BAKER HUGHES INCORPORATED...

1. A method of estimating a property of an earth formation comprising hydrocarbon and non-hydrocarbon components, the method
comprising:
conveying a carrier through a borehole penetrating the earth formation;
performing a nuclear magnetic resonance (NMR) measurement on fluid in the earth formation with an NMR instrument disposed
at the carrier to provide total NMR measurement data that includes a combination of hydrocarbon-resultant NMR measurement
data and non-hydrocarbon-resultant NMR measurement data;

separating the total NMR measurement data into the hydrocarbon-resultant NMR measurement data and the non-hydrocarbon-resultant
NMR measurement data;

scaling a portion of the non-hydrocarbon-resultant NMR measurement data based on a correction factor to obtain scaled non-hydrocarbon-resultant
NMR measurement data; and

estimating the property based on the hydrocarbon-resultant NMR measurement data and the scaled non-hydrocarbon-resultant NMR
measurement data.

US Pat. No. 9,284,803

ONE-WAY FLOWABLE ANCHORING SYSTEM AND METHOD OF TREATING AND PRODUCING A WELL

BAKER HUGHES INCORPORATED...

1. A one-way flowable anchoring system comprising:
a plurality of same anchors being sealedly fixedly engagable within a structure and each of the plurality of same anchors
having a flow bore longitudinally therethrough with a first seat and a second seat on opposing ends thereof; and

a plug positionable within the structure between two of the plurality of same anchors positioned longitudinally adjacent one
another, the plug being sealedly engagable to substantially block flow through the flow bore of a first of the plurality of
same anchors when sealingly engaged with the first seat thereof and the plug being seatingly engagable to allow flow around
the plug and into the flow bore of the second of the plurality of same anchors through an area at least equal to that of the
flow bore when the plug is seated at the second seat thereof.

US Pat. No. 9,282,260

VISUALIZING POLYNUCLEAR AROMATIC HYDROCARBONS WITHIN THE NEAR INFRARED SPECTRUM

Baker Hughes Incorporated...

10. A method comprising:
producing an image of polynuclear aromatic hydrocarbons with an optical microscope by passing a wavelength ranging from about
700 nm to about 2500 nm therethrough; wherein the polynuclear aromatic hydrocarbons are within a compound selected from the
group consisting of coke, coke precursors, naphthalene, perylene, coronene, chrysene, anthracene, and combinations thereof;

capturing the image produced by the microscope with an imaging device, wherein the imaging device is configured to filter
a wavelength of about 700 nm to about 2500 nm therethrough;

distinguishing a number of condensed aromatic rings that share two carbons for each polynuclear aromatic hydrocarbon within
a compound selected from the group consisting of coke, coke precursors, naphthalene, perylene, coronene, chrysene, anthracene,
and combinations thereof; and

wherein a sample comprising the polynuclear aromatic hydrocarbons has been collected from an oilfield fluid selected from
the group consisting of a drilling fluid, completion fluid, production fluid, servicing fluid, crude oil, refinery fluid,
and combinations thereof.

US Pat. No. 9,212,546

APPARATUSES AND METHODS FOR OBTAINING AT-BIT MEASUREMENTS FOR AN EARTH-BORING DRILLING TOOL

Baker Hughes Incorporated...

1. An instrumented cutting element for use on an earth-boring tool, the instrumented cutting element comprising:
a substrate; a diamond table bonded to the substrate;
at least one sensing element disposed at least partially within the diamond table, the at least one sensing element comprising
a doped diamond material wherein the substrate comprises at least one conduit coupled and at least partially aligned with
the at least one sensing element and extending at least substantially through the substrate; and

wherein the at least one conduit comprises an electrical conductor configured to transmit an electrical signal away from the
at least one sensing element.

US Pat. No. 9,404,362

MATERIAL CHARACTERISTIC ESTIMATION USING INTERNAL REFLECTANCE SPECTROSCOPY

BAKER HUGHES INCORPORATED...

1. An apparatus for measuring fluid characteristics, comprising:
a solid transparent body including a plurality of internally reflective surfaces configured to contact a material of interest
and configured to internally reflect an electromagnetic radiation beam, the plurality of reflective surfaces defining a n-sided
base surface having a polygonal shape and having at least three sides, each reflective surface forming a side of the polygonal
shape, the base surface being at least partially perpendicular to the plurality of reflective surfaces, the body including
an opposite surface having the polygonal shape and being at least partially perpendicular to the plurality of reflective surfaces,
the body including an entry area configured to guide the electromagnetic beam into the body and toward the plurality of surfaces,
the body configured to direct the electromagnetic radiation beam along a path within the solid transparent body from the entry
area to an exit area on the solid transparent body, the body and the entry area configured to cause the electromagnetic beam
to undergo only a selected number of reflections from the reflective surfaces until the electromagnetic beam exits the body
via the exit area, wherein the selected number of reflections is less than or equal to a maximum number of reflections, the
maximum number of reflections based on a position of the entry area, a position of the exit area and a number “n” of the sides;

an electromagnetic radiation source coupled to the entry area on the solid transparent body and configured to transmit the
electromagnetic radiation beam into the solid transparent body through the entry area; and

a detector coupled to the exit area on the solid transparent body and configured to receive at least a fraction of the reflected
electromagnetic radiation beam, the detector configured to generate a signal based on the received electromagnetic radiation
beam and transmit the signal to a processor for at least one of analysis of material characteristics and data storage.

US Pat. No. 9,353,026

OIL SOLUBLE HYDROGEN SULFIDE SCAVENGER

Baker Hughes Incorporated...

1. A method for reducing the concentration of hydrogen sulfide in a hydrocarbon comprising: introducing a zinc carboxylate
oxo complex composition into the hydrocarbon; wherein the zinc carboxylate oxo complex is the reaction product from reacting
particulate zinc oxide with a mixture of two or more carboxylic acids; wherein the zinc carboxylate oxo complex composition
is soluble in hydrocarbons; and wherein none of the acids is octanoic acid or an octanoic isomer.

US Pat. No. 9,273,526

DOWNHOLE ANCHORING SYSTEMS AND METHODS OF USING SAME

Baker Hughes Incorporated...

1. An anchoring system for wellbores, the anchoring system comprising:
a tubular member having a first end, a second end, a longitudinal axis, an outer wall surface, a bore, a first slip member,
and a second slip member, the first and second slip members being movable radially outward from the axis of the tubular member
from a run-in position to a set position, wherein the tubular member comprises a collet and each of the first and second slip
members are disposed on separate collet fingers,

wherein the first slip member comprises a first projection at an upper end of the first slip member, the first projection
extending over a first portion of an upper end of the second slip member when the first and second slip members are in their
respective run-in positions and, the first projection extending over a second portion of the upper end of the second slip
member when the first and second slip members are in their respective set positions,

wherein the second slip member includes a detent disposed on the upper end of the second slip member, the detent being in
sliding engagement with the first projection of the first slip member when the first and second slip members are in their
respective run-in positions, and

wherein the detent is disposed in alignment with a center point of the upper end of the second slip member.

US Pat. No. 9,470,078

FLUID DIVERSION THROUGH SELECTIVE FRACTURE EXTENSION

BAKER HUGHES INCORPORATED...

1. A method of re-fracturing a horizontal wellbore comprising:
extending a tubing string into a horizontal wellbore from a surface location;
positioning an end of the tubing string adjacent a first location within the horizontal wellbore, the first location having
been previously hydraulically fractured at least once to form a fracture that extends into a subterranean formation at the
first location prior to extending the tubing string into the horizontal wellbore, the tubing string extending from the surface
location to the first location;

providing a first fluid in an annulus between the tubing string and the horizontal wellbore, wherein a portion of the horizontal
wellbore beyond an end of the tubing string includes the first fluid;

providing a second fluid within the tubing string, wherein the second fluid differs from the first fluid;
sealing the annulus adjacent to the surface location; and
pumping the second fluid down the tubing string to initiate a re-fracture of the fracture that extends into the subterranean
formation at the first location while the annulus is sealed adjacent to the surface location.

US Pat. No. 9,359,887

RECOVERABLE DATA ACQUISITION SYSTEM AND METHOD OF SENSING AT LEAST ONE PARAMETER OF A SUBTERRANEAN BORE

BAKER HUGHES INCORPORATED...

1. A recoverable data acquisition system comprising at least a portion of at least one sensor positionable within a tubular
of a completion system and being recoverable therefrom separately from the tubular, a retainer movably disposed at the tubular
between at least a first position and a second position, a cavity being defined between the tubular and the retainer when
the retainer is in the first position, the at least a portion of the at least one sensor being removable from the cavity in
response to movement of the retainer from the first position to the second position.

US Pat. No. 9,223,047

FORMATION RESISTIVITY MEASUREMENTS USING PHASE CONTROLLED CURRENTS

Baker Hughes Incorporated...

1. An apparatus for estimating a property of an earth formation penetrated by a borehole, the apparatus comprising:
a carrier configured to be conveyed through the borehole;
a first transmitter electrode disposed at the carrier and configured to inject electrical current into the earth formation;
a first measurement electrode disposed at the carrier and configured to receive electrical current from the formation for
measurement due to the current injection in order to estimate the property of the earth formation;

a first measurement sensor coupled to the first measurement electrode and configured to measure electrical current amplitude
and phase of the electrical current received by the first measurement electrode;

a controller coupled to the first measurement sensor and configured to determine a phase difference between injected electrical
current and received electrical current and to estimate the property using measured electrical current that is in-phase with
the injected electrical current; and
a first bucker amplifier coupled to the first measurement electrode and configured to inject an electrical current into the
first measurement electrode based on the determined phase difference to create zero phase difference between the electrical
current injected at the first transmitter electrode and the electrical current received by the first measurement electrode
in accordance with a control algorithm implemented by the controller, wherein the control algorithm determines if a phase
difference exists between the measured current and the transmitted current and determines the magnitude and sign of the phase
difference if the phase difference is non-zero.

US Pat. No. 9,158,504

METHOD AND SYSTEM TO AUTOMATICALLY GENERATE USE CASE SEQUENCE DIAGRAMS AND CLASS DIAGRAMS

Baker Hughes Incorporated...

1. A computer-executed method of automatically generating a sequence diagram from Class-Responsibility-Collaborator (CRC)
information, the CRC information identifying objects, responsibility information for each object, and collaborator information
for each object, and the CRC information for each object being stored in a form of a CRC card corresponding to the object,
the method comprising:
storing, in a storage device, the objects and corresponding class types of the objects according to the CRC information indicated
on the CRC card corresponding to each of the objects;

associating, by a processor, each of the objects with one or more other objects according to the collaborator information
of the CRC information indicated on the CRC card corresponding to each of the objects;

determining, by the processor, messages from each of the objects to associated objects according to the responsibility information
and the collaborator information indicated on the CRC card corresponding to each of the objects;

and the processor automatically generating the sequence diagram including the objects and the messages among the objects based
on the objects and the messages.

US Pat. No. 9,303,150

REINFORCED AND CROSSLINKED POLYARYLENES, METHODS OF MANUFACTURE, AND USES THEREOF

BAKER HUGHES INCORPORATED...

1. A composition comprising:
a polymer component comprising a crosslinked product of a polyarylene of formula (1)

a crosslinked product of a polyphenylene sulfide and a polyphenylsulfone, or a combination comprising at least one of the
foregoing crosslinked product; and

a mesoporous silicate having an average pore size of about 5 nanometers to about 50 nanometers;
wherein in formula (1) each Ar is the same or different, and is independently a C6-C32 aromatic group having only carbon atoms
in the ring,

R is a substituent on the aromatic group wherein each R is the same or different, and each R is independently a C1-C20 hydrocarbyl
group, C1-C20 hydrocarbyloxy group, C1-C20 hydrocarbylthio group, trialkylsilyl group, halogen, nitro group, cyano group,
hydroxyl group, mercapto group, hydrocarbyl carbonyl group, formyl group, C1-C20 dihydrocarbyl ether group, carboxylic acid
group or a salt thereof, carboxylic ester group, primary, secondary or tertiary amino group, primary or secondary aminocarbonyl
group, phosphonic acid group or a salt thereof, sulfonic acid group or a salt thereof, polyalkyleneoxy group, or polyphenyleneoxy
group,

b is an integer from 0-10, provided that the valence of Ar is not exceeded;
x and y are the same or different, and either x or y can be zero, provided that x+y is greater than about 10,
wherein the composition is free of a metal.
US Pat. No. 9,260,647

METALLIC PARTICLE MEDIATED VISCOSITY REDUCTION OF VISCOELASTIC SURFACTANTS

Baker Hughes Incorporated...

1. A method for breaking the viscosity of an aqueous fluid gelled with a viscoelastic surfactant (VES), comprising:
providing an aqueous fluid that is a brine comprising KCl, NaCl, CaCl2, or CaBr2;

adding to the aqueous fluid, in any order:
at least one VES comprising a non-ionic surfactant, cationic surfactant, amphoteric surfactant or zwitterionic surfactant,
or a combination thereof, in an amount sufficient to form a gelled aqueous fluid comprising a plurality of elongated micelles
and having a viscosity, and

a plurality of metallic particles to produce a mixture comprising dispersed metallic particles dispersed within the gelled
aqueous fluid, the metallic particles comprising coated metallic particles that comprise metallic particle cores of a transition
metal selected from Group VA, VIA, VIIA, VIIIA, IB, IIB, IIIB or IVB of the Periodic Table, or an alloy thereof, or a combination
thereof that are configured for dissolution in the aqueous fluid to provide a source of at least one transition metal ion
and metal coating layers that are configured to selectively control access of the aqueous fluid to the particle core; and

selectively controllable dissolution of the metallic particles in the gelled aqueous fluid to provide the at least one transition
metal ion in an amount effective to reduce the viscosity.

US Pat. No. 9,255,463

FLAPPER EQUALIZER WITH INTEGRAL SPRING

Baker Hughes Incorporated...

1. A subsurface safety valve for subterranean use, comprising:
a housing having a passage therethrough;
a closure selectively movable with respect to a seat that surrounds said passage;
an actuator member in said passage to selectively move said closure with respect to said seat;
said closure having a bore that communicates opposed sides of said closure and further comprising a valve member having a
longitudinal axis and slidably mounted in said bore, said valve member and a biasing component that creates a force from being
compressed, said valve member and said biasing component integrally fastened to each other and said valve member and said
biasing component disposed in axial alignment with each other and substantially in said bore to bias said valve member from
said closure to a bore obstructed position.

US Pat. No. 9,284,789

METHODS FOR FORMING EARTH-BORING TOOLS HAVING CUTTING ELEMENTS MOUNTED IN CUTTING ELEMENT POCKETS AND TOOLS FORMED BY SUCH METHODS

Baker Hughes Incorporated...

1. A method of forming an earth-boring tool, the method comprising:
forming a hardfacing layer over at least one surface of a body;
using a plasma spray device to gouge at least one recess through the hardfacing layer and into the body using a plasma emitted
by the plasma spray device, at least a portion of the at least one recess defining a cutting element pocket;

machining an interior surface of the at least one recess after using the plasma spray device to gouge the at least one recess;
and

securing at least one cutting element to the body at least partially within the cutting element pocket.

US Pat. No. 9,404,360

FIBER OPTIC SENSOR SYSTEM USING WHITE LIGHT INTERFEROMETRY

BAKER HUGHES INCORPORATED...

1. A downhole fiber optic apparatus for acquiring downhole information comprising:
a carrier conveyable in a borehole;
a downhole sample tool configured to obtain a sample downhole;
an electromagnetic energy generator housed in the carrier for conveyance of the electromagnetic energy generator in the borehole;
a Fabry-Perot interferometer comprising an optical fiber that receives electromagnetic energy emitted from the electromagnetic
energy generator and generates an optical output signal representative of the downhole information relating to the sample,
the Fabry-Perot interferometer sensing one or more of a pressure, a temperature, a refractive index and a strain, wherein
the Fabry-Perot interferometer comprises an optical cavity having an optical cavity length that changes in response to the
one or more of the pressure, the temperature, the refractive index and the strain being sensed; and

a photodetector configured to receive the optical output signal to read the optical cavity length to generate an electrical
output signal representative of the downhole information relating to the sample.

US Pat. No. 9,273,545

USE OF LAMB AND SH ATTENUATIONS TO ESTIMATE CEMENT VP AND VS IN CASED BOREHOLE

Baker Hughes Incorporated...

1. A method of determining properties of a bonding material disposed outside of a casing in a borehole, comprising:
inducing an SH wave in the casing;
measuring attenuation of the SH wave;
determining the shear velocity or the shear impedance of the bonding material based on the measured attenuation of the SH
wave;

inducing a Lamb wave in the casing;
measuring attenuation of the Lamb wave;
generating at least one Lamb attenuation curve that has a value that satisfies the measured attenuation of the Lamb wave;
and

determining the compressional velocity or the compressional impedance of the bonding material based on the at least one generated
Lamb attenuation curve and the measured attenuation of the Lamb wave.

US Pat. No. 9,227,243

METHOD OF MAKING A POWDER METAL COMPACT

Baker Hughes Incorporated...

1. A method of making a selectively corrodible article, comprising:
forming a powder comprising a plurality of metallic powder particles, each metallic powder particle comprising a nanoscale
metallic coating layer disposed on a particle core, the metallic coating layer having a substantially uniform thickness of
25 to 2500 nm; and

forming a powder compact of the powder particles by deforming the powder particles such that they are substantially elongated
in a predetermined direction to form substantially elongated powder particles and the coating layers form a substantially
elongated cellular nanomatrix, the powder compact comprising an article that is selectively corrodible in response to a change
in a predetermined wellbore fluid, the powder compact having an ultimate compressive strength or corrosion rate in the predetermined
wellbore fluid that is greater than a powder compact of the metallic particles that comprises a cellular nanomatrix that is
not substantially elongated.

US Pat. No. 9,255,822

SPLICABLE FIBER OPTIC SENSING SYSTEM, METHOD OF MAKING SAME AND TAPE FOR SENSE TRANSMISSIVELY LOCKING AN OPTICAL FIBER

Baker Hughes Incorporated...

1. A splicable fiber optic sensing system comprising:
a core;
a sheath surrounding the core;
an adhesive disposed between the core and the sheath at some locations and not at other locations; and
at least one optical fiber disposed between the core and the sheath being sense transmissively locked to the core by the adhesive
at the locations containing the adhesive.

US Pat. No. 9,394,396

HYDROGEN SULFIDE SCAVENGER FOR USE IN HYDROCARBONS

Baker Hughes Incorporated...

1. A hydrogen sulfide scavenger comprising a reaction product of glyoxal and a polyamine selected from the group consisting
of triethylene tetramine (TETA), tetraethylene pentamine (TEPA), cyclohexane diamine, butane diamine, and combinations thereof.

US Pat. No. 9,316,075

HIGH PRESSURE LOCK ASSEMBLY

BAKER HUGHES INCORPORATED...

12. A method of locking radially adjacent components, comprising:
positioning a lock assembly with respect to a radially adjacent structure, the lock assembly comprising a plurality of dogs,
an extender body, and a mandrel, each of the dogs having a loading bearing surface;

transitioning the plurality of dogs between a retracted configuration and an extended configuration with the extender body;
engaging the plurality of dogs with at least one shoulder in the radially adjacent structure;
radially dimensionally overlapping a first interconnection feature including a first extension having a radial thickness and
a first flange having a greater radial thickness than the radial thickness of the extension of each of the dogs with a second
interconnection feature of the mandrel having a second extension and a second flange that are complementary to the first interconnection
feature first extension and first flange such that the first flange of the first interconnection feature nests with the second
extension of the second interconnection feature;

supporting the lock assembly at the radially adjacent structure with the load bearing surfaces of the dogs against the shoulder;
supporting the mandrel with the dogs at an engagement between the first and second interconnection features.

US Pat. No. 9,097,097

METHOD OF DETERMINATION OF FRACTURE EXTENT

Baker Hughes Incorporated...

1. A fracture mapping method, comprising:
non-electrically generating at least one electromagnetic signal in subterranean fractures;
sensing said signal;
determining the extent of said fractures with said signal.

US Pat. No. 9,057,247

MEASUREMENT OF DOWNHOLE COMPONENT STRESS AND SURFACE CONDITIONS

Baker Hughes Incorporated...

1. An apparatus for measuring strain on a downhole component, comprising:
at least one strain gauge deposited on a surface of the downhole component of a downhole drilling assembly or disposed within
a material forming the downhole component, the strain gauge including a plurality of conductive traces connected in parallel;
and

a processor in operable communication with the at least one strain gauge, the processor configured to detect changes in the
at least one strain gauge in response to conditions of the surface of the downhole component, the conditions of the surface
including the formation of a crack or surface discontinuity, the processor configured to estimate the formation and extent
of the crack or the surface discontinuity based on a number of conductive traces disrupted by the crack or the surface discontinuity.

US Pat. No. 9,085,946

METHODS OF FORMING POLYCRYSTALLINE COMPACTS HAVING MATERIAL DISPOSED IN INTERSTITIAL SPACES THEREIN, CUTTING ELEMENTS AND EARTH-BORING TOOLS INCLUDING SUCH COMPACTS

Baker Hughes Incorporated...

1. A method of forming a polycrystalline compact, comprising:
preparing a plurality of nanoparticles of hard material for a sintering process, comprising:
selecting a coating material comprising at least one of a boride, a carbide, a nitride, a metal carbonate, a metal bicarbonate,
and a non-catalytic metal; and

at least partially coating each nanoparticle of the plurality of nanoparticles with the coating material forming a plurality
of coated nanoparticles of hard material prior to sintering the plurality of nanoparticles of hard material; and

sintering the plurality of coated nanoparticles of hard material to form a polycrystalline hard material comprising a plurality
of hard material grains formed from the plurality of nanoparticles, the plurality of hard material grains being interspersed
and interbonded to form the polycrystalline hard material, the coating material forming an interstitial material disposed
in at least some interstitial spaces between the plurality of hard material grains formed from the plurality of nanoparticles
of hard material.

US Pat. No. 9,297,921

DTEM WITH SHORT SPACING FOR DEEP, AHEAD OF THE DRILL BIT MEASUREMENTS

BAKER HUGHES INCORPORATED...

1. An apparatus for evaluating an earth formation comprising:
a carrier configured to be conveyed in a borehole;
a transmitter on the carrier configured to produce a transient electromagnetic field in the earth formation;
a receiver on the carrier positioned at a first distance from the transmitter configured to produce a first transient signal
responsive to an interaction of the electromagnetic field with the earth formation, the first signal being affected by a resistivity
interface at a second distance at least five times the first distance from the transmitter; and

a processor configured to estimate a value of the second distance using the first transient signal, wherein estimating the
value of the second distance comprises modeling the earth formation by replacing the earth formation with a thin conductive
sheet having a depth that changes over time.

US Pat. No. 9,272,337

SYSTEM AND METHOD FOR FORMING A BORE IN A WORKPIECE

Baker Hughes Incorporated...

1. A method of controlling a rotating drill in a bore in a workpiece comprising:
a. contacting a drill head of the drill with the workpiece to form a bore in the workpiece;
b. monitoring an azimuthal orientation of the drill head in the workpiece by measuring a signal from the drill head in the
bore with an acoustic sensor that is disposed adjacent an outer surface of the workpiece and that is set radially back from
the bore; and

c. adjusting an operating parameter of the drill based on the step of monitoring the azimuthal orientation.

US Pat. No. 9,732,583

COMPLETION SYSTEMS WITH FLOW RESTRICTORS

BAKER HUGHES INCORPORATED...

1. A method of completing a wellbore, comprising:
placing a lower completion assembly that includes a flow device that provides fluid communication between the lower completion
assembly and a production zone surrounding the lower completion assembly;

placing an isolation assembly with a packer above the lower completion assembly for isolating an annulus between the lower
completion assembly and the wellbore;

placing a flow restriction device above the packer, wherein the flow restriction device includes a mandrel and an expandable
element around an outside of the mandrel;

setting the flow restriction device in the annulus to restrict flow of fluid through the annulus via at least one of a fluid
passage of the flow restriction device and a gap of the flow restriction device, at a selected restricted rate; and

setting the packer after setting the flow restriction device.

US Pat. No. 9,458,685

APPARATUS AND METHOD FOR CONTROLLING A COMPLETION OPERATION

BAKER HUGHES INCORPORATED...

1. A method of delivering a material to a downhole location in a formation, comprising:
operating a force application device at a surface location to apply a force at the surface location to a tool string extending
from the surface location to the downhole location, wherein the applied force produces an action at an assembly at the downhole
location during a frac operation or a completion operation;

measuring the force applied to the tool string by the force application device using a sensor located at the assembly at the
downhole location;

using the measurement of the applied force to alter the force applied by the force application device, and
using a pump to deliver material through the tool string to the formation.

US Pat. No. 9,290,997

DOWNHOLE TOOLS INCLUDING BEARINGS AND METHODS OF FORMING SAME

Baker Hughes Incorporated...

1. A downhole tool, comprising:
a body;
a first bearing member fixed to the body, the first bearing member comprising an outer contact surface defining an outer diameter;
a second bearing member rotatable about the first bearing member, the second bearing member comprising an inner contact surface
defining an inner diameter, the inner diameter of the second bearing member being larger than the outer diameter of the first
bearing member and the inner contact surface of the second bearing member being in sliding contact with the outer contact
surface of the first bearing member at an interface;

wherein the first bearing member comprises a channel formed in the outer contact surface of the first bearing member, the
channel comprising a notch defining a flat surface interrupting an otherwise circular cross-sectional shape of the outer contact
surface;

a third bearing member fixed to the body, the third bearing member comprising a lower contact surface; and
a fourth bearing member rotatable with respect to the third bearing member, the fourth bearing member comprising an upper
contact surface, wherein the third bearing member abuts against the fourth bearing member at in interface between the lower
contact surface and the upper contact surface, the third and fourth bearing members being configured to rotate slidably relative
to one another,

wherein at least one of the third and fourth bearing members comprises at least one channel extending, and configured to provide
a fluid pathway across, at least one of the third and fourth bearing members.

US Pat. No. 9,217,295

CUTTING INSERTS, CONES, EARTH-BORING TOOLS HAVING GRADING FEATURES, AND RELATED METHODS

Baker Hughes Incorporated...

6. A method of forming a cutting element for an earth-boring tool, comprising:
forming a plurality of grading features in or on a cutting element comprising:
forming a first material volume using a first powdered material;
forming at least one second material volume using a second powdered material visually distinct from the first powdered material;
forming a green body comprising the first material volume and the at least one second material volume; and
sintering the green body to form a cutting element; and
locating at least one of the plurality of grading features on an initial working surface of the cutting element.

US Pat. No. 9,213,121

ACOUSTIC SENSING SYSTEM FOR DETERMINING AN INTERFACE BETWEEN TWO MATERIALS

Baker Hughes Incorporated...

1. A system for locating an interface between a first material and a second material, comprising:
a plurality of acoustic sensing elements operatively arranged to measure a characteristic of one or more acoustic signals
at a plurality of locations along a length of the plurality of acoustic sensing elements; and

an instrumentation unit coupled with the plurality of acoustic sensing elements, the instrumentation unit operatively arranged
to determine a difference in acoustic coupling at specific locations in the plurality of acoustic sensing elements between
a first value of the characteristic measured at a first location of the plurality of locations and a second value of the characteristic
measured at a second location of the plurality of locations for identifying the interface between the first material and the
second material as being located between the first and second locations if the difference is greater than a preselected threshold
amount.

US Pat. No. 9,080,418

DIRTY FLUID VALVE WITH CHEVRON SEAL

BAKER HUGHES INCORPORATED...

1. An apparatus for controlling a fluid flow in a borehole, the apparatus comprising: a tool body configured to retrieve a
fluid sample from a subsurface formation, the tool body having a fluid conduit having an inlet for receiving the fluid sample
and an outlet for conveying the fluid sample to a selected location; a mandrel selectively blocking flow along the fluid conduit,
the mandrel having a reduced exterior diameter portion; and a seal disposed on the mandrel, the seal including at least one
chevron seal element: the seal and the mandrel having: (i) a first position wherein fluid flow is blocked between the seal
and the mandrel; and (ii) a second position wherein a fluid flows between the seal and the mandrel and along the reduced diameter
portion configured to cooperate with the mandrel to selectively block flow across the fluid conduit.
US Pat. No. 9,068,128

METHOD FOR REDUCING HYDROGEN SULFIDE EVOLUTION FROM ASPHALT AND HEAVY FUEL OILS

Baker Hughes Incorporated...

1. A method for reducing hydrogen sulfide emissions from heavy fuel oil or an asphalt composition comprising admixing an additive
with heavy fuel oil or an asphalt composition wherein the additive comprises nano-particles of a zinc component and nano-particles
of a non-zinc component; wherein the additive comprises a solvent selected from the group consisting of alcohols, glycols,
and combinations thereof; wherein the zinc component is selected from the group consisting of zinc carbonate, zinc oxide,
zinc sulfide, zinc boroacylate, and combinations thereof; and a non-zinc metal component selected from the group consisting
of non-zinc metal carbonate, non-zinc metal oxide, non-zinc metal sulfide, non-zinc metal boroacylate, and combinations thereof;
wherein the non-zinc metal is selected from the group of consisting of Fe, Mn, Co, Ni, Cr, Zr, Mo, Bi, and combinations thereof;
and wherein all of the nano-particles are from 5 to about 300 nm; wherein the non-zinc metal component of the additive is
present at from about 1 to about 50 molar % and is substantially as effective at reducing hydrogen sulfide as an additive
containing Zn exclusively; and wherein the additive is present at a concentration sufficient to introduce from about 20 to
2500 ppm by weight metal oxide, sulfide, boroacylate, or carbonate into the asphalt or fuel oil.

US Pat. No. 9,068,429

DISSOLVABLE TOOL AND METHOD OF DISSOLVING SAME

Baker Hughes Incorporated...

1. A dissolvable tool comprising:
a body having at least a portion configured to dissolve in a fluid; and
at least one barrier connected to the body configured to slidably fluidically seal to a structure that the body and the at
least one barrier are movable within to maintain a volume of the fluid between the at least one barrier and the body and thereby
maintain exposure between the fluid and the at least a portion of the body configure to dissolve in the fluid while the at
least one barrier and the body are moved through the structure.

US Pat. No. 9,283,619

POLARIZABLE NANOPARTICLES COMPRISING COATED METAL NANOPARTICLES AND ELECTRORHEOLOGICAL FLUID COMPRISING SAME

BAKER HUGHES INCORPORATED...

1. A nanoparticle composition comprising:
a metal nanoparticle, and
a continuous dielectric coating on a surface of the metal nanoparticle, wherein the dielectric coating is a carbonaceous coating,
metal nitride coating, metal carbide coating, or a combination comprising at least one of the foregoing coatings,

the nanoparticle composition being a dielectric material,
wherein the nanoparticle composition further comprises an additional nanoparticle, the additional nanoparticle comprising
derivatized graphene, derivatized graphene fiber, derivatized nanotube, derivatized fullerene, derivatized graphite, derivatized
carbon black, derivatized or underivatized nanoclay, a derivatized or underivatized inorganic nanoparticle, or a combination
comprising at least one of the foregoing, wherein the inorganic nanoparticle is selected from a metal or metalloid carbide,
a metal or metalloid nitride, and a metal or metalloid oxide.

US Pat. No. 9,127,508

APPARATUS AND METHODS UTILIZING PROGRESSIVE CAVITY MOTORS AND PUMPS WITH INDEPENDENT STAGES

Baker Hughes Incorporated...

1. An apparatus for use in a wellbore, comprising:
a plurality of serially coupled power sections, wherein each power section includes a rotor disposed in a stator; and
a coupling device configured to couple stators of adjoining power sections, wherein the coupling device includes a first end
fastened to an outside of the stator of a first of the adjoining power sections and a second end fastened to an outside of
the stator of a second of the adjoining power sections to provide a lateral support to the rotors of the adjoining power sections.

US Pat. No. 9,102,860

METHOD OF INHIBITING OR CONTROLLING RELEASE OF WELL TREATMENT AGENT

Baker Hughes Incorporated...

1. A method of inhibiting or controlling release of a well treatment agent in a well, a subterranean formation, a flow conduit
or a vessel by introducing into the well, subterranean formation, flow conduit or vessel the well treatment agent in a water-in-oil
microemulsion, wherein (a) the water-in-oil microemulsion provides for continuous release of the well treatment agent over
a sustained period of time of at least six months; (b) the oil phase of the water-in-oil microemulsion is a solvent-surfactant
blend; and (c) the amount of surfactant in the blend is from about 35 to about 80% by volume.

US Pat. No. 9,062,540

MISALIGNMENT COMPENSATION FOR DEEP READING AZIMUTHAL PROPAGATION RESISTIVITY

BAKER HUGHES INCORPORATED...

1. A method of conducting logging operations in a borehole penetrating an earth formation, comprising:
estimating alignment information indicative of an angular shift between at least one oriented transmitter on a bottom hole
assembly (BHA) and at least one oriented receiver on the BHA using measurements of deformation of the BHA from at least one
deformation sensor;

using the alignment information to compensate for effects of misalignment between the at least one oriented transmitter and
the at least one oriented receiver on signals generated by the at least one oriented receiver in response to energy generated
by the at least one oriented transmitter, the compensation comprising applying a compensation algorithm to the signals generated
by the at least one oriented receiver; and

estimating at least one parameter of interest of the earth formation using the compensation, wherein the at least one deformation
sensor includes at least one of: (i) a strain gauge, (ii) a transmitter oriented at a non-X, non-Z angle, (iii) a receiver
oriented at a non-X, non-Z angle, (iv) a magnetometer, (v) an accelerometer, (vi) a distance sensor, (vii) an optical sensor,
and (viii) an optical fiber sensor.

US Pat. No. 9,885,219

NON-RELEASING ANCHOR TOOL WHEN JARRING UP ON A STUCK SUBTERRANEAN TOOL COMPONENT

Baker Hughes, a GE compan...

1. A grip tool for jarring free a component of a subterranean tool, comprising:
a mandrel;
a gripping assembly mounted to said mandrel, said gripping assembly in a retracted position for insertion into the component
of the subterranean tool and an extended position against the component when jarring on said mandrel;

said mandrel retains a grip on the component when jarred in the direction out of the component and said mandrel releases said
component when jarred in the direction into the component allowing said mandrel and the entire gripping assembly to be removed
from the component.

US Pat. No. 9,394,782

APPARATUSES AND METHODS FOR AT-BIT RESISTIVITY MEASUREMENTS FOR AN EARTH-BORING DRILLING TOOL

Baker Hughes Incorporated...

1. An earth-boring drilling tool, comprising:
a bit body having at least one blade formed thereon; and
a cutting element at least partially disposed within a pocket of the at least one blade of the bit body, the cutting element
comprising:

a cutting element body having a cutting surface thereon; and
at least one sensor disposed within the cutting element body and having at least one exposed surface, the at least one exposed
surface being recessed relative to at least a portion of the cutting surface of the cutting element, the at least one sensor
oriented and configured to sense resistivity of one of a contacting formation and the cutting element.

US Pat. No. 9,366,133

ACOUSTIC STANDOFF AND MUD VELOCITY USING A STEPPED TRANSMITTER

BAKER HUGHES INCORPORATED...

1. A method of determining an acoustic property of a fluid in a wellbore, comprising:
placing a faceplate in the wellbore with a stepped surface of the faceplate in contact with the fluid, wherein the stepped
surface includes a non-stepped face and a stepped face;

transmitting an acoustic pulse through the faceplate into the fluid, wherein a first portion of the acoustic pulse passes
from the faceplate into the fluid via the non-stepped face and a second portion of the acoustic pulse passes from the faceplate
into the fluid via the stepped face;

receiving a first reflected acoustic pulse related to the first portion of the acoustic pulse from a wellbore surface and
a second reflected acoustic pulse related to the second portion of the acoustic pulse from the wellbore surface;

obtaining a measurement of the first reflected acoustic pulse and a measurement of the second reflected pulse; and
determining from the obtained measurements the acoustic property of the fluid in the wellbore.

US Pat. No. 9,341,739

APPARATUS AND METHOD FOR ESTIMATING GEOLOGIC BOUNDARIES

BAKER HUGHES INCORPORATED...

1. A method of estimating a geology of an earth formation, the method comprising:
receiving gravity measurements from each of a plurality of gravity sensors nsj arrayed along a length of a borehole in an earth formation, each of the plurality of sensors nsj generating a gravity measurement gj at a sensor location zsj, each of the plurality of sensors separated by a distance h in a direction extending along the length of the borehole;

generating, by a processor in operable communication with the plurality of sensors nsj, a model of the earth formation that includes approximate geological boundaries Nm having an approximate depth zmk, the geological boundaries defining a number of geologic layers therebetween;

defining, by the processor, a geological boundary as being represented by a change in density that is at least a minimum density
change and defining each of the geologic layers as having a thickness that encompasses two or more of the plurality of sensors
nsj;

determining a density change between adjacent sensors, comparing the density change to the minimum density change, and identifying
a geologic boundary z between the adjacent sensors based on the density change being greater than or equal to the minimum
density change, and

estimating by the processor a location and a density change ?? of the geologic boundary z between sensor locations zsj and zsj+1 based on the gravity measurements gj received from the plurality of sensors and the distance h, wherein estimating includes estimating the location of the geologic
boundary based on the equation:

wherein Gj is a second difference of a sequence of the gravity measurements gj, and is represented by the equation:

US Pat. No. 9,249,516

APPLICATION OF OXYGEN SCAVENGERS TO GLYCOL SYSTEMS

BAKER HUGHES INCORPORATED...

1. A method to reduce oxygen-induced corrosion in an aqueous system comprising:
contacting the aqueous system comprising water, oxygen and a glycol with an effective amount of an oxygen scavenger composition
to reduce oxygen-induced corrosion therein, the oxygen scavenger composition comprising:

at least one sulfite compound selected from the group consisting of sodium sulfite, sodium bisulfite, ammonium sulfite, ammonium
bisulfite, sodium meta-bisulfite, potassium sulfite, potassium bisulfite, potassium meta-bisulfite, calcium sulfite, calcium
hydrogen sulfite, and combinations thereof,

at least one transition metal salt selected from the group consisting of chloride salts, sulfate salts and combinations thereof,
where the transition metal salt comprises a transition metal ion selected from the group consisting of nickel, cobalt, manganese
and combinations thereof, and

at least one stabilizer selected from the group consisting of citric acid, ethylenediaminetetracetic acid, glycolic acid,
acetic acid, ethylene diamine, N,N-diethylethylenediamine, diethylene triamine, and salts of these stabilizers, and combinations
of these stabilizers and salts thereof; and

reducing oxygen-induced corrosion in the aqueous system by scavenging oxygen with the oxygen scavenger composition.

US Pat. No. 9,243,486

APPARATUS AND METHOD FOR DETERMINING CLOSURE PRESSURE FROM FLOWBACK MEASUREMENTS OF A FRACTURED FORMATION

Baker Hughes Incorporated...

1. An apparatus for determining closure pressure of a formation surrounding a wellbore, comprising:
an isolation device for isolating a section of the wellbore;
a fluid supply unit for supplying a fluid under pressure into the isolated section of the wellbore to cause a fracture in
the formation proximate the isolated section; and

a receiving unit for receiving fluid from the isolated section due to pressure difference between the formation and the receiving
unit, wherein the receiving unit includes a constant or substantially constant flow control device that controls the rate
of flow of the fluid into the receiving unit.

US Pat. No. 9,145,736

TILTED BIT ROTARY STEERABLE DRILLING SYSTEM

BAKER HUGHES INCORPORATED...

12. A method for forming a wellbore in a subterranean formation, comprising:
disposing a joint inside a drill bit body, the joint being positioned on an end portion of a shaft;
connecting the shaft to a housing positioned on a drill string, wherein the shaft traverses a circumferential gap separating
the housing and the drill bit body, and wherein the joint is positioned between the circumferential gap and the bit face of
the drill bit body;

forming the wellbore using the drill string; and
controlling a drilling direction of the bit face by tilting the drill bit body about the end portion by applying a tilting
force generated by at least one actuator.

US Pat. No. 9,422,806

DOWNHOLE MONITORING USING MAGNETOSTRICTIVE PROBE

BAKER HUGHES INCORPORATED...

1. A method of controlling a downhole operation, comprising:
controlling a tool to perform the downhole operation at a selected downhole location using a first value of an operation parameter
of the tool, wherein a magnetostrictive probe extends along a section of the tool for determining a temperature profile along
the section of the tool related to the operation being performed using the first value of the operation parameter; and

using a processor to:
activate a transducer at a first location of the magnetostrictive probe to generate an ultrasonic pulse at the first location,
receive a signal from the transducer related to a reflection of the generated ultrasonic pulse from a first notch at a second
location of the magnetostrictive probe,

determine a travel time of the ultrasonic pulse between the first location and the second location,
determine a temperature at the second location from the determined travel time and a reference travel time for an ultrasonic
pulse between the first location and the second location at a known reference temperature,

determine, from the temperature at the second location, a temperature profile along the section of the tool;
compare the temperature profile to a selected threshold, and
alter the operation parameter to a second value based on the comparison of the temperature profile to the selected threshold.

US Pat. No. 9,366,124

SYSTEM AND METHOD FOR RE-FRACTURING MULTIZONE HORIZONTAL WELLBORES

Baker Hughes Incorporated...

1. A method for re-fracturing a location of a formation of a multizone horizontal wellbore, the method comprising:
positioning a coiled tubing string within a casing of a multizone horizontal wellbore;
hydraulically isolating a first location from a portion of the multizone horizontal wellbore uphole from the first location,
the first location having been previously hydraulically fractured at least once, wherein hydraulically isolating the first
location comprises creating a seal with a packing element connected to the coiled tubing string to seal an annulus between
the coiled tubing string and the casing of the multizone horizontal wellbore uphole of the first location;

hydraulically re-fracturing the first location by pumping fluid down the coiled tubing string while the packing element seals
the annulus;

providing a first diverting material proximate to the first location after the first location has been hydraulically re-fractured
while the coiled tubing string remains positioned within the casing, wherein the first diverting material hydraulically isolates
the re-fractured first location from the multizone horizontal wellbore uphole of the first location;

hydraulically isolating a second location from a portion of the multizone horizontal wellbore uphole of the second location,
the second location having been previously hydraulically fractured at least once, wherein hydraulically isolating the second
location comprises creating a seal with the packing element connected to the coiled tubing string to seal the annulus between
the coiled tubing string and the casing of the multizone horizontal wellbore uphole of the second location;

hydraulically re-fracturing the second location by pumping fluid down the coiled tubing string while the packing element seals
the annulus; and

providing a second diverting material proximate to the second location after the second location has been re-fractured while
the coiled tubing string remains positioned within the casing, wherein the second diverting material hydraulically isolates
the re-fractured second location from a portion of the multizone horizontal wellbore uphole of the second location.

US Pat. No. 9,200,219

STRONG BASE AMINES TO MINIMIZE CORROSION IN SYSTEMS PRONE TO FORM CORROSIVE SALTS

BAKER HUGHES INCORPORATED...

1. A treated hydrocarbon stream having reduced corrosion capability comprising:
at least one hydrocarbon,
water,
at least one mineral acid,
a composition comprising at least one amine having a pKa between 10.5 to 12, where the amine does not contain oxygen and has
a normal boiling point greater than 95° C.; and

at least one amine salt that is less corrosive as compared to amine salts that would otherwise form without the contacting
of the composition comprising the at least one amine.

US Pat. No. 9,181,756

DRILL BIT WITH A FORCE APPLICATION USING A MOTOR AND SCREW MECHANISM FOR CONTROLLING EXTENSION OF A PAD IN THE DRILL BIT

Baker Hughes Incorporated...

16. A method of drilling a wellbore, comprising:
conveying a drill string having a drill bit at an end thereof, wherein the drill bit includes a pad configured to extend and
retract from a surface of the drill bit, and a force application device configured to extend the pad from the surface of the
drill bit, the force application device including: an electric motor that rotates a drive screw, a drive nut coupled to the
drive screw, wherein the drive screw rotation in a first direction causes the drive nut to move in a first linear direction
and rotation of the drive screw in a second direction causes the drive nut to move in a second linear direction, and a drive
shaft coupled to the drive nut configured to exert force on the pad to extend the pad from the surface of the drill bit, wherein
the drive shaft exerts force on a lever that applies force on a drive unit to cause the drive unit to extend the pad from
the surface of the drill bit; and

drilling the wellbore with the drill string.

US Pat. No. 9,410,380

SYSTEMS AND METHODS FOR PROVIDING FIBER OPTICS IN DOWNHOLE EQUIPMENT

Baker Hughes Incorporated...

3. A method comprising:
providing a plurality of field-assembled downhole system components, wherein each of the components has a passageway therein
sized to accommodate an optical fiber;

field-assembling the components and coupling the passageways of the components to form a single sealed conduit that extends
through at least two of the components; and

inserting an optical fiber into the conduit, wherein the inserted optical fiber occupies at least a portion of each of the
passageways of the at least two components,

wherein the at least two components comprise sections of a electric submersible pump motor,
wherein for at least a lower one of the motor sections, the method further comprises coupling a tubular connector to an upper
end of the corresponding passageway through the lower motor section, wherein an upper end of the tubular connector extends
above an upper end of the lower motor section, and

wherein field-assembling the motor sections comprises temporarily sealing an upper end of the tubular connector of the lower
motor section, filling the lower motor section with oil, unsealing the tubular connector, and installing an upper one of the
motor sections on the lower motor section, thereby forming a sealed conduit through the upper and lower motor sections and
the tubular connector.

US Pat. No. 9,388,664

HYDRAULIC SYSTEM AND METHOD OF ACTUATING A PLURALITY OF TOOLS

BAKER HUGHES INCORPORATED...

22. A method of actuating a plurality of tools, comprising:
altering pressure in a chemical injection line operably connected to the plurality of tools;
actuating at least one first of the plurality of tools in response to a first selected pressure change profile in the chemical
injection line;

altering flow of wellbore fluids with the at least one first of the plurality of tools;
altering pressure in the chemical injection line further;
actuating at least one second of the plurality of tools in response to a second selected pressure change profile in the chemical
injection line wherein the foregoing alterations in pressure in the chemical injection line occur without affecting whether
or not chemical is being injected via the chemical injection; and

altering flow of additional wellbore fluids with the at least one second of the plurality of tools.

US Pat. No. 9,354,347

METHOD AND APPARATUS FOR DEEP TRANSIENT RESISTIVITY MEASUREMENT WHILE DRILLING

BAKER HUGHES INCORPORATED...

1. A method for estimating a property of an earth formation penetrated by a borehole, the method comprising:
conveying a drill tubular through the borehole;
transmitting a transient signal into the formation with a transmitter transducer disposed at the drill tubular;
receiving a first signal with a first receiver transducer having a sensitivity oriented in a first direction and disposed
an axial distance from the transmitter transducer;

receiving a second signal with a second receiver transducer having a sensitivity oriented in a second direction different
from the first direction and disposed an axial distance from the transmitter transducer;

calculating a corrected signal that corrects for at least one of bending and torsion of the drill tubular between the transmitter
transducer and the first and second receiver transducers using the first signal and the second signal; and

estimating the property using the corrected signal.

US Pat. No. 9,303,475

TOOL WITH MULTISIZE SEGMENTED RING SEAT

BAKER HUGHES INCORPORATED...

1. A catch-and-release mechanism for use in a subterranean hydrocarbon production-related tool that is hydraulically actuated,
the catch-and-release mechanism comprising:
an expansion chamber defined within the tool and having a plurality of chamber portions of different diameters;
a seat to catch and release a plug, the seat being retained within the expansion chamber and formed of a plurality of separate
arcuate segments which define an annular seat having a central opening;

wherein the central opening of the seat has a first diameter when the seat resides within one of said plurality of chamber
portions and a second diameter that is larger than the first diameter when the ball seat resides within another of said chamber
portions; and

wherein at least one of said arcuate segments has a larger interior diameter than at least another of said arcuate segments,
thereby allowing fluid to flow through the seat when a plug is seated on the seat.

US Pat. No. 9,284,812

SYSTEM FOR INCREASING SWELLING EFFICIENCY

BAKER HUGHES INCORPORATED...

1. A swellable system reactive to a flow of fluid, comprising:
an article including a swellable material operatively arranged to swell upon exposure to the flow of fluid, the fluid being
aqueous and containing metallic cations from dissolved salts; and

a filter material disposed with the swellable material and operatively arranged to remove the polyvalent cations from the
flow of fluid before exposure to the swellable material,

the filter material comprising a graphene-based material, the graphene-based material comprising at least one functional group
operatively arranged to capture the polyvalent cations;

wherein the filter material and the swellable material are mixed homogeneously in the article.

US Pat. No. 9,260,568

METHOD OF CURING THERMOPLASTIC POLYMER FOR SHAPE MEMORY MATERIAL

Baker Hughes Incorporated...

1. A method of preparing a shape memory material, the method comprising:
compounding a thermoplastic polymer having a thermal decomposition temperature greater than or equal to about 200° C., with
a crosslinker, and optionally, an additive, to form a mixture;

compacting the mixture at room temperature;
heating and curing the compacted mixture at a temperature of about 300 to about 400° C., for a heating time of less than or
equal to about 72 hours to cure the thermoplastic polymer;

compression molding the cured thermoplastic polymer; and
de-molding at a temperature greater than or equal to about the glass transition temperature of the cured thermoplastic polymer.

US Pat. No. 9,243,458

METHODS FOR PRE-SHARPENING IMPREGNATED CUTTING STRUCTURES FOR BITS, RESULTING CUTTING STRUCTURES AND DRILL BITS SO EQUIPPED

Baker Hughes Incorporated...

1. A method of pre-sharpening an impregnated cutting structure for a bit for subterranean use, the impregnated cutting structure
comprising superabrasive material particles dispersed in and mutually separated by a metal matrix material, the method comprising,
prior to placing the impregnated cutting structure in a wellbore on the bit:
selecting at least one formation engaging surface of the impregnated cutting structure; and
removing a depth of the metal matrix material by machining the metal matrix material of the at least one selected formation
engaging surface adjacent, between and separating superabrasive particles dispersed therein to at least one of enhance exposure
of already exposed superabrasive particles to an increased height above the metal matrix material or expose portions of unexposed
superabrasive particles adjacent the metal matrix material.

US Pat. No. 9,244,050

METHODS AND DEVICES FOR TESTING WATER

Baker Hughes Incorporated...

1. A method of testing a liquid sample, comprising:
introducing the liquid sample into multiple jars;treating the liquid sample in the jars with at least one chemical agent to induce flocculation in the liquid sample, wherein
the liquid sample in each jar is treated with a different dosage of at least one chemical agent;
comparing the liquid samples in each jar to determine a dosage of the at least one chemical agent that results in a predetermined
level of at least one of: (i) flotation rate, (ii) floc separation, (iii) clarity, and (iv) turbidity;

agitating the liquid sample in each jar after treating the liquid sample with at least one chemical agent selected to cause
flocculation of solids in the liquid sample;

introducing dissolved air and carrier water into the liquid sample in each jar to float floc to a liquid surface in the jars;
drawing a supernate sample at a height lower than the floating floc from each jar after introducing dissolved air and carrier
water into the liquid sample; and

evaluating each supernate sample for at least turbidity.

US Pat. No. 9,187,971

OILFIELD DOWNHOLE WELLBORE SECTION MILL

BAKER HUGHES INCORPORATED...

1. A tool for cutting tubular at a subterranean location, comprising:
a stationary housing;
at least one extendable cutting blade pivotally mounted on a fixed pivot on said housing;
at least one extendable centering blade pivotally mounted on a fixed pivot on said housing;
said centering blade extends to the tubular before said cutting blade;
said housing has a passage therethrough with a movable mandrel assembly disposed in said passage;
said mandrel assembly further comprising a mandrel sequentially moving spaced drive sleeves respectively associated with said
centering blade and said cutting blade for extension of said centering blade before said cutting blade.

US Pat. No. 9,103,171

APPARATUS FOR CONTROLLING DRILL BIT DEPTH OF CUT USING THERMALLY EXPANDABLE MATERIALS

Baker Hughes Incorporated...

15. A method of drilling a wellbore, comprising:
conveying a drilling assembly having a drill bit at an end thereof, the drill bit including a body including a side, a face,
a passage in the body, and a rubbing member in the face and configured to control a depth of cut for the drill bit, wherein
the rubbing member comprises a thermally-responsive material in thermal communication with a fluid flow contained in the passage,
the thermally-responsive material configured to control a position of the rubbing member with respect to the face;

drilling the wellbore with the drill bit; and
controlling the fluid flow through the passage to control the temperature of the thermally-responsive material to control
a depth of cut of the drill bit via a control valve operated in response to a parameter of interest.

US Pat. No. 9,395,049

APPARATUS AND METHODS FOR DELIVERING A HIGH VOLUME OF FLUID INTO AN UNDERGROUND WELL BORE FROM A MOBILE PUMPING UNIT

Baker Hughes Incorporated...

19. A method of providing a high volume of pressurized fluid from a single mobile high pressure fluid delivery system into
an underground well bore, the method comprising:
on a single mobile chassis, positioning first and second high pressure fluid pumps on opposing sides of an electric motor,
wherein the fluid pumps and electric motor are axially aligned on the chassis, the electric motor having a single drive shaft
extending axially therethrough and outwardly therefrom at its opposing sides;

mechanically coupling the fluid pumps directly to drive shaft of the electric motor at the respective opposing sides of the
motor so that the electric motor is configured to simultaneously drive both pumps to pump high pressure fluid into the well
bore, the electric motor being configured to drive each fluid pump regardless of the operation of the other fluid pump;

engaging at least a first flex coupling with and between the electric motor and the first fluid pump and configured to allow
movement of the electric motor and the first fluid pump relative to one another during and without disturbing the operation
thereof;

engaging at least a second flex coupling with and between the electric motor and the second fluid pump and configured to allow
movement of the electric motor and the second fluid pump relative to one another during and without disturbing the operation
thereof;

electrically connecting a remotely controllable variable frequency drive disposed on the chassis to the electric motor and
an external electric power source; and

the variable frequency drive providing electric power to the electric motor from the external electric power source and allowing
the speed of the electric motor to be remotely controlled.

US Pat. No. 9,359,254

WELLBORE CEMENT COMPOSITIONS AND WELLBORE CEMENTING METHODS

BAKER HUGHES INCORPORATED...

1. A wellbore cement composition comprising:
substantially unhydrated cement powder; and
non-cementitious additive powder for cement, the additive powder being formulated from ingredients including a liquid additive
for cement and solid carrier particles, the liquid additive being absorbed by the solid carrier particles and including a
material selected from retarders, drilling mud surfactants, fluid loss agents, organic dispersants, antifoam agents, cement
set accelerators, foamers, foam stabilizers, and combinations thereof, and the additive powder containing a mass of the liquid
additive at least one-half a mass of the solid carrier particles.

US Pat. No. 9,243,471

REMOVABLE PACKER PLUG WITH INSTALLATION BYPASS FEATURE

Baker Hughes Incorporated...

1. A packer plug assembly for a packer, comprising:
a tubular body having a wall and an axial through passage extending down from an upper end thereof;
a seal assembly and a grip assembly on an outer surface of said tubular body for engaging the packer;
a selectively removable plug in said passage; and
a valved bypass passage around said plug, said bypass passage located in said wall of said tubular body.

US Pat. No. 9,243,475

EXTRUDED POWDER METAL COMPACT

Baker Hughes Incorporated...

1. A powder metal compact, comprising:
a substantially elongated cellular nanomatrix comprising a nanomatrix material;
a plurality of substantially elongated dispersed particles comprising a particle core material that comprises Mg, Al, Zn or
Mn, or a combination thereof, dispersed in the cellular nanomatrix; and

a solid-state bond layer formed by solid state bonding extending throughout the cellular nanomatrix between adjacent dispersed
particles, wherein the cellular nanomatrix and the dispersed particles are substantially elongated in one predetermined direction
to an extent that the cellular nanomatrix, dispersed particles, and solid-state bond layer are substantially continuous in
the predetermined direction or to an extent that the nanomatrix and dispersed particles become separated, cracked or otherwise
substantially discontinuous in the predetermined direction.

US Pat. No. 9,212,547

MONITORING DEVICE FOR PLUG ASSEMBLY

Baker Hughes Incorporated...

1. A monitoring tool, comprising:
an obstructor portion operatively arranged to impede fluid flow past the monitoring tool when the obstructor is engaged with
a corresponding seat member;

a disintegrable portion formed from a material operatively arranged to disintegrate upon exposure to a selected fluid; and
a gauge coupled with the obstructor portion and the disintegrable portion, the gauge operatively arranged to monitor one or
more parameters and released from the obstructor portion when the disintegrable portion is disintegrated by the selected fluid.

US Pat. No. 9,140,074

DRILL BIT WITH A FORCE APPLICATION DEVICE USING A LEVER DEVICE FOR CONTROLLING EXTENSION OF A PAD FROM A DRILL BIT SURFACE

Baker Hughes Incorporated...

1. A drill bit, comprising:
a member configured to extend and retract from a face section of the drill bit; and
a force application device in the drill bit configured to extend and retract the member from the face section of the drill
bit, the force application device including a drive device that includes a lever action device, wherein the lever action device
includes a lever operatively coupled to the member and a piston coupled to the lever, wherein a motion of the piston in a
radial direction causes the member to extend and retract from the face section of the drill bit along an axis of the drill
bit.

US Pat. No. 9,090,814

WELL TREATMENT FLUIDS CONTAINING AN YLIDE OR A VITAMIN B AND METHODS OF USING THE SAME

Baker Hughes Incorporated...

1. An aqueous fracturing fluid comprising:
(a) a viscosifying polymer; and
(b) a breaker comprising an ylide or a vitamin B cofactor selected from the group consisting of vitamin B1, vitamin B2, vitamin B3, vitamin B6, vitamin B9, vitamin B12, and mixtures thereof
wherein the pH of the aqueous fracturing fluid is greater than or equal to 8.0.

US Pat. No. 9,410,398

DOWNHOLE SYSTEM HAVING COMPRESSABLE AND EXPANDABLE MEMBER TO COVER PORT AND METHOD OF DISPLACING CEMENT USING MEMBER

BAKER HUGHES INCORPORATED...

14. A method of non-ballistically opening ports in a tubular of a downhole system, the method comprising:
covering at least one port in the tubular with an initially compressed radially extendable member;
blocking the at least one port with a movable sleeve within the tubular;
inserting the tubular within a borehole;
cementing an annular space between the tubular and the borehole;
allowing the radially extendable member to expand from heat of curing cement;
at least partially displacing the cement with the radially extendable member; and,
after the cement is at least substantially cured, moving the movable sleeve to expose the radially extendable member to an
interior of the tubular.

US Pat. No. 9,404,340

FRAC SLEEVE SYSTEM AND METHOD FOR NON-SEQUENTIAL DOWNHOLE OPERATIONS

BAKER HUGHES INCORPORATED...

1. An electronically triggered, self-powered frac sleeve system comprising:
a body having an inner collar and an outer collar;
first and second electronic triggers at least partially housed between the inner and outer collars;
first and second openings in the body openable to a first pressure;
first and second enclosed chambers having a second pressure less than that of first pressure;
first and second piston members positioned between the first and second openings and the first and second chambers, respectively;
and,

first and second sleeves arranged between the inner and outer collars and slidable within the body;
wherein the first and second electronic triggers expose the first and second piston members to hydrostatic pressure via the
first and second openings and movement of the first and second piston members translate to movement of the first and second
sleeves operatively connected thereto.

US Pat. No. 9,388,639

ROTATABLE CUTTING ELEMENTS AND RELATED EARTH-BORING TOOLS AND METHODS

Baker Hughes Incorporated...

15. A method of removing an earth formation, comprising:
rotating a body of an earth-boring tool;
engaging a rotatable cutting element with an earth formation, wherein the rotatable cutting element is rotatably connected
to a protruding journal proximate a rotationally leading portion of a blade, the blade extending from the body, wherein the
rotatable cutting element is not located within a pocket extending into the blade;

directing cuttings forward, away from a cutting face of the rotatable cutting element, when the cuttings reach an inner bore
extending through the rotatable cutting element; and

rotating the rotatable cutting element around the protruding journal responsive to the engagement of the rotatable cutting
element with the earth formation, which is at least partially located in the inner bore of the rotatable cutting element.

US Pat. No. 9,325,012

CARBON COMPOSITES

BAKER HUGHES INCORPORATED...

1. A carbon composite comprising
carbon microstructures having interstitial spaces among the carbon microstructures; and
a binder disposed in at least some of the interstitial spaces;
wherein the carbon microstructures comprise unfilled voids within the carbon microstructures.

US Pat. No. 9,298,859

ELECTRICAL SUBMERSIBLE PUMP DESIGN PARAMETERS RECALIBRATION METHODS, APPARATUS, AND COMPUTER READABLE MEDIUM

Baker Hughes Incorporated...

1. A method of analyzing and recalibrating parameters for an electrical submersible pump (ESP) application model, the method
comprising the steps of:
generating, by a processor, a data set comprising a plurality of sets of ESP application model input parameters and associated
theoretical output parameters for an ESP application model substantially matching a corresponding set of measured ESP output
parameters defining a plurality of winning data sets or rows; and

performing an averaging analysis, by the processor, on the plurality of winning data sets or rows to obtain a set of ESP application
model input parameters usable to recalibrate the ESP application model, wherein the step of generating a data set comprises
performing the following steps for each of a plurality of training data sets:

performing a cluster analysis, by the processor, on one of the plurality of training data sets in order to segregate the training
data set into a plurality of clusters, each cluster containing a plurality of data rows from the training data set, each data
row in the same one of the plurality of clusters having at least similar characteristics;

mapping, by the processor, the set of measured ESP output parameters to one of the plurality of clusters responsive to a similarity
analysis performed on the theoretical output parameter within each cluster to identify a winning cluster, the winning cluster
being the one cluster of at least several data rows collectively having a set of output parameters most closely matching the
corresponding set of measured ESP output parameters; and

identifying, by the processor, a winning data row within the winning cluster that yields outputs parameters which are the
most closest to the corresponding set of measured ESP output parameters to define one of the plurality of winning data rows.

US Pat. No. 9,279,293

DRILL BIT WITH EXTENDABLE GAUGE PADS

BAKER HUGHES INCORPORATED...

17. A method of drilling a wellbore, comprising:
conveying a drill string having a drill bit at an end thereof, wherein the drill bit includes:
a bit body having a blade of a selected length along a side of the bit body, the bit body having a longitudinal axis; and
a movable member on the side of the bit body that extends from a retracted position along the longitudinal axis to a selected
extended position to effectively extend the selected length of the blade when the moveable member is in the selected extended
position; and

drilling the wellbore using the drill string.

US Pat. No. 9,281,675

SYSTEMS AND METHODS FOR CABLE DEPLOYMENT OF DOWNHOLE EQUIPMENT

Baker Hughes Incorporated...

1. A system for cable deployment of downhole equipment, the system comprising:
a support structure positioned at the surface of a well;
a piece of downhole electrical equipment; and
an elongated cable coupling the piece of downhole electrical equipment to the support structure;
wherein the elongated cable includes
a plurality of weight-bearing conductors,
one or more layers of insulating or protective material surrounding the weight-bearing conductors,
an upper support coupling connected to an upper end of each of the weight-bearing conductors, wherein the upper support coupling
suspends each of the weight-bearing conductors from the support structure, and

a lower equipment coupling connected to a lower end of each of the weight-bearing conductors, wherein the lower equipment
coupling suspends the piece of downhole electrical equipment from the plurality of weight-bearing conductors,

wherein the plurality of weight-bearing conductors are electrically coupled to the piece of downhole electrical equipment,
wherein power is transmitted through the plurality of weight-bearing conductors to the piece of downhole electrical equipment,
and wherein substantially all of the weight of the piece of downhole electrical equipment is transferred from the lower equipment
coupling only through the plurality of weight-bearing conductors to the upper support coupling;

wherein the weight-bearing conductors comprise an aluminum alloy.

US Pat. No. 9,201,160

MEASUREMENT OF DOWNHOLE GAMMA RADIATION BY REDUCTION OF COMPTON SCATTERING

BAKER HUGHES INCORPORATED...

1. An apparatus for evaluating an earth formation intersected by a borehole, the apparatus comprising:
a first radiation responsive component configured to detect gamma rays;
a second radiation responsive component configured to detect gamma rays that traverse the first radiation responsive component,
wherein the second radiation responsive component is disposed within the first radiation responsive component, and wherein
the gamma rays that traverse the first radiation responsive component include at least gamma rays that interact with the first
radiation component and are indicative of Compton scattering in the formation; and

a processor configured to:
generate a reduced-Compton gamma ray spectrum mitigating effects on the gamma ray spectrum resulting from Compton scattering
in the formation by generating an anticoincidence gamma ray spectrum responsive to the gamma rays detected by the first radiation
responsive component and the gamma rays detected by the second radiation responsive component, wherein the anticoincidence
gamma ray spectrum is indicative of those gamma rays of the gamma rays detected by the second radiation responsive component
that are not detected in coincidence with the same gamma rays detected by the first radiation responsive component, wherein
those gamma rays of the gamma rays detected by the second radiation responsive component that are not detected in coincidence
with the same gamma rays detected by the first radiation responsive component are indicative of Compton scattering in the
formation.

US Pat. No. 9,200,507

DETERMINING FRACTURE LENGTH VIA RESONANCE

Baker Hughes Incorporated...

1. A method of determining a length of a fracture induced from a borehole, the method comprising:
isolating a portion of the borehole, the portion of the borehole including an end of the fracture at the borehole wall;
increasing fluid pressure in the portion of the borehole;
deploying a low-frequency source in the portion of the borehole;
varying a frequency of the low-frequency source to generate resonance oscillations at a resonance frequency in the fracture;
and

determining the length of the fracture based on the resonance frequency;
wherein the increasing fluid pressure is by movement of a piston within a pipe in the portion of the borehole.
US Pat. No. 9,187,686

ENHANCED ELECTROLYTIC DEGRADATION OF CONTROLLED ELECTROLYTIC MATERIAL

Baker Hughes Incorporated...

1. A method for degrading a downhole article, comprising:
exposing the downhole article to a composition comprising a corrosive agent selected from a reducing sugar; and
contacting the downhole article with the corrosive agent to degrade the downhole article at a temperature of about 35° C.
to about 150° C.;

wherein the downhole article is degraded at a faster rate in the presence of the corrosive agent as compared to a brine without
the corrosive agent; and further

wherein the downhole article is degraded at a slower rate in the presence of the corrosive agent as compared to a mineral
acid.

US Pat. No. 9,157,718

INTERRUPTOR SUB, PERFORATING GUN HAVING THE SAME, AND METHOD OF BLOCKING BALLISTIC TRANSFER

Baker Hughes Incorporated...

1. An interruption sub for a downhole tool, the downhole tool activatable by detonation, the interruption sub comprising:
a detonation path within the interruption sub;
a barrier rotatable between a biased closed position and an open position, and preventing ballistic transfer to the downhole
tool in the closed position by blocking the detonation path, and allowing ballistic transfer to the downhole tool in the open
position by unblocking the detonation path; and,

a longitudinally movable control arm engageable with the barrier, the control arm biased away from a first end of the interruption
sub to retain the barrier in the biased closed position;

wherein the control arm is hydraulically or electromechanically longitudinally activatable to move towards the first end of
the interruption sub and towards the barrier to rotate the barrier against its bias to the open position in response to at
least one condition acceptable for ballistic transfer.

US Pat. No. 9,518,184

PROCESS FOR PREPARING BLENDS OF BITUMEN HAVING KNOWN STABILITY PROPERTIES

Baker Hughes Incorporated...

1. A method of preparing bitumen comprising:
obtaining an inflection point value for a mixed bitumen product stream sample comprising at least two bitumen feed streams;
wherein the inflection point value correlates to the stability of the mixed bitumen product stream based on the amount of
added non-solvent; wherein the obtaining the inflection point value occurred by:

adding a non-solvent to the mixed bitumen product stream sample;
transmitting near IR laser light through the mixed bitumen product stream sample;
determining an inflection point value that correlates to the stability of the mixed bitumen product stream based on the amount
of non-solvent added; and

modifying the mixed bitumen product stream when the inflection point value occurs at a ratio of less than about 2 mL of added
non-solvent per 1 gram of the mixed bitumen product stream sample wherein the modifying the mixed bitumen product stream is
selected from the group consisting of:

altering the ratio of the at least two bitumen feed streams within the mixed bitumen product stream;
introducing at least one stabilizing additive to the mixed bitumen product stream; and
combinations thereof: and
giving a result selected from the group consisting of:
a stable mixed bitumen product stream;
the mixed bitumen product stream having a viscosity less than an otherwise identical mixed bitumen feed stream absent the
modifying the mixed bitumen product stream; and

both;
where the at least two bitumen feed streams are selected from the group consisting of:
at least two bitumen feed streams where both bitumen feed streams comprises bitumen; and
at least one bitumen feed stream comprising bitumen and at least one heavy hydrocarbon.

US Pat. No. 9,358,613

HYDROPHOBIC POROUS HARD COATING WITH LUBRICANT, METHOD FOR MAKING AND USE OF SAME

BAKER HUGHES INCORPORATED...

1. A composite comprising:
a porous matrix having a molybdenum-silicon-boron (Mo—Si—B) alloy, the Mo—Si—B alloy having a plurality of pores and comprising
one or more of the following: ?-Mo; Mo3Si; Mo5SiB2; or Mo-20Si-10B; and

a lubricant in contact with the Mo—Si—B alloy, a hydrophobic compound in contact with the Mo—Si—B alloy, or a combination
thereof;

wherein the lubricant is a solid lubricant and comprises one or more of the following: indium; tin; antimony; germanium; zinc;
copper; boron nitride; graphene; or carbon nanotube; and further wherein an amount of the plurality of pores in the porous
matrix is from 5 vol % to 40 vol %, based on a total volume of the porous matrix, and the average pore size is greater than
or equal to 1 micron; and

wherein a strength of the composite is greater than or equal to 500 MPa at a temperature greater than or equal to 1000° C.

US Pat. No. 9,328,609

APPARATUS AND METHOD FOR DETERMINATION OF FORMATION BUBBLE POINT IN DOWNHOLE TOOL

BAKER HUGHES INCORPORATED...

1. An apparatus for estimating a bubble point of a fluid in an earth formation penetrated by a borehole, the apparatus comprising:
a carrier configured to be conveyed through the borehole;
a probe disposed at the carrier and configured to extend from the carrier and seal to a wall of the borehole;
a pump in fluid communication with the probe, the pump having a variable volume configured to pump fluid from the earth formation
into the volume within the pump;

a volume sensor configured to sense the volume within the pump;
a pressure sensor in pressure communication with the fluid in the volume of the pump and configured to sense the pressure
of the fluid in the volume in the pump;

an isolation valve coupled to the probe and configured to isolate a sample of the fluid pumped through the probe, wherein
the sample is isolated in the pump; and

a processor coupled to the volume sensor, the pressure sensor, and a prime mover configured to operate the pump to change
the variable volume, the processor being configured to perform a pressure-volume test on the fluid sample, the test comprising:

increasing the pressure of the fluid sample above formation pressure by decreasing the volume within the pump and logging
the pressure and volume of the fluid sample using the pressure sensor and the volume sensor during the decrease in volume
of the pump;

calculating a reference compressibility of the fluid sample;
decreasing the pressure of the fluid sample and logging the pressure and volume using the pressure sensor and the volume sensor;
calculating a compressibility of the fluid sample using the logged pressure and volume obtained from during the decreasing;
comparing the calculated compressibility to a threshold; and
estimating the bubble point as the current fluid sample pressure when the calculated compressibility first meets or exceeds
the threshold factor.

US Pat. No. 9,303,497

USE OF LONG CHAIN ALCOHOLS, KETONES AND ORGANIC ACIDS AS TRACERS

BAKER HUGHES INCORPORATED...

1. A method for determining a presence of a tracer from a subterranean location comprising:
introducing at least one non-halogenated tracer into a subterranean location, where the at least one non-halogenated tracer
is a molecule having from 10 to 30 carbon atoms selected from the group consisting of aliphatic, aromatic, saturated, unsaturated,
and/or combinations thereof, of alcohols, ketones, organic acids, organic acid salts, sulfonated alcohols, sulfonated ketones,
sulfonated organic acids, sulfonated organic acid salts, and combinations thereof, where the non-halogenated tracer is introduced
in a form selected from the group consisting of:

neat,
encapsulated within a coating material that is inert with respect to the tracer,
in an oil internal phase in an oil-in-water emulsion, and
in situ generation;
recovering a fluid from the subterranean location where the fluid comprises the at least one non-halogenated tracer; and
reacting the at least one non-halogenated tracer with a reagent to give at least one derivatized tracer, where the reagent
is a reagent that can attach at least one halogen atom to the non-halogenated tracer.

US Pat. No. 9,297,213

POLYCRYSTALLINE DIAMOND ELEMENT

BAKER HUGHES INCORPORATED...

1. A polycrystalline diamond (PCD) element having internal diamond surfaces, the internal diamond surfaces defining interstices
between them; the PCD element comprising a masked or passivated region and an unmasked or unpassivated region, the masked
or passivated region extending a depth into the PCD element from a working surface of at least 100 microns, the unmasked or
unpassivated region defining a boundary with another region or body, and extending a depth of between 5 microns and 600 microns
from the boundary, in which at least some of the internal diamond surfaces of the masked or passivated region contact a mask
or passivation medium, and wherein some or all of the interstices of the masked or passivated region and of the unmasked or
unpassivated region are at least partially filled with an infiltrant material.

US Pat. No. 9,291,045

METHOD OF FRACTURING USING ULTRA LIGHTWEIGHT PROPPANT SUSPENSIONS AND GASEOUS STREAMS

Baker Hughes Incorporated...

1. A method of fracturing a subterranean formation comprising introducing a proppant stage into the subterranean formation,
wherein the proppant stage comprises a fine uniform textured foam containing:
(i) a viscosified aqueous fluid having ultra lightweight (ULW) proppant suspended in the viscosified aqueous fluid; and
(ii) a gaseous fluid, wherein the amount of gaseous fluid in the fine uniform textured foam is at least about 85 volume percent;wherein at least 70% gas volume of bubbles of the fine uniform textured foam have a diameter less than or equal to 0.18 mm
and further wherein the proppant stage is introduced into the subterranean formation at a pressure sufficient to create or
enlarge a fracture.

US Pat. No. 9,279,312

DOWNHOLE SLEEVE SYSTEM AND METHOD

BAKER HUGHES INCORPORATED...

17. A method of opening and closing a port in a downhole tubular, the method comprising:
stopping a first ball with a first ball seat, the first ball seat movable with a first shuttle covering the port, the first
ball seat supported by a first ball seat support;

pressurizing the tubular to move the first shuttle and expose the port;
stopping a second ball with a second ball seat uphole of the first ball seat, the second ball seat movable with a second shuttle;
pressurizing the tubular to move the second shuttle and close the port; and,
abutting the first shuttle with the second shuttle to shift the first shuttle relative to the first ball seat support.

US Pat. No. 9,243,452

CUTTING ELEMENTS FOR EARTH-BORING TOOLS, EARTH-BORING TOOLS INCLUDING SUCH CUTTING ELEMENTS, AND RELATED METHODS

Baker Hughes Incorporated...

1. A shaped cutting element for an earth-boring tool, comprising:
a substrate;
a volume of superabrasive material disposed on the substrate, the volume of superabrasive material having a non-planar front
cutting face, the non-planar front cutting face having a pointed configuration including a conical lateral side surface and
a domed end, the substrate being a cylinder having a maximum diameter less than a maximum diameter of the volume of superabrasive
material, an entire interface between the substrate and the volume of superabrasive material located rearward of the conical
lateral side surface of the non-planar front cutting face of the volume of superabrasive material along a central axis of
the shaped cutting element; and

at least one recess extending into the conical lateral side surface of the non-planar cutting face of the volume of superabrasive
material from the front cutting face.

US Pat. No. 9,157,278

APPARATUS INCLUDING LOAD DRIVEN BY A MOTOR COUPLED TO AN ALTERNATOR

Baker Hughes Incorporated...

1. An apparatus for use in a wellbore, comprising:
a load;
a motor coupled to the load to provide mechanical energy to the load;
a switch directly coupled to the motor; and
an alternator directly coupled to the switch and no other electrical circuits, the switch configured to selectively connect
phases of the alternator to phases of the motor and the alternator configured to drive the motor with a first configuration
of the switch that causes the motor to rotate in a clockwise direction and with a second configuration of the switch that
causes the motor to turn in a counterclockwise direction.

US Pat. No. 9,157,316

SYSTEM AND METHOD FOR DETERMINING PRESSURE TRANSITION ZONES

Baker Hughes Incorporated...

1. A method of determining a pressure transition depth in a borehole, comprising:
obtaining measurements of a parameter indicative of formation fluid pressure at a plurality of borehole depths extending from
a starting depth to a selected depth;

determining a global trend line of the parameter using the obtained measurements over an entirety of a first depth interval
extending from the starting depth to the selected depth;

determining a local trend line of the parameter using the obtained measurements within a second depth interval that includes
the selected depth and is a subset of the first interval;

determining a deviation between the global trend line and the local trend line; and
determining the pressure transition depth when the determined deviation between the global trend line and the local trend
line meets a selected criterion.

US Pat. No. 9,079,247

DOWNHOLE TOOLS INCLUDING ANOMALOUS STRENGTHENING MATERIALS AND RELATED METHODS

Baker Hughes Incorporated...

1. A downhole tool for use in a wellbore in a subterranean formation, comprising:
a body comprising a composite material comprising:
at least one region of at least one anomalous strengthening material; and
at least another region of at least one temperature weakening material abutting the at least one region of the at least one
anomalous strengthening material;

wherein a quantity of the at least one anomalous strengthening material and a quantity of the at least one temperature weakening
material are such that a yield strength of the body is at least substantially constant as a function of temperature from about
120° C. to about 150° C.

US Pat. No. 9,062,534

PERFORATING SYSTEM COMPRISING AN ENERGETIC MATERIAL

Baker Hughes Incorporated...

1. A perforating system comprising:
a gun body having an annular shape and comprising an energetic material having propellant;
a gun tube in the gun body comprising the energetic material;
an amount of magnesium in the gun body; and
a shaped charge disposed in an annulus of the gun body comprising a charge case, a liner, and explosive between the charge
case and liner

so that when the explosive is detonated, the energetic material and the magnesium in the gun body changes a form of the gun
body and the gun tube from a solid material to a substantially vapor phase thereby causing the gun body and the gun tube to
disappear after the explosive is detonated.

US Pat. No. 9,441,458

VARIABLE TG SHAPE MEMORY POLYURETHANE FOR WELLBORE DEVICES

BAKER HUGHES INCORPORATED...

1. A method of manufacturing a wellbore device, the method comprising:
(a) mixing a first isocyanate portion comprising an isocyanate with a first polyol portion comprising a polyol in a first
ratio of polyol to isocyanate to form a first polyurethane material on a cylindrical billet having a first original geometric
position and having a first onset glass transition temperature Tg;

(b) mixing a second isocyanate portion comprising an isocyanate with a second polyol portion comprising a polyol in a second
ratio of polyol to isocyanate to form a second polyurethane material on the same cylindrical billet having a second original
geometric position and having a second onset glass transition temperature Tg, where the first onset Tg and the second onset Tg are different;

(c) altering the geometric shapes of the first and second polyurethane materials at a temperature above both the first and
second onset Tg to change the geometric shapes of the first and second polyurethane materials respectively; and

(d) lowering the temperature of the first and second polyurethane materials to a temperature below the first and second onset
Tgs, respectively, where the first and second polyurethane materials each maintain their respective altered geometry.

US Pat. No. 9,382,781

COMPLETION SYSTEM FOR ACCOMODATING LARGER SCREEN ASSEMBLIES

BAKER HUGHES INCORPORATED...

12. A method of completing a borehole, comprising:
selectively expanding a tubular string having a substantially continuous first dimension to form a plurality of expanded portions
of the tubular string having a second dimension greater than the first dimension and at least one unexpanded portion of the
tubular string having the first dimension and interspersed between adjacent ones of the expanded portions; and

positioning at least one screen assembly radially proximate to the at least one expanded portion for forming an enlarged radial
gap between the at least one screen assembly and the expanded portion of the tubular string.

US Pat. No. 9,364,312

BIODEGRADABLE METALLIC MEDICAL IMPLANTS

BAKER HUGHES INCORPORATED...

1. An implant comprising:
a metal composite which comprises:
a cellular nanomatrix comprising a metallic nanomatrix material; and
a metal matrix disposed in the cellular nanomatrix, the metal matrix comprising a particle core material that is discontinuously
and discretely distributed as particles within the metal composite;

the implant being configured to disintegrate in response to contact with a fluid,
wherein the metal composite is formed from powder particles comprising a particle core and at least one coating layer, the
coating layer forming the cellular nanomatrix; and the particle core forming the metal matrix disposed in the cellular nanomatrix
and comprising a nanostructured material having a grain size of 10 nm to 200 nm.

US Pat. No. 9,360,388

PRESSURE SENSING SYSTEM AND METHOD OF HOUSING A PRESSURE SENSOR

BAKER HUGHES INCORPORATED...

1. A pressure sensing system, comprising:
a pressure sensor;
an optical fiber in operable communication with the pressure sensor; and
a body disposed about the pressure sensor and the optical fiber, the body including a first end, a second end and an intermediate
portion defining a cavity, the second end defining a diaphragm fluidically connected with the cavity, the body being separated
a distance from the optical fiber arranged within the cavity, wherein operation of the pressure sensor is independent of changes
in distance between the optical fiber and the diaphragm.

US Pat. No. 9,283,657

METHOD OF MAKING A DIAMOND PARTICLE SUSPENSION AND METHOD OF MAKING A POLYCRYSTALLINE DIAMOND ARTICLE THEREFROM

BAKER HUGHES INCORPORATED...

1. A method of forming a polycrystalline diamond compact from a substantially homogeneous suspension of nanodiamond particles,
microdiamond particles, and metal solvent-catalyst particles, comprising:
disposing a first functional group on a plurality of nanodiamond particles to form derivatized nanodiamond particles;
combining the derivatized nanodiamond particles with a plurality of microdiamond particles, metal solvent-catalyst particles,
and a solvent to form a substantially homogeneous suspension of the derivatized nanodiamond particles, microdiamond particle
and metal solvent-catalyst particles in the solvent; and

forming a polycrystalline diamond compact from the homogenous suspension of derivatized nanodiamond particles, microdiamond
particles, and metal solvent catalyst particles, wherein forming comprises:

forming a polycrystalline diamond precursor by removing the solvent, and
processing the polycrystalline diamond precursor under conditions of heating and pressure to form the polycrystalline diamond
compact, the polycrystalline diamond compact comprising a superabrasive.

US Pat. No. 9,255,451

TUBE LOCKING MECHANISM FOR DOWNHOLE COMPONENTS

Baker Hughes Incorporated...

1. An apparatus for securing a transmission line in a downhole component, comprising:
a first element coupled to an exterior surface of the transmission line, the transmission line configured to be disposed in
a communication conduit that extends through the downhole component, the first element attached to the transmission line so
that the first element advances with the transmission line through the communication conduit; and

at least one deformable element configured to be disposed in the communication conduit and actuated to secure the transmission
line within the communication conduit, wherein the at least one deformable element is actuated by deforming the at least one
deformable element to engage the first element and restrict at least axial movement of the transmission line.

US Pat. No. 9,187,995

PRODUCTION ENHANCEMENT METHOD FOR FRACTURED WELLBORES

BAKER HUGHES INCORPORATED...

1. A completion and production method for a borehole, comprising:
running in at least one pair of spaced packers on a string having at least one port between the packers for flow communication
into an annular space between said packers and then radially in said annular space toward said string into said at least one
port when a zone is placed in production;

setting the packers in the borehole to define the zone between the packers;
fracturing the zone with pressure pumping a slurry;
placing the zone on production after said fracturing;
accumulating slurry solids or formation produced solids from the produced zone in said annular space adjacent one of said
spaced packers that impedes said production flow in said annular space in reaching said at least one port;

providing a bypass passage outside said string and within said annular space along a portion of said string without wall openings
for fluid to flow into said annular space and then substantially parallel to said string through said bypass passage from
the fractures previously created, said passage comprising a first passage end adjacent said solids and a second passage end
outside of said accumulated solids in said annular space and adjacent another portion of said string without wall openings,
whereupon exiting said second end said fluid flow continuing substantially parallel to said string into said annular space
toward said at least one port while experiencing reduced resistance to flow in said bypass passage as compared to flowing
in said annular space through slurry solids or formation produced solids that accumulated by said packer in said annular space.

US Pat. No. 9,163,615

TUBULAR DEVICE AND ACTUATOR

Baker Hughes Incorporated...

1. A tubular device comprising a tubular having a continuous wall and a substantially constant inner radial dimension over
a longitudinal portion of the tubular and an outer surface that varies in radial dimensions over the longitudinal portion,
the longitudinal portion being configured such that a rate of reduction in a longitudinal dimension of the longitudinal portion
in response to radial expansion of the longitudinal portion is less than a rate of reduction of a longitudinal dimension of
a constantly-dimensioned-inner-and-outer-radially-surfaced-tubular made of a same material as the tubular.

US Pat. No. 9,157,312

EMAT ACOUSTIC SIGNAL MEASUREMENT USING MODULATED GAUSSIAN WAVELET AND HILBERT DEMODULATION

BAKER HUGHES INCORPORATED...

1. A method of characterizing a casing installed in a borehole in an earth formation, the method comprising:
activating a transducer at at least one azimuthal orientation in the borehole and generating an acoustic pulse;
receiving a signal comprising a plurality of events resulting from the generation of the acoustic pulse;
bandpassing the received signal using two modulated filters in a time domain, the two modulated filters being orthogonal to
one another, and providing a bandpassed signal;

estimating an envelope of the bandpassed signal; and
estimating from the envelope of the bandpassed signal an arrival time of each of the plurality of events, the arrival times
being characteristic of a property of at least one of: (i) the casing, and (ii) a cement in an annulus between the casing
and the formation.

US Pat. No. 9,482,071

SEAT APPARATUS AND METHOD

BAKER HUGHES INCORPORATED...

1. A seating apparatus, comprising:
a housing having a bore, and a seat member disposed within the bore, the seat member configured to receive a plug element,
the seat member having a first position for receiving a plug element to restrict fluid flow through the bore and a second,
radially expanded position in which the plug element passes through the seat member,

a portion of the seat member formed at least partially from a disintegrable material responsive to a selected fluid, wherein
the portion of the seat member is substantially isolated from a portion of the bore when the seat member is in the first position,
and the portion of the seat member is in communication with the selected fluid after the seat member radially expands to the
second, radially expanded position.

US Pat. No. 9,404,030

SWELLABLE ARTICLE

BAKER HUGHES INCORPORATED...

1. A swellable article, comprising:
a matrix material;
an exfoliatable graphene-based material disposed in the matrix material, wherein the exfoliatable graphene-based material
is operatively arranged to expand upon application of ultrasonic frequencies to the graphene-based material and to facilitate
swelling of the swellable article upon exposure to a selected fluid by sorbing hydrocarbons in the fluid, the swelling enabling
the swellable article to engage an adjacent structure, and

an intercallant disposed between layers of the graphene-based material; and
wherein the intercallant is one or more of the following:
a metal selected from an alkali metal, alkaline earth metal, rare earth metal, transition metal, and post-transition metal;
a binary alloy of an alkali metal with mercury or thallium;
a binary compound of an alkali metal with a Group V element;
a metal chalcogenide comprising a metal oxide; a metal sulfide; a metal selenide; or a combination thereof
a metal peroxide;
a metal hyperoxide;
a metal hydride;
a metal coordinated by a nitrogenous compound;
a halogen comprising Cl2, Br2, BrCl, ICl, IBr, BrF3, BrF5, IF5, or a combination thereof;

an acid comprising CF3COOH, HSO3F, HSO3Cl, HSO3CF3, H2S2O8, phosphoric acid, H4P2O7, H3AsO4, H2 SeO4, HIO4, H5IO6, HAuCl4, H2PtCl6, or a combination thereof; or a combination thereof;

an oxidant comprising a permanganate ion, a chlorite ion, a chlorate ion, a perchlorate ion, a hypochlorite ion, a chromate
ion, a dichromate ion; or a combination thereof; or

a solvent comprising benzene, toluene, o-xylene, dimethyl sulfoxide, furan, tetrahydrofuran, o-dioxane, m-dioxane, p-dioxane,
dimethoxyethane, n-methyl-pyrrolidone, n,n-dimethylacetamide, ?-butyrolactone, 1,3-dimethyl-2-imidazolidinone, benzyl benzoate,
hexafluorobenzene, octafluorotoluene, pentafluorobenzonitrile, pentafluoropyridine, pyridine, dimethylformamide, hexamethylphosphoramide,
nitromethane, and benzonitrile, or a combination thereof.

US Pat. No. 9,303,502

METHOD OF CONTROLLING WATER PRODUCTION THROUGH TREATING PARTICLES WITH RPMS

BAKER HUGHES INCORPORATED...

1. A method of controlling water production from a subterranean formation comprising:
introducing particles coated with a relative permeability modifier (RPM) into a subterranean formation through a wellbore,
where the RPM is a crosslinked water hydrolyzable polymer having a weight average molecular weight greater than 100,000, and
where the particles are selected from the group consisting of glass beads, ceramic beads, metal beads, bauxite grains, walnut
shell fragments, aluminum pellets, nylon pellets and combinations thereof; wherein the crosslinked water hydrolyzable polymer
is selected from the group consisting of:

crosslinked polysiloxanes, copolymers of vinylamide monomers and monomers containing ammonium or quaternary ammonium moieties;
and

copolymers of vinylamide monomers and monomers comprising vinylcarboxylic acid monomers and/or vinylsulfonic acid monomers,
and salts thereof, and wherein these vinyl amide copolymers comprise a crosslinking monomer selected from the group consisting
of diallylamine, N,N-diallylacrylamide, divinyloxyethane, and divinyldimethylsilane; and

contacting the coated particles with water, causing swelling of the RPM thereby inhibiting water flow.

US Pat. No. 9,223,046

APPARATUS AND METHOD FOR CAPACITIVE MEASURING OF SENSOR STANDOFF IN BOREHOLES FILLED WITH OIL BASED DRILLING FLUID

BAKER HUGHES INCORPORATED...

1. A method of estimating at least one resistivity parameter of a formation, comprising:
conveying a bottom hole assembly configured for electromagnetic formation measurement into a borehole; and
using at least one processor to:
(i) measure a capacitance using only one selected frequency electromagnetic signal between the formation and at least one
measure electrode associated with the bottom hole assembly;

(ii) estimate a standoff between the at least one measure electrode and a borehole wall using the capacitance by using an
inversion of a plurality of capacitance measurements; and

(iii) estimate the at least one resistivity parameter using the estimated standoff and information about the at least one
resistivity parameter estimated from an electromagnetic signal received by the bottom hole assembly from the formation.

US Pat. No. 9,207,355

METHOD FOR PHYSICAL MODELING OF RESERVOIRS

Baker Hughes Incorporated...

1. A method for simulating materials subsurface to the earth, the method comprising:
receiving dimensions of each subsurface material to be simulated using a processor;
receiving a value of a property comprising electrical resistivity for each of the subsurface materials to be simulated using
the processor; and

constructing a three-dimensional physical model of the subsurface materials using a three-dimensional printer, the three-dimensional
printer being configured to print one or more layers of a print material for each of the subsurface materials being represented
in the model wherein dimensions and a property value of the print material for each subsurface material being represented
correspond to the dimensions and the electrical resistivity value for that subsurface material;

estimating a property of the materials subsurface to the earth by applying an electrical stimulus to the physical model and
receiving an electrical signal in response to the electrical stimulus;

wherein the electrical stimulus is a voltage or current applied using one or more electrodes and the received electrical signal
is a voltage or current received using one or more electrodes.

US Pat. No. 9,157,022

FLUID LOSS CONTROL IN VISCOELASTIC SURFACTANT FRACTURING FLUIDS USING WATER SOLUBLE POLYMERS

Baker Hughes Incorporated...

1. A method for treating a subterranean formation comprising:
injecting an aqueous viscoelastic surfactant treating fluid through a wellbore and into the subterranean formation, where
the aqueous viscoelastic treating fluid consists of:

an aqueous base fluid;
a viscoelastic surfactant (VES) gelling agent; and
a water soluble uncrosslinked polymer fluid loss control agent; and
optionally a component selected from the group consisting of a proppant, gravel, an acid, a salt, other surfactants different
from the VES, clay stabilization additives, scale dissolvers, biopolymer degradation additives, and combinations thereof;

where the aqueous viscoelastic treating fluid has an absence of a water soluble crosslinked polymer fluid loss control agent;
and

treating the subterranean formation.

US Pat. No. 9,434,026

SUBTERRANEAN SCREEN ASSEMBLY MANUFACTURING METHOD

Baker Hughes Incorporated...

1. A manufacturing method for a subterranean tubular screen assembly having a longitudinal axis, comprising:
attaching at least three flat layers, wherein a first of said layers is wider than an adjacent second of said layers leaving
spaced exposed ledge surfaces on said first layer on opposed ends of said second layer, said second layer is disposed between
said first and a third said layer, said second layer acting as a screen and said first and third layers have offset openings
such that flow passing said first layer has to flow axially in a direction generally parallel to the longitudinal axis through
said screen to reach an offset third layer opening;

spiral winding said attached layers into a tubular shape;
sealing a spiral seam formed by said spiral winding.

US Pat. No. 9,428,977

MULTI-STAGE LOCKING SYSTEM FOR SELECTIVE RELEASE OF A POTENTIAL ENERGY FORCE TO SET A SUBTERRANEAN TOOL

Baker Hughes Incorporated...

1. An actuation assembly for a subterranean tool, comprising:
a mandrel supporting a final controlled element;
a first potential energy source associated with said mandrel;
a first detent assembly to selectively isolate said potential energy source from said final controlled element:
a second detent assembly selectively operable independently of said first potential energy source and said first detent assembly,
said second detent assembly when selectively defeated by a first mechanical movement, thereafter, defeats said first detent
assembly by a second mechanical movement to allow said first potential energy source to move said final controlled element.

US Pat. No. 9,366,122

NATURAL FRACTURE INJECTION TEST

BAKER HUGHES INCORPORATED...

1. A method for estimating a property of an earth formation penetrated by a borehole, the method comprising:
performing a borehole integrity test at a pressure less than a fracture gradient pressure of the formation wherein the fracture
gradient pressure is a pressure at which pre-existing rock fractures in the earth formation will open and begin to accept
fluid, the borehole integrity test providing leakage data, the borehole integrity test comprising injecting a fluid into the
formation using a fluid injector at an integrity test flow rate that is low enough so that the fracture gradient pressure
of the formation is not exceeded;

injecting a fluid into the formation at a first pressure greater than the fracture gradient pressure at a first flow rate
during a first injection time interval using the fluid injector;

measuring pressure versus time using a pressure sensor and a timer during a first test time interval after the injecting for
the first injection time interval to provide first pressure data;

injecting a fluid into the formation at a second flow rate greater than the first flow rate during a second injection time
interval using the fluid injector;

measuring pressure versus time using the pressure sensor and the timer during a second test time interval after the injecting
for the second injection time interval to provide second pressure data;

monitoring a fluid temperature in the borehole using a temperature sensor;
correcting the first pressure data and the second pressure data for fluid temperature variations using the monitored fluid
temperature;

correcting the leakage data for fluid temperature variations using the monitored fluid temperature;
estimating the property using the corrected first pressure data, the corrected second pressure data, and the corrected leakage
data using a processor;

estimating a hydraulic stimulation pressure to stimulate the formation using the corrected first pressure data, the corrected
second pressure data, and the corrected leakage data; and

hydraulically stimulating the earth formation using the estimated hydraulic stimulation pressure.

US Pat. No. 9,273,518

METHODS OF COUPLING COMPONENTS OF DOWNHOLE TOOLS, DOWNHOLE TOOLS AND COMPONENTS OF DOWNHOLE TOOLS

Baker Hughes Incorporated...

14. A downhole tool including a bearing assembly comprising at least one bearing component being movable relative to a portion
of the downhole tool, the at least one bearing component consisting of a continuous phase matrix material and discrete particles
of diamond material embedded in and dispersed throughout an entire thickness of the continuous phase matrix material, the
at least one bearing component coupled to another portion of the downhole tool by a metal material formed on a bare, diamond-enhanced
surface of the bearing component through an ultrasonic molten metal brazing process.

US Pat. No. 9,260,961

MODULAR MONITORING ASSEMBLY

Baker Hughes Incorporated...

1. A monitoring assembly, comprising:
a sleeve;
a sensor for monitoring one or more selected parameters;
a plurality of modules in communication with the sensor and removably disposed within the sleeve such that individual modules
of the plurality of modules are physically removable from the sleeve and withdrawable to a remote location, the plurality
of modules including a first module in an active state and a second module in an inactive state; and

a detector that determines when the first module has been physically removed from the assembly, the second module transitioning
to the active state when the first module is physically removed from the assembly.

US Pat. No. 9,194,220

APPARATUS AND METHOD FOR DETERMINING FLUID INTERFACE PROXIMATE AN ELECTRICAL SUBMERSIBLE PUMP AND OPERATING THE SAME IN RESPONSE THERETO

Baker Hughes Incorporated...

9. A method of producing fluid from a wellbore, comprising
providing an ESP in the wellbore for pumping fluid into a production tubing;
measuring temperature at a plurality of locations along a section of the production tubing along and uphole of the ESP using
a sensor string clamped to the production tubing at spaced apart locations along and uphole of the ESP, the sensor string
including distributed sensors; and

determining from the measured temperatures at the plurality of locations a change in temperature between sensors that exceeds
a temperature threshold to determine a level of liquid in the wellbore; and

adjusting the ESP to control the level of the liquid in the wellbore while pumping fluid from the wellbore.

US Pat. No. 9,481,823

SYNERGISTIC CHEMISTRY TO PREVENT SILICATE SCALING

BAKER HUGHES INCORPORATED...

1. A method for inhibiting or preventing the formation of silicate scales, which method comprises adding to a fluid having
a potential for silicate scaling an amount of a chemical blend effective to inhibit or prevent the formation of silicate scales,
where the chemical blend comprises:
at least one first chemical that is a polyamine phosphonate; and
at least one second chemical that is a lysine tetra(alkylene)phosphonate.

US Pat. No. 9,429,236

SEALING DEVICES HAVING A NON-ELASTOMERIC FIBROUS SEALING MATERIAL AND METHODS OF USING SAME

BAKER HUGHES INCORPORATED...

1. A sealing device for use in a wellbore to isolate an annulus of the wellbore, the sealing device comprising:
a sealing element comprising a non-elastomeric fibrous sealing material disposed on a surface of the sealing device, the non-elastomeric
fibrous sealing material comprising a plurality of fibers of non-elastomeric sealing material, the plurality of fibers of
non-elastomeric sealing material comprising an initial position in which the plurality of fibers of non-elastomeric sealing
material comprises an initial volume and a compressed position in which the initial volume of the plurality of fibers of non-elastomeric
sealing material is reduced,

wherein the plurality of fibers of non-elastomeric sealing material isolates the annulus of the wellbore when the plurality
of fibers of non-elastomeric sealing material is in the compressed position.

US Pat. No. 9,372,124

APPARATUS INCLUDING STRAIN GAUGES FOR ESTIMATING DOWNHOLE STRING PARAMETERS

BAKER HUGHES INCORPORATED...

1. An apparatus for measuring strain on a downhole carrier, comprising:
a replaceable strain sensitive chassis configured to be removably attached to a surface of the carrier, the carrier made from
a material having a first coefficient of expansion, the chassis configured to be subject to a strain corresponding to a strain
on the carrier, the chassis having a second coefficient of expansion that is within a range of the first coefficient of expansion
so that the chassis and the carrier experience a proportional amount of strain; and

at least one strain gauge configured to estimate a strain of the carrier, the at least one strain gauge including at least
one thin film conductor sputtered onto a surface of an insulating layer, the insulating layer being deposited onto a surface
of the chassis, the at least one thin film conductor being a single layer of a metallic material.

US Pat. No. 9,809,712

HYDROPHOBIC AND OLEOPHOBIC COATINGS

BAKER HUGHES, a GE COMPAN...

1. A hydrophobic surface comprising a surface texture and a coating disposed on the surface texture, wherein the coating comprises
a first layer disposed directly on the surface texture and a second layer disposed on the first layer, the first layer comprising
a conforming material and the second layer comprising an amorphous diamond like carbon material doped with 25 to 35 atomic
percent of a dopant comprising a combination of Si and O or a combination of Si, O, and F, the diamond like carbon material
comprising 60 to 90 atomic percent of sp2 bonded carbon and 10 to 40 atomic percent of sp3 bonded carbon; and the conforming material comprising polytetrafluoroethylene, fluorinated ethylene propylene, perfluoroalkoxy,
polyvinylidene fluoride, polydimethylsiloxane, polyphenylene sulfide, metal-polytetrafluoroethylene composites, or a combination
comprising at least one of the foregoing; and wherein the surface texture comprises a micro texture, a micro-nano texture,
or a combination of a micro texture and a micro-nano texture; and the coating has a scratch hardness of greater than 100 ksi,
determined according to ASTM standard D7027-05 (2009) using a micro-scratch tester.
US Pat. No. 9,527,771

ELECTROLYTIC COMPOSITE MATERIALS

BAKER HUGHES INCORPORATED...

1. A composition, comprising:
a metallic composition comprising a particle having a core surrounded by a shell, the core comprising a magnesium alloy and
the shell comprising a metallic or ceramic layer not identical to the magnesium alloy, the magnesium alloy comprising magnesium
metal alloyed with Al, Cd, Ca, Co, Cu, Fe, K, Li, Mn, Na, Ni, Si, Ag, W, Sb, Sr, Ti, Th, Zn, Zr, or a combination comprising
at least one of the foregoing,

an inorganic oxide-based polymer, the inorganic oxide-based polymer comprising a plurality of structural repeating units which
comprise —(X—O)— where X is Si, Al, P, or a combination comprising at least one of the foregoing, and

a solvent.

US Pat. No. 9,441,471

IN SITU HEAT GENERATION

Baker Hughes Incorporated...

1. A method for generating in situ heat downhole comprising:
introducing a fluid composition into a wellbore, wherein the fluid composition comprises:
a metallic powder comprising a plurality of metallic powder particles, each metallic powder particle comprising:
at least one metallic particle core having a melting temperature (TP); wherein the metallic particle core comprises a metal
selected from the group consisting of magnesium, aluminum, zinc, iron, manganese, alloys thereof, and combinations thereof;

a coating disposed on the metallic particle core, wherein the coating comprises a material having a melting temperature (TC);
wherein at least two metallic powder particles are configured for solid-state sintering to one another at a predetermined
sintering temperature (TS), and TS is less than TP and TC and wherein the metallic powder particles are sintered together
to form a metallic particle compact, wherein the size of the metallic particle compact ranges from about 500 ?m to about 20
cm; and

a base fluid selected from the group consisting of a drilling fluid, a completion fluid, a stimulation fluid, a workover fluid,
activation fluid, and mixtures thereof;

releasing at least one metallic particle core from the plurality of metallic powder particles; and
reacting the at least one released metallic particle core with a heat-generating fluid and thereby generating heat.

US Pat. No. 9,410,415

METHOD OF FRACTURING SUBTERRANEAN FORMATIONS WITH CROSSLINKED FLUID

Baker Hughes Incorporated...

1. A method of fracturing a subterranean formation penetrated by a wellbore, comprising the steps of:
formulating a viscous fracturing fluid comprising (i) water, (ii) a hydratable polymer selected from the group consisting
of guar and guar derivatives, (iii) a borate based crosslinking agent and (iv) a proppant, wherein the hydratable polymer
loading in the viscous fracturing fluid is from 6 to 18 pptg;

pumping the viscous fracturing fluid through an entrance site in the wellbore into the reservoir; and propagating fractures
within the reservoir while decreasing the viscosity of the viscous fracturing fluid distally from the entrance site wherein
at least one of the following conditions prevail at in situ conditions during propagation of the fractures:

(a) the apparent viscosity of the fracturing fluid 100 feet from the entrance site is less than 10 percent of the apparent
viscosity of the fracturing fluid at the entrance site;

(b) the apparent viscosity of the fracturing fluid 15 minutes after introduction into the entrance site is less than 15% of
the apparent viscosity of the fracturing fluid at the entrance site; or

(c) the apparent viscosity of the fracturing fluid is less than 10 cP within 15 minutes after being introduced through the
entrance site.