An isolation valve has a valve body, which is mountable on or integrally formed with a tubular and which defines a valve pocket. A first flow path portion extends within the valve body between a tube inlet (connectable to an inlet tube) and a valve inlet port (in communication with the valve pocket). A second flow path portion extends within the valve body between a valve outlet port (in communication with the valve pocket) and a tube outlet (connectable to an outlet tube). A valve rod is disposed within the valve pocket of the valve body. The valve rod is moveable within the valve pocket between an open position (in which the valve inlet port and valve outlet port are in communication with each other) and a closed position (in which the valve inlet port and the valve outlet port are isolated from each other).
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
F16K 3/26 - Gate valves or sliding valves, i.e. cut-off apparatus with closing members having a sliding movement along the seat for opening and closing with sealing faces shaped as surfaces of solids of revolution with cylindrical valve members with fluid passages in the valve member
2.
GUIDANCE AND EVENT PREDICTION FOR WELL DRILLING OPERATIONS
A method for use with a subterranean well drilling operation can include training a predictive model with historical well data to predict a probability of a historical wellbore event occurring, then inputting to the trained predictive model parameters of a target well to be drilled, and the predictive model predicting a probability of a wellbore event occurring in the target well. A system for use with a subterranean well drilling operation can include a predictive model trained to predict at least one historical wellbore event, based on historical well data. The predictive model can be configured to predict a probability of a wellbore event occurring in a target well. The predictive model can be configured to provide guidance for drilling the target well.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
G06N 3/00 - Computing arrangements based on biological models
3.
FORMATION TESTING WITH CONTROLLED PRESSURE DRILLING
A formation testing method can include deploying a drill string including a packer and a circulating tool into a well, setting the packer, thereby blocking fluid flow through an annulus, and opening the circulating tool, thereby permitting fluid communication between the annulus and an interior flow passage of the drill string. The opening step can include displacing a radio frequency identification tag into the circulating tool. A formation testing system can include a drill string with a drill bit, a circulating tool and a packer. The packer is configured to seal off an annulus, and the circulating tool is selectively operable to permit fluid communication between the annulus and an interior flow passage of the drill string in response to a radio frequency identification tag being deployed into the circulating tool.
A method for use with a subterranean well drilling operation can include training a predictive model with historical well data to predict a probability of a historical wellbore event occurring, then inputting to the trained predictive model parameters of a target well to be drilled, and the predictive model predicting a probability of a wellbore event occurring in the target well. A system for use with a subterranean well drilling operation can include a predictive model trained to predict at least one historical wellbore event, based on historical well data. The predictive model can be configured to predict a probability of a wellbore event occurring in a target well. The predictive model can be configured to provide guidance for drilling the target well.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
5.
IMPACT JAR DELAY, ACTIVATION INDICATOR, SHOCK ABSORBER, AND RELATCH ASSIST
An impact jar apparatus including a dynamic portion connectable to an upper tool string portion, a static portion connectable to a lower tool string portion, and a hydraulic manifold, an activation indicator, a relatch assist, and/or a shock absorber. The hydraulic manifold fluidly communicates with an annulus between the dynamic and static portions. The hydraulic manifold adjusts a delay between application of a trigger tension and consequent activation of the impact jar apparatus. The activation indicator, including a wire coil in the static portion and magnets carried by the dynamic portion, generates a magnetic field whereby a voltage pulse is generated in the wire coil in response to the magnetic field passing the wire coil upon activation of the impact jar apparatus. The relatch assist urges the dynamic and static portions toward a latched position. The shock absorber absorbs axial shock generated by activation of the impact jar apparatus.
A method of cementing a tubular string in a wellbore can include applying a predetermined pressure differential from a flow passage extending axially through the tubular string to an annulus surrounding the tubular string, thereby opening a rupture disk of a cementing stage tool connected in the tubular string, and then flowing a fluid through the flow passage and into the annulus via the rupture disk, thereby displacing an opening plug into engagement with an opening sleeve of the cementing stage tool. A cementing stage tool can include a longitudinal flow passage, an outer housing assembly, an opening sleeve that prevents fluid flow between the flow passage and a housing port in a run-in configuration, and a rupture disk that permits fluid flow between the flow passage and the housing port in response to a predetermined pressure differential applied from the flow passage to the housing port.
E21B 33/14 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
7.
FORMATION TESTING WITH CONTROLLED PRESSURE DRILLING
A formation testing method can include deploying a drill string including a packer and a circulating tool into a well, setting the packer, thereby blocking fluid flow through an annulus, and opening the circulating tool, thereby permitting fluid communication between the annulus and an interior flow passage of the drill string. The opening step can include displacing a radio frequency identification tag into the circulating tool. A formation testing system can include a drill string with a drill bit, a circulating tool and a packer. The packer is configured to seal off an annulus, and the circulating tool is selectively operable to permit fluid communication between the annulus and an interior flow passage of the drill string in response to a radio frequency identification tag being deployed into the circulating tool.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
Power-operated downhole tools for use in the oil and gas
industry, namely, modular multi-function cement-through
systems comprising cutters, mills, or spears for anchoring
to a well casing.
9.
Impact Jar Delay, Activation Indicator, Shock Absorber, and Relatch Assist
An impact jar apparatus including a dynamic portion connectable to an upper tool string portion, a static portion connectable to a lower tool string portion, and a hydraulic manifold, an activation indicator, a relatch assist, and/or a shock absorber. The hydraulic manifold fluidly communicates with an annulus between the dynamic and static portions. The hydraulic manifold adjusts a delay between application of a trigger tension and consequent activation of the impact jar apparatus. The activation indicator, including a wire coil in the static portion and magnets carried by the dynamic portion, generates a magnetic field whereby a voltage pulse is generated in the wire coil in response to the magnetic field passing the wire coil upon activation of the impact jar apparatus. The relatch assist urges the dynamic and static portions toward a latched position. The shock absorber absorbs axial shock generated by activation of the impact jar apparatus.
A wet-mate connection is used in a well and comprises first and second connection assemblies and an actuator. The first connection assembly includes at least one first connector for at least one first control line. The second connection assembly is configured to connect with the first connection assembly and includes at least one second connector for at least one second control line. The second connector is movable on the second connection assembly between a retracted condition and an extended condition. In the extended condition, the second connector can mate with the first connector to communicate the first and second control lines with one another. The actuator is disposed on the second connection assembly and is configured to move the second connector at least from the retracted condition to the extended condition.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
11.
AXIALLY AND ROTATIONALLY LOCKED MODULAR VALVE ASSEMBLY SYSTEM
A modular system of plunger valve assemblies provides for axially and rotationally locking joints between upper and lower valve housings. Also provided are rotationally locking joints between adjacent valve assemblies.
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
E21B 17/046 - CouplingsJoints between rod and bit, or between rod and rod with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
F16K 15/06 - Check valves with guided rigid valve members with guided stems
12.
AXIALLY AND ROTATIONALLY LOCKED MODULAR VALVE ASSEMBLY SYSTEM
A modular system of plunger valve assemblies provides for axially and rotationally locking joints between upper and lower valve housings. Also provided are rotationally locking joints between adjacent valve assemblies.
A setting tool disposed on tubing runs a packer into casing. During a setting process, a plug is engaged on a seat of an intensifying piston disposed in the tool. Tubing pressure applied against the seated plug moves the intensifying piston, which produces intensified pressure on fluid in a first volume of the intensifying piston communicated to a second volume of a setting piston. In response, the setting piston moves on the tool toward the packer's packing assembly. At some point in the process, the seated plug can be released from the seat. Additionally in the process, the second volume can fill with actuation fluid drawn through a fill valve from an annular space between the setting tool and the casing. The intensifying piston can then be reset as the actuation fluid is communicated from the second volume to the first volume.
E21B 23/06 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting packers
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
A rotating control device can include a groove formed on a housing, and an elastomeric ring isolating inner and outer portions of the groove, the elastomeric ring permitting fluid communication between the inner and outer portions of the groove in response to a pressure differential from the inner to the outer portion of the groove. A method can include forming a circumferentially extending groove, providing fluid communication between the groove and an annular area isolated between rotary seals, and positioning an elastomeric ring in the groove, the elastomeric ring preventing fluid flow from an exterior of the groove to the annular area, and permitting fluid flow from the annular area to the exterior of the groove. Another rotating control device can include an elastomeric ring in a groove, and a passage in a housing that provides fluid communication between the groove and an annular area between rotary seals.
A rotating control device can include a groove formed on a housing, and an elastomeric ring isolating inner and outer portions of the groove, the elastomeric ring permitting fluid communication between the inner and outer portions of the groove in response to a pressure differential from the inner to the outer portion of the groove. A method can include forming a circumferentially extending groove, providing fluid communication between the groove and an annular area isolated between rotary seals, and positioning an elastomeric ring in the groove, the elastomeric ring preventing fluid flow from an exterior of the groove to the annular area, and permitting fluid flow from the annular area to the exterior of the groove. Another rotating control device can include an elastomeric ring in a groove, and a passage in a housing that provides fluid communication between the groove and an annular area between rotary seals.
A tubular string can include helical threads on respective tubulars, and a structural formation on at least one of the threads. The formation is configured to produce a change in torque as the threads are threaded together. A method of making up a threaded connection between tubulars can include producing a structural formation on at least one of threads of the respective tubulars, engaging the threads, and applying torque to the threaded connection, thereby causing the tubulars to shoulder up. The formation causes a change in the torque a predetermined number of turns prior to the shoulder up.
A tubular connection position measurement system can include an acoustic transmitter (38) secured with a rotary table (16), and an acoustic receiver (40) secured with the rotary table. Another tubular connection position measurement system can include an acoustic transmitter (38), an acoustic receiver (40), and a controller (46) configured to adjust a position of a tong assembly (28), based on a transit time of an acoustic signal transmitted in a tubular and received by the acoustic receiver. A method of determining a tubular connection position can include transmitting an acoustic signal through a tubular, a portion of the tubular being positioned above a rig floor (18), receiving a reflection of the acoustic signal, and determining a height (H) of the portion of the tubular above the rig floor, based on a transit time of the transmitted and reflected acoustic signal through the portion of the tubular.
A tubular string can include helical threads on respective tubulars, and a structural formation on at least one of the threads. The formation is configured to produce a change in torque as the threads are threaded together. A method of making up a threaded connection between tubulars can include producing a structural formation on at least one of threads of the respective tubulars, engaging the threads, and applying torque to the threaded connection, thereby causing the tubulars to shoulder up. The formation causes a change in the torque a predetermined number of turns prior to the shoulder up.
A method of cementing a tubular string in a wellbore can include applying a predetermined pressure differential from a flow passage extending axially through the tubular string to an annulus surrounding the tubular string, thereby opening a rupture disk of a cementing stage tool connected in the tubular string, and then flowing a fluid through the flow passage and into the annulus via the rupture disk, thereby displacing an opening plug into engagement with an opening sleeve of the cementing stage tool. A cementing stage tool can include a longitudinal flow passage, an outer housing assembly, an opening sleeve that prevents fluid flow between the flow passage and a housing port in a run-in configuration, and a rupture disk that permits fluid flow between the flow passage and the housing port in response to a predetermined pressure differential applied from the flow passage to the housing port.
E21B 33/14 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
E21B 34/06 - Valve arrangements for boreholes or wells in wells
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
A gas lift device includes a housing, a valve, and a nozzle. The housing defines a chamber and defines an inlet and an outlet in communication with the chamber. The valve in the chamber permits fluid communication from the inlet toward the outlet and prevents fluid communication in the reverse. The nozzle disposed in the chamber has a converging section, a throat, and a diverging section, which extend along a longitudinal axis of the chamber. A surface of the converging section converges inwardly from the chamber to the throat to funnel fluid communication from the inlet to the throat. A flow restriction of the throat restricts the fluid communication from the converging section to the diverging section. A surface of the diverging section diverges outwardly from the throat toward the outlet. Vanes extend inwardly in the diverging section and spiral about the longitudinal axis.
A tubular connection position measurement system can include an acoustic transmitter secured with a rotary table, and an acoustic receiver secured with the rotary table. Another tubular connection position measurement system can include an acoustic transmitter, an acoustic receiver, and a controller configured to adjust a position of a tong assembly, based on a transit time of an acoustic signal transmitted in a tubular and received by the acoustic receiver. A method of determining a tubular connection position can include transmitting an acoustic signal through a tubular, a portion of the tubular being positioned above a rig floor, receiving a reflection of the acoustic signal, and determining a height of the portion of the tubular above the rig floor, based on a transit time of the transmitted and reflected acoustic signal through the portion of the tubular.
E21B 47/095 - Locating or determining the position of objects in boreholes or wellsIdentifying the free or blocked portions of pipes by detecting acoustic anomalies, e.g. using mud-pressure pulses
E21B 41/00 - Equipment or details not covered by groups
A method for use with a subterranean well can include operating a human interface controller to control a well operation, thereby producing an operational force in the well operation, and applying a feedback force to an input structure of the human interface controller, the feedback force being based on the operational force. A system for use with a subterranean well can include a human interface controller configured to receive human input to control a well operation, and a control system configured to produce an operational force in the well operation in response to the human input. The control system is further configured to produce a feedback force in the human interface controller in opposition to the human input.
G05G 9/047 - Manually-actuated control mechanisms provided with one single controlling member co-operating with two or more controlled members, e.g. selectively, simultaneously the controlling member being movable in different independent ways, movement in each individual way actuating one controlled member only in which movement in two or more ways can occur simultaneously the controlling member being movable by hand about orthogonal axes, e.g. joysticks
A method of cementing a tubular string in a wellbore can include applying a predetermined pressure differential from a flow passage extending axially through the tubular string to an annulus surrounding the tubular string, thereby opening a rupture disk of a cementing stage tool connected in the tubular string, and then flowing a fluid through the flow passage and into the annulus via the rupture disk, thereby displacing an opening plug into engagement with an opening sleeve of the cementing stage tool. A cementing stage tool can include a longitudinal flow passage, an outer housing assembly, an opening sleeve that prevents fluid flow between the flow passage and a housing port in a run-in configuration, and a rupture disk that permits fluid flow between the flow passage and the housing port in response to a predetermined pressure differential applied from the flow passage to the housing port.
E21B 33/14 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
24.
SYSTEM AND METHOD FOR AUTOMATED CONFIGURATION OF HANDLING EQUIPMENT AND DOWNHOLE COMPONENTS
System and methods disclosed herein store sizing parameters for sized members used with downhole components and stores dimensions of the downhole components to be handled at the wellsite. The sizing parameter for a respective sized member defines how the respective sized member is sized for use with the downhole components. Machine-readable indicia is encoded with the sizing parameters and physically associated with the sized members. When handling a current downhole component, the sizing parameter associated with current sized member is determined by reading the machine-readable indicia The sizing parameter associated with the read indicia is then compared to the stored the dimensions of the downhole components to be handled. An automated response is then produced based on the comparison. The sized members can be gripping elements used in a spider or an elevator, jaws used on a power tong, or features disposed on a downhole tool.
G05B 19/4155 - Numerical control [NC], i.e. automatically operating machines, in particular machine tools, e.g. in a manufacturing environment, so as to execute positioning, movement or co-ordinated operations by means of programme data in numerical form characterised by programme execution, i.e. part programme or machine function execution, e.g. selection of a programme
G06K 19/06 - Record carriers for use with machines and with at least a part designed to carry digital markings characterised by the kind of the digital marking, e.g. shape, nature, code
G06K 19/07 - Record carriers with conductive marks, printed circuits or semiconductor circuit elements, e.g. credit or identity cards with integrated circuit chips
25.
SYSTEM AND METHOD FOR AUTOMATED CONFIGURATION OF HANDLING EQUIPMENT AND DOWNHOLE COMPONENTS
System and methods disclosed herein store sizing parameters for sized members used with downhole components and stores dimensions of the downhole components to be handled at the wellsite. The sizing parameter for a respective sized member defines how the respective sized member is sized for use with the downhole components. Machine-readable indicia are encoded with the sizing parameters and physically associated with the sized members. When handling a current downhole component, the sizing parameter associated with current sized member is determined by reading the machine-readable indicia. The sizing parameter associated with the read indicia is then compared to the stored the dimensions of the downhole components to be handled. An automated response is then produced based on the comparison. The sized members can be gripping elements used in a spider or an elevator, jaws used on a power tong, or features disposed on a downhole tool.
A wet-mate connection is used in a well and comprises first and second connection assemblies and an actuator. The first connection assembly includes at least one first connector for at least one first control line. The second connection assembly is configured to connect with the first connection assembly and includes at least one second connector for at least one second control line. The second connector is movable on the second connection assembly between a retracted condition and an extended condition. In the extended condition, the second connector can mate with the first connector to communicate the first and second control lines with one another. The actuator is disposed on the second connection assembly and is configured to move the second connector at least from the retracted condition to the extended condition.
A wet-mate connection is used in a well and comprises first and second connection assemblies and an actuator. The first connection assembly includes at least one first connector for at least one first control line. The second connection assembly is configured to connect with the first connection assembly and includes at least one second connector for at least one second control line. The second connector is movable on the second connection assembly between a retracted condition and an extended condition. In the extended condition, the second connector can mate with the first connector to communicate the first and second control lines with one another. The actuator is disposed on the second connection assembly and is configured to move the second connector at least from the retracted condition to the extended condition.
E21B 47/12 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
28.
APPARATUS AND METHODS FOR DEPLOYING SENSOR IN DOWNHOLE TOOL
A downhole assembly includes a tubular body having a bore and a downhole tool connected to the tubular body. The downhole assembly also includes a sensor assembly having a carrier and a sensor. A sensor adapter is used to couple the sensor assembly to the tubular body. The sensor adapter includes an adapter body disposed in the bore of the tubular body; an adapter shaft for connection with the carrier; and a plurality of channels formed between the adapter shaft and the adapter body.
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
E21B 23/03 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting the tools into, or removing the tools from, laterally offset landing nipples or pockets
29.
Synchronized Actuator Having Multiple Motors for Downhole Well Tool
A downhole tool, such an interval control valve, for use in a well has multiple motors and two drive assemblies to displace a yoke. A member, such as a sliding sleeve, of the downhole tool is connected to the yoke and can be actuated in response to the displacement of the yoke. The drive assemblies include first and second rotatable screws, and the yoke is disposed on the screws. Each motor can produce drive to rotate a respective screw. A respective gear is rotatable in association with at least the rotation of its associated screw. An intermediate gear is engaged between these two gears. The intermediate gear interconnects the rotation of the two screws, forcing them to rotate at the same speed. Likewise, the intermediate gear balances the drive of the motors, forcing the two screws to rotate at the same speed.
A variable-frequency drive includes a rectifier, a filter, an inverter, a capacitor bank, and control circuitry. The rectifier converts AC power from a power source to DC power on a DC bus for filtering by the filter. The inverter converts the DC power to three-phase AC power for output to the electric motor. The capacitor bank has one or more capacitors connected to the DC bus. The capacitor bank can store regenerative power on the DC bus from the inverter and can supply the stored DC power to the DC bus for conversion to the three-phase AC power to drive the electric motor. The control circuitry pre-charges the capacitor bank from the AC power of the power source. The control circuitry monitors one or more parameters of the variable-frequency drive and detects one or more fault conditions associated with the one or more monitored parameters.
H02P 29/024 - Detecting a fault condition, e.g. short circuit, locked rotor, open circuit or loss of load
H02J 7/00 - Circuit arrangements for charging or depolarising batteries or for supplying loads from batteries
H02J 7/34 - Parallel operation in networks using both storage and other DC sources, e.g. providing buffering
H02M 5/458 - Conversion of AC power input into AC power output, e.g. for change of voltage, for change of frequency, for change of number of phases with intermediate conversion into DC by static converters using discharge tubes or semiconductor devices to convert the intermediate DC into AC using devices of a triode or transistor type requiring continuous application of a control signal using semiconductor devices only
31.
Managing Regenerative Energy of Rod Pump System without Dynamic Braking Resistor
A variable-frequency drive includes a rectifier, a filter, an inverter, a capacitor bank, and control circuitry. The rectifier converts AC power from a power source to DC power on a DC bus for filtering by the filter. The inverter converts the DC power to three-phase AC power for output to the electric motor. The capacitor bank has one or more capacitors connected to the DC bus. The capacitor bank can store regenerative power on the DC bus from the inverter and can supply the stored DC power to the DC bus for conversion to the three-phase AC power to drive the electric motor. The control circuitry pre-charges the capacitor bank from the AC power of the power source. The control circuitry monitors one or more parameters of the variable-frequency drive and detects one or more fault conditions associated with the one or more monitored parameters.
H02P 27/08 - Arrangements or methods for the control of AC motors characterised by the kind of supply voltage using variable-frequency supply voltage, e.g. inverter or converter supply voltage using DC to AC converters or inverters with pulse width modulation
F04B 47/02 - Pumps or pumping installations specially adapted for raising fluids from great depths, e.g. well pumps the driving mechanisms being situated at ground level
H02P 25/032 - Reciprocating, oscillating or vibrating motors
32.
SYSTEM AND METHOD FOR VERIFICATION OF WELL SERVICE DESIGN
Systems and methods monitor equipment used in performing well services. Machine-readable indicia (e.g., RFID tags) for the equipment are encoded with coded identifiers, each of which includes information about product line, operational classification, and unique identification. The encoded indicia are physically associated with the equipment, and tracking information is associated in the system with the coded identifiers. The system compiles a design list to implement a given service using equipment. The system then remotely tracks the equipment using the coded identifiers of the encoded indicia. In particular, the equipment in the design list is dispatched to the site by verifying the encoded indicia for the equipment, a dispatched list of the encoded indicia is received for the equipment obtained at the site, and the dispatched list is verified against the design list. Additional tracking of the equipment can be performed with the coded identifiers and encoded indica.
Systems and methods monitor equipment used in performing well services. Machine-readable indicia (e.g., RFID tags) for the equipment are encoded with coded identifiers, each of which includes information about product line, operational classification, and unique identification. The encoded indicia are physically associated with the equipment, and tracking information is associated in the system with the coded identifiers. The system compiles a design list to implement a given service using equipment. The system then remotely tracks the equipment using the coded identifiers of the encoded indicia. In particular, the equipment in the design list is dispatched to the site by verifying the encoded indicia for the equipment, a dispatched list of the encoded indicia is received for the equipment obtained at the site, and the dispatched list is verified against the design list. Additional tracking of the equipment can be performed with the coded identifiers and encoded indica.
A sensor assembly can include a gyroscope, an accelerometer, and a housing assembly containing the gyroscope and the accelerometer. An axis of the gyroscope can be collinear with an axis of the accelerometer. A method of inspecting a well pumping unit can include attaching a sensor assembly to the pumping unit, recording acceleration versus time data, and in response to an amplitude of the acceleration versus time data exceeding a predetermined threshold, transforming the data to acceleration versus frequency data. A method of balancing a well pumping unit can include comparing peaks of acceleration versus rotational orientation data to peaks of acceleration due to circular motion, and adjusting a position of a counterweight, thereby reducing a difference between the peaks of acceleration due to circular motion and the peaks of the acceleration versus rotational orientation data for subsequent operation of the pumping unit.
Systems and methods are provided for evaluating a foamer for use in an oil and gas well for unloading of a liquid. The systems and methods provide for methods including: (a) combining (i) an aqueous phase, a hydrocarbon phase, or both an aqueous phase and a hydrocarbon phase in a predetermined proportion with (ii) a foamer to obtain a liquid, wherein the foamer is in a predetermined concentration in the liquid; (b) sparging the liquid with a gas at a predetermined gas flow rate to create a foam from at least some of the liquid and at least some of the gas; and (c) during or after the step of sparging, determining the amount of the liquid in the foam, wherein the step of determining is performed one or more times.
G01N 7/16 - Analysing materials by measuring the pressure or volume of a gas or vapour by allowing the material to emit a gas or vapour, e.g. water vapour, and measuring a pressure or volume difference by heating the material
E21B 43/16 - Enhanced recovery methods for obtaining hydrocarbons
G01N 33/00 - Investigating or analysing materials by specific methods not covered by groups
36.
SYSTEMS AND METHODS TO EVALUATE A FOAMER FOR UNLOADING LIQUID IN OIL AND GAS WELLS OF MATURE FIELDS
Systems and methods are provided for evaluating a foamer for use in an oil and gas well for unloading of a liquid. The systems and methods provide for methods including: (a) combining (i) an aqueous phase, a hydrocarbon phase, or both an aqueous phase and a hydrocarbon phase in a predetermined proportion with (ii) a foamer to obtain a liquid, wherein the foamer is in a predetermined concentration in the liquid; (b) sparging the liquid with a gas at a predetermined gas flow rate to create a foam from at least some of the liquid and at least some of the gas; and (c) during or after the step of sparging, determining the amount of the liquid in the foam, wherein the step of determining is performed one or more times.
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
E21B 49/00 - Testing the nature of borehole wallsFormation testingMethods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
E21B 21/14 - Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor using liquids and gases, e.g. foams
A tong positioning system includes a positioning device configured to move a tong assembly. The positioning device includes a first actuator, a second actuator, and a control attachment attachable to the positioning device. The control attachment includes a shutoff valve fluidly coupled to a hydraulic supply, a control valve block, and a control device. The control valve block includes a hydraulic input fluidly coupled to the shutoff valve, a hydraulic output fluidly coupled to a hydraulic return, a first valve fluidly coupled to the first actuator, the first valve configured to actuate the first actuator, and a second valve fluidly coupled to the second actuator, the second valve configured to actuate the second actuator. The control device is configured to control the first valve and to control the second valve to actuate the first and second actuators to move the tong assembly.
Methods comprising: injecting into a wellbore in a subterranean formation a multi-particle lost circulation material composition comprising a base fluid and a particle blend comprising substantially cylindrical particles and substantially spherical particles and wherein said particle blend comprises: degradable particles of at least three different sizes and wherein a first-sized particles and a second-sized particles are substantially cylindrical and a third-sized particles are substantially spherical.
C09K 8/504 - Compositions based on water or polar solvents
C09K 8/506 - Compositions based on water or polar solvents containing organic compounds
C09K 8/516 - Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
E21B 33/138 - Plastering the borehole wallInjecting into the formation
39.
METHODS OF USING MULTI-PARTICLE LOST CIRCULATION MATERIAL IN HIGHLY POROUS OR FRACTURED FORMATIONS
Methods comprising: injecting into a wellbore in a subterranean formation a multi-particle lost circulation material composition comprising a base fluid and a particle blend comprising substantially cylindrical particles and substantially spherical particles and wherein said particle blend comprises: degradable particles of at least three different sizes and wherein a first-sized particles and a second-sized particles are substantially cylindrical and a third-sized particles are substantially spherical.
A subsea assembly can include a pressure control device having an annular seal configured to seal off an annulus formed between an outer housing and a tubular string, a connector, and a guide configured to guide the tubular string into an internal flow passage extending through the subsea assembly, the pressure control device being connected between the connector and the guide. A method can include assembling a subsea assembly with a pressure control device and a connector, the pressure control device including an outer housing and an annular seal, lowering the subsea assembly through water from a rig to a subsea wellhead installation, connecting the subsea assembly to the subsea wellhead installation, and positioning a tubular string in the subsea assembly, so that the annular seal seals against an external surface of the tubular string, the tubular string being exposed to the water between the rig and the subsea assembly.
A pressure control assembly can include an outer housing and a rotating control device including a bearing assembly with a rotatable inner barrel, a pressure sensor and one or more magnetic field generators, and at least two seal elements configured to seal between the inner barrel and a tubular positioned in the pressure control assembly. A magnetic field detector secured to the outer housing is configured to receive signals from the magnetic field generators, the signals being indicative of outputs of the pressure sensor. A method can include securing a magnetic field detector to an outer housing, installing the rotating control device in the outer housing, the rotating control device comprising a rotatable inner barrel, a pressure sensor and multiple magnetic field generators, and transmitting signals indicative of outputs of the pressure sensor from the magnetic field generators to the magnetic field detector.
A pressure control assembly can include an outer housing and a rotating control device including a bearing assembly with a rotatable inner barrel, a pressure sensor and one or more magnetic field generators, and at least two seal elements configured to seal between the inner barrel and a tubular positioned in the pressure control assembly. A magnetic field detector secured to the outer housing is configured to receive signals from the magnetic field generators, the signals being indicative of outputs of the pressure sensor. A method can include securing a magnetic field detector to an outer housing, installing the rotating control device in the outer housing, the rotating control device comprising a rotatable inner barrel, a pressure sensor and multiple magnetic field generators, and transmitting signals indicative of outputs of the pressure sensor from the magnetic field generators to the magnetic field detector.
A pressure control assembly can include an outer housing and a rotating control device including a bearing assembly with a rotatable inner barrel, a pressure sensor and one or more magnetic field generators, and at least two seal elements configured to seal between the inner barrel and a tubular positioned in the pressure control assembly. A magnetic field detector secured to the outer housing is configured to receive signals from the magnetic field generators, the signals being indicative of outputs of the pressure sensor. A method can include securing a magnetic field detector to an outer housing, installing the rotating control device in the outer housing, the rotating control device comprising a rotatable inner barrel, a pressure sensor and multiple magnetic field generators, and transmitting signals indicative of outputs of the pressure sensor from the magnetic field generators to the magnetic field detector.
(1) Power-operated downhole tools for use in the oil and gas industry, namely, modular multi-function cement-through systems comprising cutters, mills, or spears for anchoring to a well casing.
An annulus flow control tool can include an inner mandrel with a longitudinal bypass flow path, a sleeve on the inner mandrel, the sleeve being displaceable on the inner mandrel between bypass open and bypass closed positions, and at least one annular seal carried externally on the sleeve. A method of controlling annulus flow can include connecting an annulus flow control tool in a tubular string, the annulus flow control tool including a bypass flow path and at least one external annular seal, deploying the tubular string into the well, sealingly engaging a well surface with the annular seal, flowing a fluid through the tubular string into the well, thereby causing another fluid in an annulus between the tubular string and the well surface to flow through the bypass flow path, and closing the bypass flow path, the annulus flow control tool thereby blocking flow through the annulus.
A method of determining viscosity can include connecting a bypass flow passage in parallel with a main flow passage, connecting a mass flowmeter and a variable flow restrictor in the bypass flow passage, and connecting at least one viscometer to the bypass flow passage. A rheology measurement apparatus can include a bypass flow passage connected in parallel with a main flow passage, a mass flowmeter connected in the bypass flow passage, and a pipe viscometer connected in the bypass flow passage. Another bypass flow passage may be connected in parallel with the main flow passage, with another mass flowmeter connected in the second bypass flow passage.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
G01N 11/08 - Investigating flow properties of materials, e.g. viscosity or plasticityAnalysing materials by determining flow properties by measuring flow of the material through a restricted passage, e.g. tube, aperture by measuring pressure required to produce a known flow
47.
VALVE ASSEMBLY FOR DOWNHOLE PUMP OF RECIPROCATING PUMP SYSTEM
A downhole pump used for a reciprocating pump includes a barrel and a plunger. The barrel couples to a tubing string and has a standing valve. The plunger couples to a rod string and has a traveling valve. One or both of the valves can include an assembly comprising a housing and an insert. The insert allowing for flow therethrough has a ball stop and a ball passage. Positioned in housing, one end of the insert engages a tapered sidewall in the housing. The insert is secured with metallic material metallurgically affixed between the insert and the housing. For example, brazing material can be brazed at the end of the insert to metallurgically affix the insert in the passage. A ball is positioned in the insert, and a seat is positioned adjacent an end of the insert. The assembly is then incorporated into components of the pump.
An annulus flow control tool can include an inner mandrel (44) with a longitudinal bypass flow path (64), a sleeve (52) on the inner mandrel (44), the sleeve being displaceable on the inner mandrel (44) between bypass open and bypass closed positions, and at least one annular seal (50) carried externally on the sleeve.
E21B 33/124 - Units with longitudinally-spaced plugs for isolating the intermediate space
E21B 34/00 - Valve arrangements for boreholes or wells
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
49.
NON-INTRUSIVE RHEOMETER FOR USE IN WELL OPERATIONS
A method of determining viscosity can include connecting a bypass flow passage in parallel with a main flow passage, connecting a mass flowmeter and a variable flow restrictor in the bypass flow passage, and connecting at least one viscometer to the bypass flow passage. A rheology measurement apparatus can include a bypass flow passage connected in parallel with a main flow passage, a mass flowmeter connected in the bypass flow passage, and a pipe viscometer connected in the bypass flow passage. Another bypass flow passage may be connected in parallel with the main flow passage, with another mass flowmeter connected in the second bypass flow passage.
G01N 11/04 - Investigating flow properties of materials, e.g. viscosity or plasticityAnalysing materials by determining flow properties by measuring flow of the material through a restricted passage, e.g. tube, aperture
G01N 11/08 - Investigating flow properties of materials, e.g. viscosity or plasticityAnalysing materials by determining flow properties by measuring flow of the material through a restricted passage, e.g. tube, aperture by measuring pressure required to produce a known flow
50.
Electronic limit barrier for hydraulic power tongs
A system includes hydraulic power tongs mounted to a rig floor and including a primary tong and one or more controls for operating the primary tong, an electronic limit barrier device including one or more sensors operable to determine a distance between the hydraulic power tongs and an operator on the rig floor, and a hydraulic control valve in communication with the electronic limit barrier device and fluidly coupled to the hydraulic power tongs. The electronic limit barrier device is programmed to compare the distance to a pre-defined cutoff distance, and release hydraulic fluid from the hydraulic power tongs upon determining that the distance is less than or equal to the pre-defined cutoff distance.
A long-stroke pumping unit includes a tower; a counterweight assembly movable along the tower; a crown mounted atop the tower; a sprocket supported by the crown and rotatable relative thereto; and a belt. The unit further includes a motor having a stator mounted to the crown and a rotor torsionally connected to the sprocket; and a sensor for detecting position of the counterweight assembly. The pumping unit may include a dynamic control system for controlling a speed of a motor.
F04B 49/20 - Control of, or safety measures for, machines, pumps, or pumping installations, not otherwise provided for in, or of interest apart from, groups by changing the driving speed
E21B 43/12 - Methods or apparatus for controlling the flow of the obtained fluid to or in wells
E21B 47/009 - Monitoring of walking-beam pump systems
An apparatus or cradle having top and bottom supports is used to assemble, transport, and deploy a bottom hole assembly. The cradle supports at least a whipstock and mill of the assembly during assembly and transport. At the rig, the assembly and at least the mill support are lifted, and a portion of the assembly is through a rotary table of the rig. The assembly is then supported on the rig by engaging a base of the cradle on the rotary table. A milling tool is connected to the mill of the assembly, and the assembly is disconnected from the at least one support of the cradle. The assembly and the milling tool can then be run through the rotary table for deployment downhole.
Control of a drilling system (10) drilling a wellbore (12) is improved using a hydraulics model corrected for pressure losses. A surface backpressure of the outlet and a standpipe pressure of the inlet are measured with sensors (240) in the system. An estimate of the standpipe pressure is calculated based integrating from the measured surface backpressure back to the inlet in the hydraulics model. The pressure loss increment in the hydraulics model is calculated based on a difference between the measured and estimated standpipe pressures. Meanwhile, a parameter in the drilling system is monitored during drilling so the parameter can be adjusted at least partially based on the hydraulics model corrected for the pressure loss.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
A method of utilizing a hydraulics model (48) with a well operation can include the steps of inputting well parameters to the hydraulics model, assigning nodes (70) to respective well locations, the hydraulics model being configured to determine corresponding pressures at the respective nodes, and unevenly spacing the nodes along a wellbore (14). A well equipment control system (40) for use with a subterranean well can include a hydraulics model (48) configured to determine pressures at respective nodes along a wellbore, the nodes being unevenly spaced along the wellbore, and an actuator (44) configured to actuate well equipment (42) at least in part based on the hydraulics model pressure determinations.
Control of a drilling system drilling a wellbore is improved using a hydraulics model corrected for pressure losses. A surface backpressure of the outlet and a standpipe pressure of the inlet are measured with sensors in the system. An estimate of the standpipe pressure is calculated based integrating from the measured surface backpressure back to the inlet in the hydraulics model. The pressure loss increment in the hydraulics model is calculated based on a difference between the measured and estimated standpipe pressures. Meanwhile, a parameter in the drilling system is monitored during drilling so the parameter can be adjusted at least partially based on the hydraulics model corrected for the pressure loss.
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 47/022 - Determining slope or direction of the borehole, e.g. using geomagnetism
A debris catcher assembly includes a debris filter assembly having a selectively operable valve. such as a rupture disk, to allow a secondary flow path should the debris filter assembly become clogged with debris.
E21B 27/00 - Containers for collecting or depositing substances in boreholes or wells, e.g. bailers for collecting mud or sandDrill bits with means for collecting substances, e.g. valve drill bits
E21B 37/00 - Methods or apparatus for cleaning boreholes or wells
E21B 43/34 - Arrangements for separating materials produced by the well
E21B 43/38 - Arrangements for separating materials produced by the well in the well
A convertible valve assembly includes an upper and lower plunger valve, connected to one another to operate in unison, and a retainer assembly for holding the valves in a bi-directional configuration and releasing the valves to a unidirectional configuration upon application of a downhole hydraulic pressure.
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
A convertible valve assembly has an upper and lower plunger valve connected to one another so that they reciprocate together. A retainer assembly holds the valves in a bi-directional configuration, allowing fluid flow in both directions through the valves. The retainer assembly then releases the valves to a unidirectional configuration upon application of a downhole hydraulic pressure, so that fluid can flow only one direction through the valve assembly.
A debris catcher assembly includes a debris filter assembly having a selectively operable valve, such as a rupture disk, to allow a secondary flow path should the debris filter assembly become clogged with debris.
E21B 27/00 - Containers for collecting or depositing substances in boreholes or wells, e.g. bailers for collecting mud or sandDrill bits with means for collecting substances, e.g. valve drill bits
E21B 21/06 - Arrangements for treating drilling fluids outside the borehole
E21B 34/06 - Valve arrangements for boreholes or wells in wells
60.
APPARATUS AND METHOD TO FORM CENTRALIZER BLADES ON WELLBORE TUBULAR
A tubular is prepared for downhole use to include integrated centralizer feature disposed thereon. Blade elements are disposed about a surface of the tubular. An interconnection, such as a band, connected between the blade elements can be used to wrap them circumferentially about the tubular. The blade elements are then affixed to the surface of the tubular to produce the integrated centralizer features by coating a spray welding material over at least a portion of the plurality of blade elements and over at least an adjacent portion of the surface of the tubular. The blade elements can be hollow vanes or fins so they are collapsible when a restriction is encountered downhole to avoid a stuck pipe situation.
A system (10) can include a tong assembly (12), a tong positioning device (28) configured to adjust a vertical height of the tong assembly, one or more calibration marker (42) secured to the tong assembly, and a camera (38) disposed at a camera position at which the calibration marker is within a field of view (40) of the camera. A method of vertically positioning a tong assembly can include taking a digital image of a tong assembly and one or more calibration marker, identifying a pixel position of the calibration marker in the digital image, and adjusting a height of the tong assembly based in part on the pixel position of the calibration marker.
A system can include a tong assembly, a tong positioning device configured to adjust a vertical height of the tong assembly, one or more calibration marker secured to the tong assembly, and a camera disposed at a camera position at which the calibration marker is within a field of view of the camera. A method of vertically positioning a tong assembly can include taking a digital image of a tong assembly and one or more calibration marker, identifying a pixel position of the calibration marker in the digital image, and adjusting a height of the tong assembly based in part on the pixel position of the calibration marker.
G06V 10/44 - Local feature extraction by analysis of parts of the pattern, e.g. by detecting edges, contours, loops, corners, strokes or intersectionsConnectivity analysis, e.g. of connected components
G06V 10/56 - Extraction of image or video features relating to colour
A tubular shear assembly for use with a subterranean well can include a tubular shear device configured to shear a tubular string that extends into the well. The tubular shear device can include a body, a fixed shear jaw, and a rotary shear jaw configured to rotate relative to the body and the fixed shear jaw to shear the tubular string. A method of retrieving a tubular string from a subterranean well can include displacing a tubular shear device, including positioning the tubular string between a fixed shear jaw of the tubular shear device and a rotary shear jaw of the tubular shear device, and rotating the rotary shear jaw relative to the fixed shear jaw, thereby shearing the tubular string.
A tubular shear assembly for use with a subterranean well can include a tubular shear device configured to shear a tubular string that extends into the well. The tubular shear device can include a body, a fixed shear jaw, and a rotary shear jaw configured to rotate relative to the body and the fixed shear jaw to shear the tubular string. A method of retrieving a tubular string from a subterranean well can include displacing a tubular shear device, including positioning the tubular string between a fixed shear jaw of the tubular shear device and a rotary shear jaw of the tubular shear device, and rotating the rotary shear jaw relative to the fixed shear jaw, thereby shearing the tubular string.
E21B 29/00 - Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windowsDeforming of pipes in boreholes or wellsReconditioning of well casings while in the ground
E21B 19/00 - Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrickApparatus for feeding the rods or cables
65.
Apparatus and methods for deploying sensor in downhole tool
A downhole assembly includes a tubular body having a bore and a downhole tool connected to the tubular body. The downhole assembly also includes a sensor assembly having a carrier and a sensor. A sensor adapter is used to couple the sensor assembly to the tubular body. The sensor adapter includes an adapter body disposed in the bore of the tubular body; an adapter shaft for connection with the carrier; and a plurality of channels formed between the adapter shaft and the adapter body.
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
E21B 23/03 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting the tools into, or removing the tools from, laterally offset landing nipples or pockets
66.
Apparatus and method to form centralizer blades on wellbore tubular
A tubular is prepared for downhole use to include integrated centralizer feature disposed thereon. Blade elements are disposed about a surface of the tubular. An interconnection, such as a band, connected between the blade elements can be used to wrap them circumferentially about the tubular. The blade elements are then affixed to the surface of the tubular to produce the integrated centralizer features by coating a spray welding material over at least a portion of the plurality of blade elements and over at least an adjacent portion of the surface of the tubular. The blade elements can be hollow vanes or fins so they are collapsible when a restriction is encountered downhole to avoid a stuck pipe situation.
Methods, tools, and systems for determining two-phase borehole fluid holdup using pulsed neutron (PN) measurements are described. Embodiments of the techniques involve using formation models that are extended/extrapolated (or remodeled) to a value of 100 p.u., which correlates to the borehole environment where there is no formation matrix present. Those models can be used to determine the fractional relationship of oil and water in the borehole based on carbon and oxygen ratios provided by the PN measurement.
E21B 49/08 - Obtaining fluid samples or testing fluids, in boreholes or wells
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
68.
PULSED NEUTRON DETERMINATION OF BOREHOLE FLUID HOLD-UP
Methods, tools, and systems for determining two-phase borehole fluid holdup using pulsed neutron (PN) measurements are described. Embodiments of the techniques involve using formation models that are extended/ extrapolated (or remodeled) to a value of 100 p.u., which correlates to the borehole environment where there is no formation matrix present. Those models can be used to determine the fractional relationship of oil and water in the borehole based on carbon and oxygen ratios provided by the PN measurement.
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
A cementing operation cements casing in a borehole. A bottom plug pumped down the casing ahead of cement lands at a float valve. Circulation of the cement is established through the bottom plug to a shoe track downhole from the float valve. A top plug pumped down the casing behind the cement lands on the bottom plug. An internal component of the float valve is released by building-up pressure in the casing behind the internal component up to a release threshold. The internal component can latch at the shoe. At least some of the cement in the shoe track is displaced from the casing's shoe to the borehole by pumping the plugs and the internal component to the shoe. With the cement displaced out of the shoe track, the time required to drill out the assembly can be greatly reduced.
E21B 33/16 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement chargePlugs therefor
70.
Float valve producing turbulent flow for wet shoe track
A float tool is used for controlling flow in tubing. The float tool comprises a housing, at least one valve, and at least one inset. The housing is configured to install on the tubing and has a longitudinal bore therethrough. The at least one valve is disposed in the longitudinal bore. The at least one valve is configured to allow the flow in a downbore direction through the longitudinal bore and is configured to prevent flow in an upbore direction through the longitudinal bore. The at least one inset is disposed in the longitudinal bore and is disposed downbore of the at least one valve. The at least one inset defines an orifice therethrough. The orifice has one or more vanes angled relative to the longitudinal bore. The one or more vanes are configured to produce turbulence in the flow in the downbore direction through the longitudinal bore.
E21B 33/16 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement chargePlugs therefor
Methods and systems for determining bulk density and/or neutron porosity of a formation are described herein. The methods and systems use a pulsed neutron (PN) tool and may be performed with a tool having a single gamma detector though tools with multiple detectors may be used as well. The PN tool may be a geochemical logging tool. The methods and systems involve partitioning the time spectrum into pluralities of bins that are indicative of non-clay mineral elements and of shale/clay to the overall bulk density.
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
72.
Determination of formation water salinity using time resolved chlorine capture gamma spectroscopy
Methods and systems for determining formation salinity using pulsed neutron (PN) tools are described. Embodiments of the described methods involve binning chlorine yields or chlorine count rates arising from capture events into early and late capture regimes, which may be used to attribute the events to either the borehole or the formation.
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
A flow measurement apparatus can include a main flow passage having a flowmeter, a bypass flow passage connected in parallel with the main flow passage, the bypass flow passage having a flow restrictor, a mass flowmeter, and at least one sensor configured to measure a pressure differential across the mass flowmeter, and a control system configured to determine at least one rheological parameter of a non-Newtonian fluid based on outputs of the sensor and the mass flowmeter. A method for measuring a rheological fluid property of a non-Newtonian fluid can include measuring a volumetric flow rate through a flowmeter connected in a main flow passage, measuring a differential pressure across a mass flowmeter in a bypass flow passage, measuring a mass flow rate through the bypass flow passage, and determining the rheological fluid property from the differential pressure and the mass flow rate through the bypass flow passage.
E21B 21/08 - Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
E21B 47/10 - Locating fluid leaks, intrusions or movements
G01F 1/76 - Devices for measuring mass flow of a fluid or a fluent solid material
G01F 1/84 - Coriolis or gyroscopic mass flowmeters
G01F 1/88 - Indirect mass flowmeters, e.g. measuring volume flow and density, temperature, or pressure with differential-pressure measurement to determine the volume flow
G01N 11/04 - Investigating flow properties of materials, e.g. viscosity or plasticityAnalysing materials by determining flow properties by measuring flow of the material through a restricted passage, e.g. tube, aperture
74.
DETERMINATION OF NEUTRON POROSITY AND BULK DENSITY FROM A PULSED NEUTRON TOOL
Methods and systems for determining bulk density and/or neutron porosity of a formation are described herein. The methods and systems use a pulsed neutron (PN) tool and may be performed with a tool having a single gamma detector though tools with multiple detectors may be used as well. The PN tool may be a geochemical logging tool. The methods and systems involve partitioning the time spectrum into pluralities of bins that are indicative of non-clay mineral elements and of shale/clay to the overall bulk density.
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
75.
DETERMINATION OF FORMATION WATER SALINITY USING TIME RESOLVED CHLORINE CAPTURE GAMMA SPECTROSCOPY
Methods and systems for determining formation salinity using pulsed neutron (PN) tools are described. Embodiments of the described methods involve binning chlorine yields or chlorine count rates arising from capture events into early and late capture regimes, which may be used to attribute the events to either the borehole or the formation.
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
76.
Extended reach power track tool used on coiled tubing
A traction tool is operable with fluid flow from coiled tubing for use in a wellbore. The traction tool includes a mandrel, a driver, at least one piston, and a motor. The driver is rotatably disposed on the mandrel and can be movable between retracted and extended conditions when the at least one piston is actuated. The driver in the extended condition is configured to engage inside the wellbore. The piston is adjacent to the driver and is actuated by the fluid flow from the mandrel. The motor is also actuated by the fluid flow from the mandrel. The motor imparts rotation to the piston and the drive, which can be supported by bearings on the tool's mandrel. Tracks on the driver arranged at an angle transverse to a longitudinal axis of the tool allow the rotating driver to spiral inside the wellbore and advance the traction tool.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
77.
EXTENDED REACH POWER TRACK TOOL USED ON COILED TUBING
A traction tool (100a) is operable with fluid flow from on coiled tubing (20) for use in a wellbore (10). The traction tool includes a mandrel (102), a driver (110), at least one piston (120a-b), and a motor (140). The driver is rotatably disposed on the mandrel and can be movable between retracted and extended conditions when the at least one piston is actuated. The driver (110) in the extended condition is configured to engage inside the wellbore. The piston (120a-b) is adjacent to the driver and is actuated by the fluid flow from the mandrel. The motor (140) is also actuated by the fluid flow from the mandrel. The motor (140) imparts rotation to the piston and the drive, which can be supported by bearings (129b) on the tool's mandrel. Tracks (116) on the driver arranged at an angel transverse to a longitudinal axis of the tool allow the rotating driver to spiral inside the wellbore and advance the traction tool.
E21B 17/20 - Flexible or articulated drilling pipes
E21B 19/22 - Handling reeled pipe or rod units, e.g. flexible drilling pipes
E21B 23/00 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
E21B 23/14 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for displacing a cable or a cable-operated tool, e.g. for logging or perforating operations in deviated wells
78.
METHOD FOR COUNTING RESTRICTIONS IN A SUBTERRANEAN WELLBORE
A tool counts the number of radial restrictions or seats in a series of frac valves along a completion string. At a pre-selected count, the tool radially expands a landing mechanism and lands on the next-reached frac valve.
E21B 43/267 - Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 47/01 - Devices for supporting measuring instruments on drill bits, pipes, rods or wirelinesProtecting measuring instruments in boreholes against heat, shock, pressure or the like
79.
Method for counting restrictions in a subterranean wellbore
A tool counts the number of radial restrictions or seats in a series of frac valves along a completion string. At a pre-selected count, the tool radially expands a landing mechanism and lands on the next-reached frac valve.
E21B 43/26 - Methods for stimulating production by forming crevices or fractures
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 47/09 - Locating or determining the position of objects in boreholes or wellsIdentifying the free or blocked portions of pipes
A completion string for running gas-lift operations in a hydrocarbon well has a bypass string with a central bore for flowing production fluids to the surface and an annular passageway for flowing gas-lift gas downwards to a gas-lift assembly in the wellbore.
A completion string for running gas-lift operations in a hydrocarbon well, where a portion of the wellbore is compromised and unable to effectively contain gas for a gas-lift operation, has a bypass string with a central bore for flowing production fluids to the surface and an annular passageway for flowing gas-lift gas downwards to a gas-lift assembly in the wellbore.
Systems and methods for diagnosis of a water source of a water production problem in a well include: measuring flow and water/oil ratio (WOR) of a fluid mixture produced from a well; accepting the measured flow and the WOR over a period of time; calculating the derivative in time of WOR (WOR') over the period of time; accepting a selection of or making a comparison of the WOR or WOR' over time to a particular WOR or WOR' case history from a library of WOR and WOR' case histories that correlate with various types of water sources in a library of potential water sources; accepting an additional type of information about the well selected from the group consisting of reservoir properties, completion history, production history, injection history, and interventions history; and weighting and scoring to suggest a diagnosis of a likely water source from the library of potential water sources.
Systems and methods for diagnosis of a water source of a water production problem in a well include: measuring flow and water/oil ratio (WOR) of a fluid mixture produced from a well; accepting the measured flow and the WOR over a period of time; calculating the derivative in time of WOR (WOR′) over the period of time; accepting a selection of or making a comparison of the WOR or WOR′ over time to a particular WOR or WOR′ case history from a library of WOR and WOR′ case histories that correlate with various types of water sources in a library of potential water sources; accepting an additional type of information about the well selected from the group consisting of reservoir properties, completion history, production history, injection history, and interventions history; and weighting and scoring to suggest a diagnosis of a likely water source from the library of potential water sources.
A method of injecting gas into a well can include flowing the gas through a gas flow passage extending through a housing connected to a wellhead installation, the gas thereby flowing through the wellhead installation and into an annulus in the well, and maintaining fluid pressure applied to a piston of a gas injection valve while the gas flows into the annulus. A gas injection system can include a housing having a gas flow passage extending longitudinally through the housing, and being configured to connect to a wellhead installation, and a gas injection valve including a pivotably mounted flapper closure member. The flapper closure member in an open position permits gas flow between the gas flow passage and the wellhead installation, and the flapper closure member in a closed position prevents the gas flow from the wellhead installation through the gas flow passage.
A method of injecting gas into a well can include flowing the gas through a gas flow passage extending through a housing connected to a wellhead installation, the gas thereby flowing through the wellhead installation and into an annulus in the well, and maintaining fluid pressure applied to a piston of a gas injection valve while the gas flows into the annulus. A gas injection system can include a housing having a gas flow passage extending longitudinally through the housing, and being configured to connect to a wellhead installation, and a gas injection valve including a pivotably mounted flapper closure member. The flapper closure member in an open position permits gas flow between the gas flow passage and the wellhead installation, and the flapper closure member in a closed position prevents the gas flow from the wellhead installation through the gas flow passage.
A downhole tool, such an interval control valve, for use in a well has multiple motors and two drive assemblies to displace a yoke. A member, such as a sliding sleeve, of the downhole tool is connected to the yoke and can be actuated in response to the displacement of the yoke. The drive assemblies include first and second rotatable screws, and the yoke is disposed on the screws. Each motor can produce drive to rotate a respective screw. A respective gear is rotatable in association with at least the rotation of its associated screw. An intermediate gear is engaged between these two gears. The intermediate gear interconnects the rotation of the two screws, forcing them to rotate at the same speed. Likewise, the intermediate gear balances the drive of the motors, forcing the two screws to rotate at the same speed.
A downhole tool, for use in a well has multiple motors (160a, 160b) and two drive assemblies (110a, 110b) to displace a yoke (120). A member, such as a sliding sleeve (60), of the downhole tool is connected to the yoke and can be actuated in response to the displacement of the yoke. The drive assemblies include first and second rotatable screws (112a, 112b), and the yoke is disposed on the screws. Each motor can produce drive to rotate a respective screw. A respective gear (152a, 152b) is rotatable in association with at least the rotation of its associated screw. An intermediate gear (156) is engaged between these two gears. The intermediate gear interconnects the rotation of the two screws forcing them to rotate at the same speed. Likewise, the intermediate gear balances the drive of the motors forcing the two screws to rotate at the same speed.
E21B 23/04 - Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells operated by fluid means, e.g. actuated by explosion
E21B 34/06 - Valve arrangements for boreholes or wells in wells
Power-operated downhole tools for use in the oil and gas industry, namely, modular multi-function cement-through systems comprising cutters, mills, or anchors
89.
Pulsed neutron monitoring of carbon dioxide in reservoirs
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
90.
PULSED NEUTRON MONITORING OF CARBON DIOXIDE IN RESERVOIRS
G01V 5/10 - Prospecting or detecting by the use of ionising radiation, e.g. of natural or induced radioactivity specially adapted for well-logging using primary nuclear radiation sources or X-rays using neutron sources
A gravel pack assembly for a borehole has first and second joints and a foil. The basepipes of the joints connect end-to-end, and both of the basepipes have filters for filtering fluid passage from a borehole into bores of the basepipes. Transport tubes are disposed along the first and second joint, and a jumper tube expands across the connected ends of the basepipes and connects the transport tubes together. The foil encloses an area across the connected ends. The foil has an external surface defining an annulus thereabout with the borehole. The foil has end rings abutting the filters of the joints. At least a section of the foil leaks fluid from the borehole to the area enclosed by the foil, and at least a filter portion of the assembly filters the leaked fluid from the area to at least one of the first and second bores.
A plug for use in a wellbore has a piston that is movable on a body. A control valve is disposed in communication between the wellbore and a piston chamber and can capture wellbore pressure in the piston chamber. A closure on the body can transition from a closed condition to an open condition relative to the port in response to the movement of the piston. A fixture releasably holds the closure in the closed condition on the body. The fixture releases in response an increased pressure differential on the piston above an initial pressure differential between the captured chamber pressure and the wellbore pressure.
E21B 33/16 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement chargePlugs therefor
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
E21B 34/14 - Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
E21B 47/117 - Detecting leaks, e.g. from tubing, by pressure testing
A plug assembly having valve chamber chargeable with pressure from above or below the plug assembly. The charged chamber is used to selectively move an external sleeve to open fluid communication between the tubular above and below the plug assembly.
E21B 33/16 - Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes using plugs for isolating cement chargePlugs therefor
E21B 34/10 - Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
E21B 47/117 - Detecting leaks, e.g. from tubing, by pressure testing
94.
NESTED SPLICE TUBES FOR INTEGRATING SPOOLABLE GAUGES WITH DOWNHOLE CABLES
A fiber optic cable conducts optical fiber to downhole gauges in a wellbore. Cable connections are used to protect splicing of the optical fiber between cable sections and the gauges. The cable connection includes adjoining tubes, which have passages for the optical fiber. The tubes are nested together and enclose the splicing of the optical fiber. A cable-end tube is affixed to a section of the cable with the passage overlaying a jacket of the cable, and a gauge-end tube is affixed to an end of the downhole gauge with the passage overlaying the end of the downhole gauge. At least one spanning tube has ends that are affixed nested inside the passages of the adjoining ones of the tubes. The cable connections allow the cable and gauges to be wound on a spool or reel for installing into the wellbore.
G02B 6/255 - Splicing of light guides, e.g. by fusion or bonding
E21B 47/135 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range using light waves, e.g. infrared or ultraviolet waves
95.
Nested splice tubes for integrating spoolable gauges with downhole cables
A fiber optic cable conducts optical fiber to downhole gauges in a wellbore. Cable connections are used to protect splicing of the optical fiber between cable sections and the gauges. The cable connection includes adjoining tubes, which have passages for the optical fiber. The tubes are nested together and enclose the splicing of the optical fiber. A cable-end tube is affixed to a section of the cable with the passage overlaying a jacket of the cable, and a gauge-end tube is affixed to an end of the downhole gauge with the passage overlaying the end of the downhole gauge. At least one spanning tube has ends that are affixed nested inside the passages of the adjoining ones of the tubes. The cable connections allow the cable and gauges to be wound on a spool or reel for installing into the wellbore.
E21B 47/135 - Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. of radio frequency range using light waves, e.g. infrared or ultraviolet waves
G02B 6/255 - Splicing of light guides, e.g. by fusion or bonding
G02B 6/44 - Mechanical structures for providing tensile strength and external protection for fibres, e.g. optical transmission cables
A method for use with a subterranean well can include positioning an x-ray unit so that x-rays emitted by the x-ray unit scan a tubular string, displacing the tubular string relative to the x-ray unit, and identifying a threaded connection in the tubular string. A system can include a torque application device configured to apply torque to a threaded connection in a tubular string, and an x-ray unit configured to project x-rays toward the tubular string.
G01N 23/04 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by transmitting the radiation through the material and forming images of the material
G01N 23/083 - Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups , or by transmitting the radiation through the material and measuring the absorption the radiation being X-rays
97.
AGENT FILE REFERENCE: X-RAY IDENTIFICATION OF CONNECTIONS IN A TUBULAR STRING
A method for use with a subterranean well can include positioning an x-ray unit so that x-rays emitted by the x-ray unit scan a tubular string, displacing the tubular string relative to the x-ray unit, and identifying a threaded connection in the tubular string. A system can include a torque application device configured to apply torque to a threaded connection in a tubular string, and an x-ray unit configured to project x-rays toward the tubular string.
E21B 19/16 - Connecting or disconnecting pipe couplings or joints
E21B 44/00 - Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systemsSystems specially adapted for monitoring a plurality of drilling variables or conditions
98.
AGENT FILE REFERENCE:REAL TIME SHOULDER POINT DETERMINATION IN THREADED CONNECTION MAKE-UP
A method of controlling make-up of a threaded connection can include training an artificial intelligence, inputting data to the artificial intelligence during the threaded connection make-up, the artificial intelligence thereby determining a shoulder point during the threaded connection make-up, and controlling application of torque to the threaded connection, based in part on the determined shoulder point. A system for controlled make-up of a threaded connection can include a torque application device configured to apply torque and rotation to the threaded connection, and a control system comprising a controller and an artificial intelligence. The controller may be configured to control operation of the torque application device, and the artificial intelligence may be adapted to determine a shoulder point of the threaded connection during the make-up of the threaded connection.
A method of controlling make-up of a threaded connection can include training an artificial intelligence, inputting data to the artificial intelligence during the threaded connection make-up, the artificial intelligence thereby determining a shoulder point during the threaded connection make-up, and controlling application of torque to the threaded connection, based in part on the determined shoulder point. A system for controlled make-up of a threaded connection can include a torque application device configured to apply torque and rotation to the threaded connection, and a control system comprising a controller and an artificial intelligence. The controller may be configured to control operation of the torque application device, and the artificial intelligence may be adapted to determine a shoulder point of the threaded connection during the make-up of the threaded connection.
E21B 17/042 - CouplingsJoints between rod and bit, or between rod and rod threaded
G05B 13/02 - Adaptive control systems, i.e. systems automatically adjusting themselves to have a performance which is optimum according to some preassigned criterion electric
100.
AGENT FILE REFERENCE:CASING CONNECTION MAKE-UP WITH TOP DRIVE AND CASING RUNNING TOOL
A method of running a casing string (16) into a subterranean well that includes connecting a casing running tool (18) to a top drive (12), thereby enabling transmission of torque and rotation outputs of the top drive (12) to the casing running tool (18), connecting a casing string section (16a) to the casing running tool (18), threading an end of the casing string section (16a) to another casing string section (16b), thereby forming a connection between the casing string sections (16a, 16b), and controlling the torque and rotation outputs of the top drive (12), based on at least one indication of torque level applied to the connection from the top drive (12) via the casing running tool (18).
