Michael K Strachan

8274399, Sep 25, 2012

Nov 30, 2007

12/741490

Michael Strachan - Spring TX, US
Martin Paulk - Houston TX, US

Halliburton Energy Services Inc. - Houston TX

G01V 3/00

3408536, 34087002

A drilling system has multiple cutting structures, including a bit and one or more secondary cutting structures. A method balances the rate of penetration of the drilling system and the wear on the cutting structures by controlling weight on bit and RPM. The method includes calculating a predicted rate of penetration for the bit, using in the calculation the current predicted wear on the bit and the properties of the rock to be penetrated by the bit. The method includes calculating a predicted rate of penetration for at least one of the one or more secondary cutting structures, using in the calculation the current predicted wear on the secondary cutting structure and the properties of the rock to be penetrated by the secondary cutting structure. The method includes determining the slowest rate of penetration among those calculated for the bit and at least one the one or more secondary cutting structures. The method includes calculating the weight on bit and RPM for each of the bit and at least one of the one or more secondary cutting structures to substantially match the determined slowest rate of penetration.

20090321139, Dec 31, 2009

Feb 1, 2008

12/525346

Michael J. Strachan - The Woodlands TX, US

E21B 10/44
E21B 7/04
E21B 10/42
E21B 7/08

175 61, 175426, 175394

A drill bit comprising: a cutting section comprising gage cutters, wherein in the cutting section is a first end of the bit, and wherein the cutting section has a full gage diameter; a heel section comprising a blade, wherein the heel section is at an end of the drill bit opposite the cutting section, and wherein a diameter of the heel section is a full gage diameter, wherein the blade has a high spiral around the drill bit; and a clearance section between the cutting and heel sections, wherein the clearance section comprises a diameter less than full gage, and wherein clearance section extends from the gage cutters of the cutting section to the blade of the heel section.

20110174541, Jul 21, 2011

Aug 17, 2009

13/122149

Michael John Strachan - Spring TX, US
Cili Sun - Sugar Land TX, US

Halliburton Energy Services, Inc. - Houston TX

E21B 44/00
E21B 44/02
G06F 19/00

175 27, 175 24, 702 9

A system for drilling a well comprises a drill string in a wellbore having a bit at a distal end thereof. At least one sensor measures a drilling parameter. A computer controller has a set of instructions stored therein to process the measured drilling parameter over a drilled interval to calculate, in substantially real time, an updated friction slope and an updated worn bit slope and to calculate an updated drilling parameter for at least a portion of the well-based on the updated friction slope and the updated worn bit slope.

20130008648, Jan 10, 2013

Mar 23, 2011

13/635490

James Randolph Lovorn - Tomball TX, US
Derrick Winston Lewis - Conroe TX, US
Daniel David Gleitman - Houston TX, US
Michael John Strachan - Spring TX, US
Clive D. Menezes - Conroe TX, US

Halliburton Energy Services, Inc. - Houston TX

E21B 34/06
E21B 21/00
E21B 47/00

16625001, 166316, 166 66, 166 53

A method for modifying a return fluid in a wellbore comprises disposing at least one controllable flow restrictor along a drill string in the wellbore. At least one parameter of interest is determined at at least one location along an annulus in the wellbore. Controllably actuating the at least one flow restrictor to modify a local property of a return fluid in the annulus based at least in part on the measured parameter of interest.

20210381323, Dec 9, 2021

Jun 2, 2021

17/336922

- Houston TX, US
Michael John Strachan - Houston TX, US
John Kenneth Snyder - Houston TX, US

E21B 17/10

Provided is a stabilizer for use in a wellbore. The stabilizer, in one example, includes a downhole tubular coupleable to a downhole conveyance in a wellbore. In accordance with this example, the stabilizer additionally includes two or more helical wellbore stabilizing elements extending radially outward from the downhole component, the two or more helical wellbore stabilizing elements shaped such that an annular flow area between leading edges of adjacent helical wellbore stabilizing elements and between trailing edges of adjacent helical wellbore stabilizing elements is variable along at least a portion of a length (L) of the two or more helical wellbore stabilizing elements, and such that an unobstructed axial flow path exists between the adjacent helical wellbore stabilizing elements along the length (L).

20190234166, Aug 1, 2019

Apr 9, 2019

16/379586

- Houston TX, US
Michael J. Strachan - Conroe TX, US

E21B 31/113
F16K 31/04
F16K 3/08
E21B 31/107
E21B 21/10
E21B 34/06

An apparatus and method for drilling is disclosed, including a drill string with at least one jar and one reaction valve. Drilling fluid flows through the reaction valve. The reaction valve is selectively throttled, which creates a differential pressure across the valve seat. The differential pressure creates an axial force that is transferred to the jar, which aids in cocking or firing the jar. In an embodiment, a reaction valve throttles downward fluid flow to create a downward compressional force on the jar, while in another embodiment, a reaction valve throttles upward fluid flow to create an upward tensile force on the jar. Upward and downward fluid flow may be alternatively throttled for alternately firing the jar upwards and downwards. A bypass valve may be included in the drill string for establishing a drilling fluid flow path when such may be otherwise obstructed by foreign matter in the wellbore.

20170067306, Mar 9, 2017

Apr 18, 2014

15/123211

- Houston TX, US
Michael J. Strachan - Conroe TX, US

E21B 31/113
E21B 34/06

An apparatus and method for drilling is disclosed, including a drill string with at least one jar and one reaction valve. Drilling fluid flows through the reaction valve. The reaction valve is selectively throttled, which creates a differential pressure across the valve seat. The differential pressure creates an axial force that is transferred to the jar, which aids in cocking or firing the jar. In an embodiment, a reaction valve throttles downward fluid flow to create a downward compressional force on the jar, while in another embodiment, a reaction valve throttles upward fluid flow to create an upward tensile force on the jar. Upward and downward fluid flow may be alternatively throttled for alternately firing the jar upwards and downwards. A bypass valve may be included in the drill string for establishing a drilling fluid flow path when such may be otherwise obstructed by foreign matter in the wellbore.

20170037685, Feb 9, 2017

Apr 29, 2014

15/035181

- Houston TX, US
Michael J. Strachan - Conroe TX, US

E21B 7/06
E21B 4/04
E21B 4/16
E21B 44/00
E21B 17/00
E21B 45/00
E21B 44/04
E21B 47/024
E21B 4/02
E21B 10/00

A system and method for drilling is disclosed, the system including a drill string with at least one drill pipe, a bottom hole assembly and a drill bit. The bottom hole assembly includes a downhole mud motor for rotating the drill bit, and a steering motor coupled between the mud motor and the drill pipe. The downhole mud motor includes a bent housing. The drill pipe is continuously rotated to minimize friction, regardless of whether the drill bit is turned using rotary drilling or drilling with the downhole mud motor. Tool face orientation may be controlled by operating the steering motor at the drill pipe speed, but in an opposite rotational direction to thereby hold the mud motor and bent housing stationary with respect to the formation. Steering motor speed may be increased or decreased to adjust tool face orientation.