Halliburton Energy Services, Inc.

Nuno Da Silva

Stephan Regnard

Olivier Dupont

Olivier Mageren

Nicolas Luyckx

Luis Enrique Quintana Martinez

Ludovic Delmar

Valerie Sillen

Valérie Sillen

Didier Rousseau

Daniel Ruiz Romera

An example method for dynamic wear prediction for a drill bit with a cutting structure may include receiving at a processor of an information handling system an unworn profile of the cutting structure and a diamond distribution of the cutting structure. The diamond distribution may include a three-dimensional diamond distribution characterized by radial and axial position on the drill bit. The method may include calculating a final predicted wear profile of the cutting structure based, at least in part, on the unworn profile and the diamond distribution. The method also may include calculating iterations of intermediary wear profiles based, at least in part, on the previous wear profile and the diamond distribution. The final predicted wear profile may indicate a fully worn portion of the cutting structure. A usable life for the drill bit may be determined based, at least in part, on the final predicted wear profile.

Dynamic wear prediction for fixed cutter drill bits

The present disclosure provides a method of forming an inner barrel assembly by installing a fluid collection liner including a pre-formed porous material that is able to retain a reservoir fluid in an inner barrel to form an inner barrel assembly. It also provides an inner barrel assembly including an inner barrel and a fluid collection liner disposed in the inner barrel, the fluid collection liner comprising a plurality of sections of pre-formed porous material that are able to retain at least one reservoir fluid. It further provides an inner barrel assembly including a segment of an inner barrel isolated from a bottom hole assembly and a fluid collection liner disposed in the inner barrel, the fluid collection liner including a pre-formed porous material that is able to retain a reservoir fluid.

Inner barrel assembly for recovery of reservoir fluids from a core sample

A method for designing a core bit to control and reduce the cutting forces acting on a core of rock is disclosed. The method includes generating a model of a core bit including a plurality of cutting elements on a plurality of blades. The method may additionally include simulating a coring operation with the model of the core bit. The method may further include calculating at least one force vector generated by at least one of the plurality of cutting elements on the model of the core bit during the coring operation. The method may further include determining at least one force acting on a core in the model of the core bit based on the at least one force vector and generating a design of the core bit based on the at least one force acting on the core.

Core bit designed to control and reduce the cutting forces acting on a core of rock

In some embodiments, an apparatus and a system, as well as a method and article, may operate to generate a surface representing mechanical specific energy as a function of dimensionless products of downhole drilling process variables. Additional actions may include characterizing an area of the surface for different drill bit types, and operating a controlled device according to a location of run data associated with at least one of the different drill bit types and the area on the surface. Additional apparatus, systems, and methods are disclosed.

Drilling operation apparatus, methods, and systems

Systems and methods for a protective connection for coring inner barrels are disclosed. A coring apparatus includes a first inner barrel, a second inner barrel, and a tubular extension between adjacent ends of the first and second inner barrels. The coring apparatus includes an outer connector member moveably positioned about the tubular extension and configured for releasably connecting the first and second inner barrels. The first and second inner barrels and tubular extension define a substantially continuous tubular inner structure to receive a core sample.

Coring inner barrel connections for core of rock protection

A turbine-drill bit assembly is disclosed. The assembly comprises a box connection turbine connected to a pin connection drill bit. The turbine has a turbine body around a turbine shaft, the turbine body having a turbine stabilizer. The drill bit has a bit gauge or a bit sleeve around a bit shank, an end of the turbine stabilizer nearest the drill bit being spaced a first maximum distance from an end of the bit gauge or bit sleeve. In addition, a shouldering interface is formed at respective abutment shouldering surfaces of the turbine shaft and bit shank when the drill bit is attached to the turbine shaft, the interface being spaced a second maximum distance from an end of the bit gauge or bit sleeve.

Turbine drill bit assembly

A described bottom hole assembly includes a drill bit arranged at a distal end of a drill string and rotatable about a first central axis, the drill bit exhibiting a first unbalance force acting laterally on the drill bit at a first angular orientation, a first unbalance force marking physically applied to the drill bit and corresponding to the first unbalance force, a tool arranged axially from the drill bit, the tool exhibiting a second unbalance force acting laterally on the tool at a second angular orientation, and a second unbalance force marking physically applied to the tool and corresponding to the second unbalance force, wherein an angular offset between the first and second unbalance forces markings is able to be manipulated in order to obtain a minimized or desired tandem resulting unbalance force.

Unbalance force identifiers and balancing methods for drilling equipment assemblies

Described herein is a wear indicator () for use in a drill bit or a core head. The wear indicator () comprises an elongate element that forms part of the drill bit. The elongate element has a plurality of numbers () formed along its length, each number () being formed as a void and corresponds to a level of wear in accordance with the IADC dull grading system. As the drill becomes worn, the wear indicator () wears at the same rate to reveal one of the numbers (). The numbers range from '1' to '8' where the number &#x201c;1&#x201d; illustrates the least wear and the number &#x201c;8&#x201d; indicates the most wear. When unworn, none of the numbers are visible.

Wear indicators for drilling equipment

A matrix drill bit and method of manufacturing a matrix bit having back raked cutting elements is disclosed. In one aspect, a matrix drill bit for well drilling includes a matrix bit body that has a front area in a direction of drilling and two or more diamond impregnated cutting blades protruding from the front area of the matrix bit body. The cutting blades each have a front external surface protruding from the front area of the matrix bit body and present a plurality of back raked downhole interface surfaces in the direction of drilling. The downhole interface surfaces span a leading face and a trailing face where the leading face extends to a first height and the trailing face extends to a second height and the first height is greater than the second height.

Matrix drill bits with back raked cutting elements

The invention concerns a drill bit () with stationary cutting structure, comprising a tool body () and several blades (), which consist of a metal matrix impregnated with abrasive particles, and which are fixed to the tool body while extending forward therefrom, said blades () forming jointly a front cutting surface (), and having radial channels () for drilling fluid which mutually separate the blades () and are open outwards. The invention is characterized in that it further comprises, through at least one radial fluid channel () arranged between two said blades (), at least one bridge (&#x2033;) which connects said two blades, by being arranged between the tool body () and said front cutting surface ().

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Brussels, Belgium

Nuno Da Silva