US 10,650,108 B2Granted

PDC bits with mixed cutter blades

AssigneeHalliburton Energy Services, Inc.

InventorShilin Chen

Life of this patent

Estimating the term…

Loading patent…

Abstract

Downhole drilling tools designed and manufactured to minimize or reduce imbalance forces and wear by disposing cutting elements in cutter groups and cutter sets in a level of force balance and by placing impact and/or wear resistant cutters on blades subject to high impact forces and/or large loadings. Manufacturing costs may be reduced by placing inexpensive cutters on blades not subject to high impact forces and/or loadings. Some embodiments comprise designing downhole tools with combinations of thicker blades to receive high impact forces and/or loadings with thinner blades. Some embodiments comprise designing downhole drilling tools with optimized fluid-flow properties. Designing methods may comprise performing simulations on a designed tool, evaluating respective forces acting on cutters during simulated engagement with a downhole (uniform and transitional) and/or evaluating wear on cutters and bit, and/or CFD simulations to evaluate fluid-flow optimization on a tool. Various cutter layout procedures and algorithms are described.

Claims20

Dependent claims

A method for designing a downhole drilling tool that is impact resistant comprising:

inputting into a computer a plurality of downhole drilling tool characteristics;
inputting into the computer a plurality of downhole drilling conditions;
simulating drilling a wellbore extending from a flat surface in a first downhole formation having a first compressive strength;
simulating drilling the wellbore with the downhole drilling tool into a second formation having a second compressive strength, wherein the second compressive strength is different than the first compressive strength;
evaluating impact forces acting on each blade during drilling into the first downhole formation and during drilling into the second downhole formation;
determining a plurality of high impact blades;
determining a plurality of low impact blades;
installing a plurality of a first type of cutting element on the plurality of high impact blades, wherein the first type of cutting elements are selected from a group consisting of high impact resistant cutters, high wear resistant cutters, and combinations thereof;
and
installing a plurality of a second type of cutting element on the plurality of low impact blades, wherein the second type of cutting element elements are selected from a group consisting of cutters that are low impact resistant cutters, cutters that are low wear resistant, and combinations thereof;
simulating drilling a wellbore into the first downhole formation and further into the second formation;
repeating evaluation of impact forces on each respective blade;
determining if conditions are met for reducing or minimizing impact on each respective blade;
modifying installing of one or more of the first type of cutting element on one or more respective blades and modifying installing of one or more of the second type of cutting element on respective blades if conditions are not met for reducing or minimizing impact on each respective blade;
and
repeating simulations to determine if conditions are met for reducing or minimizing impact on each respective blade and repeating further modifying installing of at least one of the first type of cutting element and at least one of the second type of cutting element on respective each blade until conditions are met for a downhole tool that has minimized impact forces on each respective blade.

13 more elements

A method for optimizing fluid flow in a rotary drill bit comprising:

inputting into a computer a plurality of downhole drilling tool characteristics;
inputting into the computer a plurality of downhole drilling conditions;
performing simulations to determine one or more blades subject to high impact during downhole drilling and to determine one or more blades subject to low impact during downhole drilling;
evaluating impact forces acting on each blade during downhole drilling;
increasing respective thickness of the blades that are subject to high impact during downhole drilling thereby changing configuration of a plurality of respective associated junk slots;
installing a plurality of a first type of cutting element on the plurality of high impact blades wherein the first type of cutting elements are selected from a group consisting of high impact resistant cutters, high wear resistant cutters, and combinations thereof;
and
installing a plurality of a second type of cutting element on the plurality of low impact blades, wherein the second type of cutting element elements are selected from a group consisting of cutters that are low impact resistant cutters, cutters that are low wear resistant, and combinations thereof;
performing computational fluid dynamics (CFD) program simulations to analyze fluid flow patterns;
and
modifying the thickness of the one or more blades subject to high impact during drilling thereby modifying the configuration of one or more respective associated junk slots;
and
repeating the CFD simulations until optimizing fluid flow of the drill bit is obtained.

10 more elements

Dependencies are inferred from the claim text.

Facts

Application: 16/185,138Filed 9 Nov 2018 · continuation
Priority: 15 Dec 2010
Published: US 2019/0080034 A114 Mar 2019
Granted: 12 May 2020
Term ends: Not estimatedThe source records don’t support an estimate.

Classification6 codes

G06F 30/20
Computer-aided design [CAD]: design optimisation, verification or simulation
E21B 10/54
Characterised by wear resisting parts, e.g. diamond inserts: the bit being of the rotary drag type, e.g. fork-type bits
E21B 10/55
The bit being of the rotary drag type, e.g. fork-type bits: with preformed cutting elements
G06F 30/17
Geometric CAD: mechanical parametric or variational design

Family

Application12/969,122Parent of this division · filed 15 Dec 2010
Application14/807,396Parent of this continuation · filed 23 Jul 2015
US 9,115,552 B2Parent of this division · filed 25 Aug 2015
US 2019/0080034 A1Pre-grant publication · published 14 Mar 2019
US 10,162,911 B2Parent of this continuation
Application14/807,396Parent of this division
US 2012/0152624 A1Published application
US 2015/0363523 A1Published application
US 10,650,108 B2This patent

From the US filing history. Foreign family members aren’t listed.