Data processing: structural design – modeling – simulation – and em – Simulating nonelectrical device or system – Mechanical
Reexamination Certificate
2000-10-11
2004-08-31
Paladini, Albert W. (Department: 2125)
Data processing: structural design, modeling, simulation, and em
Simulating nonelectrical device or system
Mechanical
C175S045000, C702S009000
Reexamination Certificate
active
06785641
ABSTRACT:
FIELD OF THE INVENTION
The invention relates generally to drilling a wellbore, and more specifically to simulating the drilling performance of a drilling tool assembly drilling a wellbore. In particular, the invention relates to methods for simulating the dynamic response of a drilling tool assembly, methods for optimizing a drilling tool assembly design, and methods for optimizing the drilling performance of a drilling tool assembly.
BACKGROUND OF THE INVENTION
FIG. 1
shows one example of a conventional drilling system for drilling an earth formation. The drilling system includes a drilling rig
10
used to turn a drilling tool assembly
12
which extends downward into a wellbore
14
. The drilling tool assembly
12
includes a drilling string
16
, and a bottomhole assembly (BHA)
18
, attached to the distal end of the drill string
16
.
The drill string
16
comprises several joints of drill pipe
16
a
connected end to end through tool joints
16
b.
The drill string
16
transmits drilling fluid (through its hollow core) and transmits rotational power from the drill rig
10
to the BHA
18
. In some cases the drill string
16
further includes additional components such as subs, pup joints, etc.
The BHA
18
includes at least a drill bit
20
. Typical BHAs may also include additional components attached between the drill string
16
and the drill bit
20
. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (MWD) tools, logging-while-drilling (LWD) tools, and downhole motors.
In general, drilling tool assemblies
12
may include other drilling components and accessories, such as special valves, such as kelly cocks, blowout preventers, and safety valves. Additional components included in a drilling tool assembly
12
may be considered a part of the drill string
16
or a part of the BHA
18
depending on their locations in the drilling tool assembly
12
.
The drill bit
20
in the BHA
18
may be any type of drill bit suitable for drilling earth formation. Two common types of earth boring bits used for drilling earth formations are fixed-cutter (or fixed-head) bits and roller cone bits.
FIG. 2
shows one example of a fixed-cutter bit.
FIG. 3
shows one example of a roller cone bit.
Referring to
FIG. 2
, fixed-cutter bits (also called drag bits)
21
typically comprise a bit body
22
having a threaded connection at one end
24
and a cutting head
26
formed at the other end. The head
26
of the fixed-cutter bit
21
typically comprises a plurality of ribs or blades
28
arranged about the rotational axis of the bit and extending radially outward from the bit body
22
. Cutting elements
29
are embedded in the raised ribs
28
to cut formation as the bit is rotated on a bottom surface of a wellbore. Cutting elements
29
of fixed-cutter bits typically comprise polycrystalline diamond compacts (PDC) or specially manufactured diamond cutters. These bits are also referred to as PDC bits.
Referring to
FIG. 3
, roller cone bits
30
typically comprise a bit body
32
having a threaded connection at one end
34
and a plurality of legs (not shown) extending from the other end. A roller cone
36
is mounted on each of the legs and is able to rotate with respect to the bit body
32
. On each cone
36
of the bit
30
are a plurality of cutting elements
38
, typically arranged in rows about the surface of the cone
36
to contact and cut through formation encountered by the bit. Roller cone bits
30
are designed such that as a drill bit rotates, the cones
36
of the bit
30
roll on the bottom surface of the wellbore (called the “bottomhole”) and the cutting elements
38
scrape and crush the formation beneath them. In some cases, the cutting elements
38
on the roller cone bit
30
comprise milled steel teeth formed on the surface of the cones
36
. In other cases, the cutting elements
38
comprise inserts embedded in the cones. Typically, these inserts are tungsten carbide inserts or polycrystalline diamond compacts. In some cases hardfacing is applied to the surface of the cutting elements to improve wear resistance of the cutting structure.
For a drill bit
20
to drill through formation, sufficient rotational moment and axial force must be applied to the bit
20
to cause the cutting elements of the bit
20
to cut into and/or crush formation as the bit is rotated. The axial force applied on the bit
20
is typically referred to as the “weight on bit” (WOB). The rotational moment applied to the drilling tool assembly
12
at the drill rig
10
(usually by a rotary table) to turn the drilling tool assembly
12
is referred to as the “rotary torque”. The speed at which the rotary table rotates the drilling tool assembly
12
, typically measured in revolutions per minute (RPM), is referred to as the “rotary speed”. Additionally, the portion of the weight of the drilling tool assembly supported at the rig
10
by the suspending mechanism (or hook) is typically referred to as the hook load.
During drilling, the actual WOB is not constant. Some of the fluctuation in the force applied to the bit may be the result of the bit contacting with formation having harder and softer portions that break unevenly. However, in most cases, the majority of the fluctuation in the WOB can be attributed to drilling tool assembly vibrations. Drilling tool assemblies can extend more than a mile in length while being less than a foot in diameter. As a result, these assemblies are relatively flexible along their length and may vibrate when driven rotationally by the rotary table. Several modes of vibration are possible for drilling tool assemblies. In general, drilling tool assemblies may experience torsional, axial and lateral vibrations. Although partial damping of vibration may result due to viscosity of drilling fluid, friction of the drill pipe rubbing against the wall of the wellbore, energy absorbed in drilling the formation, and drilling tool assembly impacting with wellbore wall, these sources of damping are typically not enough to suppress vibrations completely.
Up to now, vibrations of a drilling tool assembly have been difficult to predict because different forces may combine to produce the various modes of vibration, and models for simulating the response of an entire drilling tool assembly including roller cone bit interacting with formation in a drilling environment have not been available. However, drilling tool assembly vibrations are generally undesirable, not only because they are difficult to predict, but also because they can significantly affect the instantaneous force applied on the bit. This can result in the bit not operating as expected. For example, vibrations can result in off-centered drilling, slower rates of penetration, excessive wear of the cutting elements, or premature failure of the cutting elements and the bit. Lateral vibration of the drilling tool assembly may be a result of radial force imbalances, mass imbalance, and bit/formation interaction, among other things. Lateral vibration results in poor drilling tool assembly performance, overgage hole drilling, out-of-round, or “lobed” wellbores and premature failure of both the cutting elements and bit bearings.
When the bit wears out or breaks during drilling, the entire drilling tool assembly must be lifted out of the wellbore section-by-section and disassembled in an operation called a “pipe trip”. In this operation, a heavy hoist is required to pull the drilling tool assembly out of the wellbore in stages so that each stand of pipe (typically pipe sections of about 90 feet) can be unscrewed and racked for the later re-assembly. Because the length of a drilling tool assembly may extend for more than a mile, pipe trips can take several hours and can pose a significant expense to the wellbore operator and drilling budget. Therefore, the ability to design drilling tool assemblies which have increased durability and longevity, for example, by minimizing the wear on the drilling tool assembly due to vibrations, is very important and greatly desired to minimize
Osha & May L.L.P.
Paladini Albert W.
Smith International Inc.
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