Note: Descriptions are shown in the official language in which they were submitted.
CA 02620905 2010-06-29
METHOD AND APPARATUS FOR DETERMINING
DESTRUCTIVE TORQUE ON A DRILLING ASSEMBLY
This application is a divisional application of Serial.No.
2,482,922 filed April 3., 2003.
Background of Invention
Field of the Invention
The invention relates generally to the field of drilling wellbores through
the earth. More particularly, the invention relates to apparatus and methods
for
determining the dynamic mode of motion of a drill string used to turn a drill
bit.
Background Art
Drilling wellbores through the earth includes "rotary" drilling, in which a
drilling rig or similar lifting device suspends a drill string which turns a
drill bit
located at one end of the drill string. Equipment on the rig and/or an
hydraulically
opersted_.motot..diisposed in, the drill string 'rotate the_ bit. _
The..rig._includes _ lifting
equipment which suspends the drill string so as to place a selected axial
force
(weight on bit - "WOB") on the drill bit as the bit is rotated. The combined
axial
force and bit rotation causes the bit to gouge, scrape and/or crush the rocks,
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thereby drilling a wellbore through the rocks. Typically a drilling rig
includes
liquid pumps for forcing a fluid called "drilling mud" through the interior of
the
drill string. The drilling mud is ultimately discharged through nozzles or
water
courses in the bit. The mud lifts drill cuttings from the wellbore and carries
them
to the earth's surface for disposition. Other types of drilling rigs may use
compressed air as the fluid for lifting cuttings.
The forces acting on a typical drill string during drilling are very large.
The amount of torque necessary to rotate the drill bit may range to several
thousand foot pounds. The axial force may range into several tens of thousands
of pounds. The length of the drill string, moreover, may be twenty thousand
feet
or more. Because the typical drill string is composed of threaded pipe
segments
having diameter on the order of only a few inches, the combination of length
of
the drill string and the magnitude of the axial and torsional forces acting on
the
drill string can cause certain movement modes of the drill string within the
wellbore which can be quite destructive. For example, a well known form of
destructive drill string movement is known as "whirl", in which the bit and/or
the
drill string rotate precessionally about an axis displaced from the center of
the
wellbore, either in the same direction or in a direction opposite to the
rotation of
the drill string and drill bit. Another destructive mode is called "bit
bounce" in
which the entire drill string vibrates axially (up and down). "Lateral"
vibrations
and "torque shocks" can also be detrimental to drill string wear and drilling
performance. Still other movement modes include "wind up" and torsional
release of the bottom of the drill string when the bit or other drill string
components momentarily stop rotation and then release. Any or all of these
destructive modes of motion, if allowed to continue during drilling, both
decrease
drilling performance and increase the risk that some component of the drill
string
will fail.
The foregoing examples are not intended to be an exhaustive
representation of the destructive movement modes a drill string may undergo,
but
are only provided as examples to explain the nature of the present invention.
It is
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known in the art to measure axial and lateral acceleration or related
parameters, as
well as axial force and rotational torque related parameters, at the earth's
surface
to try to determine the existence of a destructive mode in the drill string. A
limitation to using surface measurements to determine destructive drill string
modes is that the drill string is an imperfect communication channel for
axial,
lateral and/or torsional accelerations which are imparted to the drill string
at or
near the bottom of the wellbore. In particular, the drill string itself can
absorb
considerable torsion and change in length over its extended length. Moreover,
much of the drill string may be in contact with the wall of the wellbore
during
drilling, whereby friction between the wellbore wall and the drill string
attenuates
some of the accelerations applied to the drill string near the bottom of the
wellbore.
It is also known in the art to measure acceleration, rotation speed,
pressure, weight and/or torque applied to various components of the drill
string at
a position located near the drill bit. Devices which make such measurements
typically form part of a so-called "measurement-while-drilling" (M)WD) system,
which may include additional sensing devices for measuring direction of the
wellbore with respect to a geographic reference and sensors for measuring
properties of the earth formations penetrated by the wellbore. A limitation to
using MWD systems known in the art for determining destructive operating
modes in a drill string is that the data communication rate of MWD systems is
generally limited to a few bits per second. The low communication rate results
from the type of telemetry used, namely, low frequency electromagnetic waves,
or
more commonly, drilling mud flow or pressure modulation. The low
communication rate requires that very selected information measured by various
sensors on the MWD system be communicated to the earth's surface by the
telemetry (known in the art as "in real time"). Destructive modes, however,
may
include accelerations having frequencies of several Hertz or more. Typically,
measurements of acceleration, rotation speed, pressure, weight and/or torque
are
sampled at a relatively high rate, but only average amplitude, average
amplitude
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variation or peak values are transmitted to the earth's surface without regard
to
whether a peak, average or average variation value corresponds to any
particular
drill string failure mode. As a result, MWD systems known in the art do not
necessarily make the best use of the mode-related measurements made by the
MWD system sensors.
It is desirable to have a method and system for identifying drill string
movement modes that can communicate the identified mode to the earth's surface
for analysis so as to facilitate the appropriate remedial action for each
specific
movement mode and reduce the chance of drill string failure.
Summary of Invention
One aspect of the invention is a method for determining mode of
movement in a drill string. A method according to this aspect of the invention
includes measuring lateral acceleration of the drill string and determining a
lateral
position of the drill string with respect to time from the acceleration
measurements. The movement mode is determined from the position with respect
to time.
Another aspect of the invention is a method for determining a mode of
motion of a drill string. A method according to this aspect of the invention
includes measuring a parameter related to acceleration of the drill string
along at
least one direction, spectrally analyzing the measurements of acceleration,
and
determining existence of a particular mode from the spectrally analyzed
measurements.
Another aspect of the invention is a method for determining destructive
torque on a bottom hole assembly. A method according to this aspect of the
invention includes measuring angular acceleration from at least one location
along
the bottom hole assembly, and comparing the angular accelerations to a
selected
threshold. The selected threshold is related to moment of inertia of selected
components of the bottom hole assembly and a maximum allowable torque
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applicable to threaded connections between the selected components. The
method also includes generating a warning indication when the angular
acceleration exceeds the selected threshold.
Another aspect of the invention is a method for estimating wear on a drill
string. A method according to this aspect of the invention includes
determining a
mode of motion of the drill string; calculating side forces generated by
contact
between affected components of the drill string and a wall of a wellbore as a
result of the mode of motion, and estimating a wear rate corresponding to the
side
forces and a rate of rotation of the drill string. In one embodiment,
determining
the mode of motion includes measuring lateral acceleration of the drill string
and
determining a lateral position of the drill string with respect to time from
the
acceleration measurements. The movement mode is determined from the position
with respect to time.
Another aspect of the invention is a method for estimating hole condition.
A method according to this aspect of the invention includes determining a mode
of motion of the drill string, calculating side forces generated by contact
between
affected components of the drill string and a wall of a wellbore as a result
of the
mode of motion, calculating variation in torque corresponding to the modal
side
forces on the drill string, estimating torque variation generated at the bit,
and
determining the hole condition by subtracting variation in the torque
variation of
the bit and variation in the torque variation due to modal side forces from
the total
variation in torque measured at the surface. In one embodiment, determining
the
variation in torque from the bit is from empirical measurements of average bit
torque at different rotation rates with various values of weight on bit in
different
formation types with similar bit condition. Determining the mode of motion
includes measuring lateral acceleration of the drill string and determining a
lateral
position of the drill string with respect to time from the acceleration
measurements. The drill string movement mode is determined from the position
with respect to time.
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Another aspect of the invention is a method for estimating fatigue on a drill
string. A method according to this aspect of the invention includes
determining a mode
of motion of the drill string, calculating flexural forces generated as a
result of the
mode of motion, and estimating a fatigue rate from the flexural forces. In one
embodiment, determining the mode of motion includes measuring lateral
acceleration
of the drill string and determining a lateral position of the drill string
with respect to
time from the acceleration measurements. The movement mode is determined from
the
position with respect to time.
In accordance with a first aspect of the present invention, there is provided
a
method for determining a mode of movement in a drill string, comprising:
measuring lateral acceleration of the drill string;
determining a lateral position of the drill string with respect to time from
the
acceleration measurements; and
determining the mode from the position with respect to time.
In accordance with a second aspect of the present invention, there is provided
a
method for determining a mode of movement of a drill string, comprising:
measuring a parameter related to acceleration of the drill string along at
least
one direction; spectrally analyzing the measurements of acceleration; and
determining existence of a particular mode from the spectrally analyzed
measurements, wherein the determining the particular mode comprises
identifying a
component frequency in the spectrally analyzed measurements which corresponds
to at
least one of a resonant frequency and a whirl frequency of a selected
component of the
drill string.
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In accordance with a third aspect of the present invention, there is provided
a method for
estimating wear on a drill string, comprising:
determining a mode of movement of the drill string;
calculating side forces generated by contact between affected components of
the drill
string and a wall of a wellbore as a result of the mode of movement; and
estimating a wear rate corresponding to the side forces and a rate of rotation
of the drill
string.
In accordance with a fourth aspect of the present invention, there is provided
an apparatus
for determining mode of movement in a drill string, comprising:
a sensor for measuring lateral acceleration of the drill string;
means for determining a lateral position of the drill string with respect to
time from the
acceleration measurements; and
means for determining the mode from the lateral position with respect to time.
In accordance with a fifth aspect of the present invention, there is provided
an apparatus
for determining a mode of movement of a drill string, comprising:
a sensor for measuring a parameter related to acceleration of the drill string
along at least
one direction;
a spectral analyzer operatively coupled to the sensor; and
means for determining existence of a particular mode from the spectrally
analyzed
measurements, the means for determining the particular mode comprising means
for identifying
a component frequency operatively coupled to the spectral analyzer, the
component frequency
corresponding to at least one of whirl rate, torsional resonance, axial
resonance and lateral
resonance of the selected component of the drill string.
In accordance with a sixth aspect of the present invention, there is provided
a method for
determining destructive torque on a bottom hole assembly, comprising:
measuring a parameter related to angular acceleration at least one location
along the drill
string;
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comparing angular acceleration determined from the measured parameter to a
selected
threshold, the selected threshold related to a moment of inertia of selected
components of the drill string and a maximum torque applicable to at least one
of
threaded connections between the selected components, and tubular components
of a drill string; and
generating a warning indication when the angular acceleration exceeds the
selected
threshold.
In accordance with a seventh aspect of the present invention, there is
provided an
apparatus for determining destructive torque on a bottom hole assembly,
comprising:
a sensor measuring angular acceleration at least one location along the drill
string;
means for comparing angular acceleration to a selected threshold operatively
coupled to
the sensor, the selected threshold related to a moment of inertia of selected
components of the bottom hole assembly and a maximum torque applicable to
threaded connections between the selected components; and
means for generating a warning indication when the angular acceleration
exceeds the
selected threshold.
Other aspects and advantages of the invention will be apparent from the
following
description of the appended claims.
Brief Description of the Drawings
Figure 1 shows a typical wellbore drilling operation.
Figure 2 shows parts of a typical MWD system.
Figure 3 shows another example of a bottom hole assembly (BHA).
Figure 4 shows a table of component resonant frequencies for each of the BHA
components shown in Figure 3.
Figure 5 shows an example of spectrally analyzed acceleration measurements
which
indicate existence of lateral resonance between the stabilizers shown in the
example BHA of
Figure 3.
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Figure 6 shows an example of spectrally analyzed acceleration measurements
which
indicate existence of bit bounce for the example BHA shown in Figure 3.
Figure 7 shows an example of spectrally analyzed acceleration measurements
which
indicate torsional "chatter" in the drill collars of the example BHA shown in
Figure 3.
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Figure 8 shows an example of spectrally analyzed acceleration
measurements which indicate existence of backward whirl in the heavyweight
drill pipe of the example BHA shown in Figure 3.
Figure 9 shows an example of doubly integrated acceleration
measurements which indicate normal rotation in a drill string.
Figure 10 shows an example of doubly integrated acceleration
measurements which indicate lateral shock or bending.
Figure 11 shows an example of doubly integrated acceleration
measurements which indicate whirl.
Figure 12 shows a graph of instantaneous, maximum and minimum
angular accelerations on the BHA with respect to time.
Figure 13 is a flow chart of an embodiment of a method for determining
wear rate on components of a drill string from a mode of drill string motion.
Figure 14 shows the centripetal side force and frictional torsional force
resulting from forward whirling mode of motion of the drill string.
Figure 15 is a flow chart of an embodiment of a method for determining
fatigue rate on components of a drill string from a mode of drill string
motion.
Figure 16 is a flow chart of an example method of comparing surface
measured torque with respect to expected surface torque to determine unsafe
conditions in the wellbore.
Detailed Description
Figure 1 shows a typical wellbore drilling system which may be used with
various embodiments of a method and system according to the invention. A
drilling rig 10 includes a drawworks 11 or similar lifting device known in the
art
to raise, suspend and lower a drill string. The drill string includes a number
of
threadedly coupled sections of drill pipe, shown generally at 32. A lowermost
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part of the drill string is known as a bottom hole assembly (BHA) 42, which
includes, in the embodiment of Figure 1, a drill bit 40 to cut through earth
formations 13 below the earth's surface. The BHA 42 may include various
devices such as heavy weight drill pipe 34, and drill collars 36. The BHA 42
may
also include one or more stabilizers 38 that include blades thereon adapted to
keep
the BHA 42 roughly in the center of the wellbore 22 during drilling. In
various
embodiments of the invention, one or more of the drill collars 36 may include
a
measurement while drilling (MWD) sensor and telemetry unit (collectively
"MWD system"), shown generally at 37. The sensors included in and the purpose
of the MWD system 37 will be further explained below with reference to Figure
2.
The drawworks 11 is operated during active drilling so as to apply a
selected axial force to the drill bit 40. Such axial force, as is known in the
art,
results from the weight of the drill string, a large portion of which is
suspended by
the drawworks 11. The unsuspended portion of the weight of the drill string is
transferred to the bit 40 as axial force. The bit 40 is rotated by turning the
pipe 32
using a rotary table/kelly bushing (not shown in Figure 1) or preferably a top
drive 14 (or power swivel) of any type well known in the art. While the pipe
32
(and consequently the BHA 42 and bit 40) as well is turned, a pump 20 lifts
drilling fluid ("mud") 18 from a pit or tank 24 and moves it through a
standpipe/hose assembly 16 to the top drive 14 so that the mud 18 is forced
through the interior of the pipe segments 32 and then the BHA 42. Ultimately,
the mud 18 is discharged through nozzles or water courses (not shown) in the
bit
40, where it lifts drill cuttings (not shown) to the earth's surface through
an
annular space between the wall of the wellbore 22 and the exterior of the pipe
32
and the BHA 42. The mud 18 then flows up through a surface casing 23 to a
wellhead and/or return line 26. After removing drill cuttings using screening
devices (not shown in Figure 1), the mud 18 is returned to the tank 24.
The standpipe system 16 in this embodiment includes a pressure
transducer 28 which generates an electrical or other type of signal
corresponding
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to the mud pressure in the standpipe 16. The pressure transducer 28 is
operatively
connected to systems (not shown separately in Figure 1) inside a recording
unit 12
for decoding, recording and interpreting signals communicated from the MWD
system 37. As is known in the art, the MWD system 37 includes a device, which
will be explained below with reference to Figure 2, for modulating the
pressure of
the mud 18 to communicate data to the earth's surface. In some embodiments the
recording unit 12 includes a remote communication device 44 such as a
satellite
transceiver or radio transceiver, for communicating data received from the MWD
system 37 (and other sensors at the earth's surface) to a remote location.
Such
remote communication devices are well known in the art. The data detection and
recording elements shown in Figure 1, including the pressure transducer 28 and
recording unit 12 are only examples of data receiving and recording systems
which may be used with the invention, and accordingly, are not intended to
limit
the scope of the invention. The top drive 14 may also include sensors (shown
generally as 14B) for measuring rotational speed of the drill string, the
amount of
axial load suspended by the top drive 14 and the torque applied to the drill
string.
The signals from these sensors 14B may be communicated to the recording unit
12 for processing as will be further explained.
One embodiment of an MWD system, such as shown generally at 37 in
Figure 1, is shown in more detail in Figure 2. The MWD system 37 is typically
disposed inside a non-magnetic housing 47 made from monel or the like and
adapted to be coupled within the drill string at its axial ends. The housing
47 is
typically configured to behave mechanically in a manner similar to other drill
collars (36 in Figure 1). The housing 47 includes disposed therein a turbine
43
which converts some of the flow of mud (18 in Figure 1) into rotational energy
to
drive an alternator 45 or generator to power various electrical circuits and
sensors
in the MWD system 37. Other types of MWD systems may include batteries as
an electrical power source.
Control over the various functions of the MWD system 37 may be
performed by a central processor 46. The processor 46 may also include
circuits
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for recording signals generated by the various sensors in the MWD system 37.
In
this embodiment, the MWD system 37 includes a directional sensor 50, having
therein tri-axial magnetometers and accelerometers such that the orientation
of the
MWD system 37 with respect to magnetic north and with respect to earth's
gravity can be determined. The MWD system 37 may also include a gamma-ray
detector 48 and separate rotational (angular)/axial accelerometers,
magnetometers
or strain gauges, shown generally at 58. The MWD system 37 may also include a
resistivity sensor system, including an induction signal generator/receiver
52, and
transmitter antenna 54 and receiver 56A, 56B antennas. The resistivity sensor
can
be of any type well known in the art for measuring electrical conductivity or
resistivity of the formations (13 in Figure 1) surrounding the wellbore (22 in
Figure 1). The types of sensors in the MWD system 37 shown in Figure 2 is not
meant to be an exhaustive representation of the types of sensors used in MWD
systems according to various aspects of the invention. Accordingly, the
particular
sensors shown in Figure 2 are not meant to limit the scope of the invention.
The central processor 46 periodically interrogates each of the sensors in
the MWD system 37 and may store the interrogated signals from each sensor in a
memory or other storage device associated with the processor 46. Some of the
sensor signals may be formatted for transmission to the earth's surface in a
mud
pressure modulation telemetry scheme. In the embodiment of Figure 2, the mud
pressure is modulated by operating an hydraulic cylinder 60 to extend a pulser
valve 62 to create a restriction to the flow of mud through the housing 47.
The
restriction in mud flow increases the mud pressure, which is detected by the
transducer (28 in Figure 1). Operation of the cylinder 60 is typically
controlled
by the processor 46 such that the selected data to be communicated to the
earth's
surface are encoded in a series of pressure pulses detected by the transducer
(28 in
Figure 1) at the surface. Many different data encoding schemes using a mud
pressure modulator, such as shown in Figure 2, are well known in the art.
Accordingly, the type of telemetry encoding is not intended to limit the scope
of
the invention. Other mud pressure modulation techniques which may also be
CA 02620905 2008-03-12
used with the invention include so-called "negative pulse" telemetry, wherein
a
valve is operated to momentarily vent some of the mud from within the MWD
system to the annular space between the housing and the wellbore. Such venting
momentarily decreases pressure in the standpipe (16 in Figure 1). Other mud
pressure telemetry includes a so-called "mud siren", in which a rotary valve
disposed in the MWD housing 47 creates standing pressure waves in the mud,
which may be modulated using such techniques as phase shift keying for
detection at the earth's surface. Other electromagnetic, hard wired
(electrical
conductor), or optical fiber or hybrid telemetry systems may be used as
alternatives to mud pulse telemetry, as will be further explained below.
In some embodiments, each component of the BHA (42 in Figure 1) may
include its own rotational, lateral or axial accelerometers, magnetometers,
pressure sensors, caliper/stand-off sensors or strain gauge sensor. For
example,
referring back to Figure 1, each of the drill collars 36, the stabilizer 38
and the bit
40 may include such sensors. The sensors in each BHA component may be
electrically coupled, or may be coupled by a linking device such as a short-
hop
electromagnetic transceiver of types well known in the art, to the processor
(46 in
Figure 2). The processor 46 may then periodically interrogate each of the
sensors
disposed in the various components of the BHA 40 to make motion mode
determinations according to various embodiments of the invention.
For purposes of this invention, either strain gauges, magnetometers or
accelerometers are practical examples of sensors which may be used to make
measurements related to the acceleration imparted to the particular component
of
the BHA (42 in Figure 1) and in the particular direction described. As is
known
in the art, torque, for example, is a vector product of moment of inertia and
angular acceleration. A strain gauge adapted to measure torsional strain on
the
particular BHA component would therefore measure a quantity directly related
to
the angular acceleration applied to that BHA component. Accelerometers and
magnetometers however, have the advantage of being easier to mount inside the
various components of the BHA, because their response does not depend on
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accurate transmission of deformation of the BHA component to the accelerometer
or magnetometer, as is required with strain gauges. However, it should be
clearly
understood that for purposes of defining the scope of this invention, it is
only
necessary that the property measured be related to the component acceleration
being described. An accelerometer adapted to measure rotational (angular)
acceleration would preferably be mounted such that its sensitive direction is
perpendicular to the axis of the BHA component and parallel to a tangent to
the
outer surface of the BHA component. The directional sensor 50, if
appropriately
mounted inside the housing 47, may thus have one component of its three
orthogonal components which is suitable to measure angular acceleration of the
MWD system 37.
Figure 3 shows another example of a BHA 42A in more detail for
purposes of explaining the invention. The BHA 42A in this example includes
components comprising a bit 40, which may be of any type known in the art for
drilling earth formations, a near-bit or first stabilizer 38, drill collars
36, a second
stabilizer 38A,which may be the same or different type than the first
stabilizer 38,
and heavy weight drill pipe 34. Each of these sections of the BHA 42A may be
identified by its overall length as shown in Figure 3. The bit 40 has length
C5, the
first stabilizer 38 has length C2, and so on as shown in Figure 3. The entire
BHA
42A has a length indicated by C6. In some embodiments of the invention,
characteristic resonant and/or motion frequencies of each component of the BHA
42A may be determined by experiment and/or by modeling (e.g. finite element
analysis). Characteristic frequencies of interest in embodiments of the
invention
are shown, for example, in the table of Figure 4. The example characteristic
frequencies include "whirl" frequencies, shown as Wl-W6, axial resonant
frequencies, shown as Al-A6 orsional resonant frequencies, shown as Tl-T6, and
a lateral (bending) resonant frequency, shown as Ll-L6.
In one embodiment of the invention, the characteristic frequencies are
determined for selected components of a particular BHA used in a wellbore
being
drilled. The example BHA shown in Figure 1 and Figure 3 are only two of many
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different BHA configurations that may be used to drill a wellbore or part of a
wellbore. Accordingly, in some embodiments of the invention, the
characteristic
frequencies of each BHA component are typically modeled before the BHA is
actually used in the wellbore using the BHA configuration to be used in the
wellbore. Modeling the characteristic frequencies may include as input
parameters lengths, diameters, bending stiffness, torsional stiffness, moment
of
inertia, mass, and material properties (e.g. density, acoustic velocity,
compressibility) of each BHA component. The modeling may include expected
axial force (also known as "weight on bit"), expected torque on the BHA,
diameter of the bit (40 in Figure 3), diameters of casings, fluid properties
of the
drilling mud (18 in Figure 1) such as density and viscosity.
In some embodiments of the invention, the characteristic frequencies
determined as a result of the modeling may be stored in the processor (46 in
Figure 2). During operation of the drill string and BHA (42 in Figure 2 and
42A
in Figure 3) axial acceleration is measured, lateral acceleration is measured
and
angular (or rotational) acceleration is measured. As previously explained,
strain
may be measured with respect to each motion component as an alternative to
measuring acceleration. In some embodiments, axial, lateral and angular
acceleration may be measured by the accelerometers in the directional sensor
(50
in Figure 2). Other embodiments may use separate accelerometers,
magnetometers, or strain gauges to measure the component accelerations or
strains. In still other embodiments, angular acceleration may be determined
from
measurements made by the magnetometers in the directional sensor (50 in Figure
2). As is known in the art, the magnetometers measure a magnitude of the
earth's
magnetic field along the component direction. As the MWD system (37 in Figure
2) rotates with the drill pipe and BHA, the direction of the earth's magnetic
field
with respect to the MWD system (37 in Figure 2) also rotates. By determining
the
second derivative, with respect to time, of the rotational orientation of the
MWD
system (37 in Figure 2) with respect to magnetic north, the angular
acceleration of
the MWD system (37 in Figure 2) may be determined.
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In some embodiments, the axial acceleration, lateral acceleration and
angular acceleration may be measured at one position in the BHA (42 in Figure
1). This may be at the location of the directional sensor (50 in Figure 2) as
previously explained. Characteristic vibration frequencies from each bottom
hole
assembly component are typically detectable at any point in the BHA with much
less attenuation than described earlier when trying to detect downhole
vibrations
at the earth's surface. In other embodiments, the accelerations may be
measured
by sensors within various individual components of the BHA and signals from
these sensors communicated to the processor (46 in Figure 2) for calculation
(as
will be further explained) and/or communication to the earth's surface.
In some embodiments, the measurements of acceleration made by the
various embodiments of sensors as described herein are processed (in processor
46 or in another computer disposed in the BHA) in a manner that will now be
explained. First, the measurements of acceleration with respect to time may be
spectrally analyzed. Spectral analysis may be performed, for example, by any
fast
Fourier transform or discrete Fourier transform method well known in the art.
A
result of spectral analysis is a set of values representing amplitudes of
component
frequencies in the acceleration data. The component frequencies can be
compared
to the modeled frequencies for the various BHA components to determine the
presence of specific destructive modes of motion in the BHA.
One example of a destructive mode is shown in Figure 5, which is a graph
of amplitudes of lateral acceleration component frequencies in the lateral
acceleration data. An amplitude peak 60 can be observed at the expected
lateral
resonant frequency of the drill collars section L3. The amplitude of the
lateral
resonance at the peak 60 may be large enough such that the rig operator should
change one or more drilling operating parameters to reduce the amplitude of
the
peak 60 below a predetermined threshold. The threshold may be determined by
modeling or by experimentation using actual BHA components. Drilling
operating parameters which may be directly controlled by the drilling rig
operator
include axial force on the drill bit (weight on bit), rotational speed of the
top drive
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(14 in Figure 4), also referred to in the art as RPM, and the rate of flow of
the
mud (18 in Figure 1) by changing an operating speed of the mud pumps (20 in
Figure 1). Alleviating the resonance may also be achieved by some sequence of
drilling procedures, such as the reciprocation of the drill pipe or drilling
fluid re-
formulation.
In certain embodiments of the invention, the existence of the characteristic
drilling mode frequencies having an amplitude higher than the selected
threshold,
such as shown at 60 in Figure 5, is determined by calculations performed in
the
processor (46 in Figure 2), as previously explained. As is known in the art,
the
relatively slow speed of data communication using mud pressure modulation
telemetry makes it impracticable to transmit to the earth's surface in a
timely
manner data represented as the graph in Figure 5. Therefore, in some
embodiments, the processor may be programmed to determine the existence of a
resonance above a selected amplitude threshold, such as shown at 60 in Figure
5.
If such a resonance is determined to exist, the type of resonance event is
determined by comparison, in the processor (46 in Figure 2), of the resonance
frequency to prior determined resonant frequencies, and an indication of the
existence of the resonance may be communicated to any one of a number of
automatic downhole control systems known in the art, for example, thrusters
(weight on bit control), mud flow bypass controls (to control mud motor RPM)
which can then change the drilling operating parameters downhole so as to
alleviate the resonance. The indication of a resonance may also be
communicated
to the rig operator by momentary reprogramming of the mud telemetry. The
indication may take the form of a unique pressure pulse sequence, according to
mud telemetry techniques well known in the art. Upon receipt of such an
indication by the rig operator, a drilling procedure or any one or more of the
drilling operating parameters may be changed to eliminate the destructive mode
.resonance.
Figure 6 shows another example of a destructive mode as an amplitude
peak 62 occurring at the axial resonant frequency of the BHA (A6 in Figure 4).
CA 02620905 2008-03-12
Existence of bit bounce may be communicated to the rig operator by a different
selected mud pressure pulse sequence. As in the case of lateral resonance, the
bit
bounce shown in Figure 6 may be reduced in some cases by changing one or more
of the drilling operating parameters. Figure 7 shows an example of torsional
"chatter" (resonance at the torsional frequency of the drill collars) as an
amplitude
peak at 64. Such chatter may take place, for example, as a result of
rotational
excitation of the BHA due to the drill bit becoming momentarily rotationally
stuck in certain formations. Torsional chatter may be reduced by changing one
or
more of the drilling operating parameters.
Another destructive mode shown in Figure 8 is backward "whirl" of the
heavy weight drill pipe (34 in Figure 1). Whirl in many cases may not be
reduced
or eliminated merely by changing a drilling operating parameter, as is known
in
the art, because whirl can be a dynamically stable condition. Despite the
dynamically stable nature of some whirl, it can be destructive to the affected
BHA
components because of the bending stresses which take place. Often, the most
effective way to eliminate whirl is to stop drilling operations by stopping
drill
string rotation, lifting the bit off the bottom of the wellbore, and then
resuming
drilling using different drilling operating parameters. Note that the whirl
frequency is related to component outside diameter, wellbore diameter and the
rotational rate of the drill string (RPM). RPM, as may be inferred from the
previous explanation of determining angular acceleration, may be determined by
measuring magnetic field-based rotational position of the MWD system and
calculating a first derivative thereof to determine rotational speed (RPM).
The types of destructive mode shown as resonant amplitude peaks in
acceleration data in Figures 5-8 are not meant to be an exhaustive
representation
of all the modes which may be identified using methods according to the
invention. To summarize this aspect of the invention, at least one
acceleration
component is measured at one or more locations along the BHA. The
acceleration measurements are spectrally analyzed to determine existence of a
component frequency corresponding to a destructive mode. If the amplitude of
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CA 02620905 2008-03-12
the destructive mode frequency exceeds a selected threshold, an indication of
such
condition can be communicated to automated downhole control systems or
alternatively transmitted to the earth's surface for changes to drilling
operating
parameters. Any drill string movement mode may have more than one threshold.
Each such threshold may also have an alarm code related to the severity of
such
drill string movement. Each such alarm code can be communicated to either the
automatic downhole control system, the surface control system or to the rig
operator's control console, the need either to modify one or more drilling
operating parameters or alternatively to stop the drilling process.
The foregoing embodiments of a method according to the invention
include performing spectral analysis and determining the existence of a
destructive mode in the processor (46 in Figure 2) or similar device disposed
somewhere in the BHA (42 in Figure 2). In other embodiments, acceleration
measurements may be transmitted to the earth's surface, whereby the spectral
analysis and mode determination may be performed at the earth's surface. One
way to communicate the acceleration (and other) measurements to the surface
for
processing is to use a type of drill pipe disclosed in Published U. S. Patent
Application No. 2002/0075114 Al filed by Hall et al. The drill pipe disclosed
in
the Hall et al. application includes electromagnetically coupled wires in each
drill
pipe segment and a number of signal repeaters located at selected positions
along
the drill string. Alternatively fiber-optic or hybrid data telemetry systems
might
be used as a communication link from the downhole processor to the surface.
Another embodiment for determining existence of lateral destructive
modes in a BHA can be explained with reference to Figures 9, 10 and 11. The
MWD system (37 in Figure 2), as previously explained, includes accelerometers
disposed so as to be sensitive to acceleration along three mutually orthogonal
directions and magnetometers adapted to measure the rotational orientation of
system, and thus the accelerometers. Typically one accelerometer direction is
parallel to the housing (47 in Figure 2) axis, and the other two directions
are
transverse to the housing axis. The acceleration measurements made by the
17
CA 02620905 2008-03-12
transverse accelerometers can be doubly integrated to determine, with respect
to
time and accounting for changes in sensor orientation as measured by the
magnetometers, a position of the MWD system with respect to a center of the
wellbore. One example of determining lateral position with respect to time is
shown in Figure 9. A curve 68 connects points representing calculations of the
position of the MWD system at selected times. The curve 68 in Figure 9 is
interpreted to indicate substantially "normal" rotation of the BHA, wherein
"normal" means that the rotation is substantially about the axis of the BHA
and
very little lateral deflection of the BHA is taking place.
A corresponding lateral position curve 70 is shown in Figure 10. The
curve 70 in Figure 10 is interpreted to indicate existence of lateral
"shocks", or
rapid lateral deflections of the BHA. An interesting aspect of shock type
deflection as shown in Figure 10 is that if the magnitude of lateral
displacement
does not result in the drill string component contacting the side of the
wellbore,
the shock so indicated may in some cases be essentially non-destructive or
only
minimally destructive to the BHA component involved. Prior art mode detection
techniques, which typically cause the mud telemetry to indicate a warning when
instantaneous acceleration in any direction exceeded a selected threshold, may
indicate that motion such as shown in Figure 10 required immediate
intervention
by the rig operator. However, other modes, such as shown at curve 72 in Figure
11, which indicates whirl, may actually be far more destructive to the BHA or
other component drill string because of the large bending stresses or drill
string
component wear which is believed to occur. Whirl, however, because it includes
substantially continuous contact between the affected BHA or drill string
component and the wall of the wellbore (22 in Figure 1) may not produce
accelerations exceeding a particular "destructive" threshold. Accordingly,
prior
art techniques which indicate only acceleration exceeding a selected threshold
may fail to identify whirl, and at the same time, may provide false indication
of
destructive modes in the BHA. The embodiment described with respect to
Figures 9, 10 and 11 requires that lateral component acceleration be measured
in
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CA 02620905 2008-03-12
each component of the BHA for which the mode is to be identified, however. In
one embodiment of this invention, the different drill string movement modes
are
identified by calculating both an average lateral displacement and a variation
in
lateral displacement. The normal drilling mode (shown by lateral displacement
curve 68 in Figure 9) will have a very small variation in lateral displacement
and
small average lateral displacement. Lateral vibration drill string movement
(shown by lateral displacement curve 70 in Figure 10) will have a larger
average
displacement and larger variation in lateral displacement dependent upon hole
and
drill string component diameters. Whirling drill string movement mode (shown
by lateral displacement curve 72 in Figure 11) will have an even larger
average
drill string displacement from center but typically will have a smaller
variation in
displacement than for lateral vibration drill string movement modes, dependent
upon drill string and hole diameters. The relative direction of drill string
displacements can be used to discriminate between forward and backward
whirling modes.
Still another embodiment of the invention may be better understood by
referring to Figure 12. In this embodiment, at least one sensor disposed in
the
BHA, or in the MWD system (37 in Figure 2) measures a parameter related to
angular acceleration. A graph of such measurements made with respect to time
and as recorded in the processor (46 in Figure 2) is shown at curve 74 in
Figure
12. In the ideal situation, the BHA would rotate at substantially constant
speed
during drilling operations, and the angular acceleration would be
substantially
zero except when rotation of the BHA is started or stopped. However, the
rotation speed of the BHA is affected by the interaction between the drill bit
(40
in Figure 2) and drill string with the formations (13 in Figure 1), and
frictional
forces between the various components of the BHA and the wall of the wellbore
(22 in Figure 1). In some cases, the drill string is known to stop rotating
completely, becoming rotationally "stuck" for some time intervals in some
conditions of excessive bit torque and/or poor hole cleaning. The drill string
may
remain rotationally stuck until the torque applied to the drill string from
surface
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CA 02620905 2008-03-12
exceeds a breakdown value, whereupon the drill string resumes rotation.
However, during the time the bit (or lower portion of the BHA) is not
rotating, the
drill string above the BHA up to the surface (up to top drive 14 in Figure 1)
is still
rotating. As is known in the art, the drill string above the BHA, up to the
earth's
surface, may absorb a substantial amount of rotation from the surface,
sometimes
as many as three or more full rotations of the pipe, before enough torque is
applied to the stuck part of the drill string to cause the stuck part of the
drill string
to resume rotation. The torque stored in the drill string above the stuck part
may
release with considerable rotational acceleration when the stuck part of the
drill
string is finally freed to rotate. Such unwinding, when applied to the BHA,
exerts
considerable torque on the BHA components. Conversely, a large torque is
applied as a result of continued upper drill string rotation to that portion
of the
drill string which becomes stuck. In some cases, either from sticking or
unwinding, an amount of torque which can shear, yield or loosen threaded
connections between the components of the BHA and drill string may result from
the magnitude of the angular acceleration applied during such "wind up" and
release rotation of the BHA and drill string. Therefore, in the embodiment
illustrated in Figure 12, an angular acceleration is measured, typically but
not
necessarily exclusively by the MWD system. Threshold maximum torques (in
both directions of rotation), which are related to a shear failure value or a
release
(connection "break out") value of the threaded connections is determined for
each
threaded connection in the BHA. Failure values of torque for any or all of the
tubular components of the drill string may also be determined. The threshold
torques, shown at 78A and 78B, may be determined, in some embodiments, by
treating multiple drill string components either side of a threaded connection
as a
single mass, and assuming angular acceleration is substantially equal along
the
length of those drill string components. In some embodiments, a threshold
torque
may be related to a failure torque of one or more tubular components of the
drill
string.
CA 02620905 2008-03-12
A moment of inertia of each drill string and BHA component is known or
can be readily determined. A torque applied between each BHA component can
be determined from the component inertia values and from the measured angular
acceleration. The thresholds can be set to operationally significant
percentages of
the lowest torque which would cause breaking of a threaded connection or
loosening of a threaded connection in the BHA based upon such inputs as drill
string component material, connection type, thread lubricant friction factor
and
applied make-up torque. If the angular acceleration measured exceeds either
threshold 78A, 78B, such as shown at 76 in Figure 12, an indication of such
condition may be transmitted to the earth's surface as previously explained
with
respect to Figures 5-8. Upon receipt of such indication, the rig operator may
change one or more drilling operating parameters, or instigate operational
procedures such as reciprocation of the drill string or adjusting of drilling
fluid
formulation in order to reduce or eliminate the excessive angular
acceleration. As
was also previously explained, the calculation of whether the angular
acceleration
exceeds the selected threshold may also be performed at the earth's surface,
particularly when using a "wired" drill pipe such as disclosed in the Hall et
al.
application described above, or any other form of high speed telemetry.
In some embodiments, axial acceleration is measured at the BHA (42 in
Figure 1). Axial acceleration may be measured using the accelerometer shown at
58 in Figure 2, for example. In the processor (46 in Figure 2) a maximum value
of axial acceleration is determined in a selected time interval. A suitable
time
interval may be on the order of 5 to 20 seconds. The time interval is
ultimately
related to the time period of the previously described stick-slip motion of
the drill
string. The maximum axial acceleration is used to calculate a maximum axial
force on the components of the BHA by using the mass of the individual
components of the BHA and the acceleration determined as just explained. The
axial force is combined with the maximum torque determined as previously
explained with respect to Figure 12, to determine whether a safe combined
operating limit for the various components of the BHA is being exceeded.
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CA 02620905 2008-03-12
Methods for combining maximum torque with maximum axial force to determine
whether a BHA is operating within safety limits are well known in the art.
One embodiment of the invention includes estimating downhole rotational
accelerations from variations in the torque applied to the drill string by the
top
drive (14 in Figure 1). In this embodiment, as shown in the flow chart of
Figure
14, torque is measured at the surface. Next, the amplitude of the torque
variations
and average surface torque values are determined. It is assumed that the
variations in torque measured at the surface are related to variations in
torque
along the drill string and at the BHA. The torque variations thus estimated or
determined at the BHA and along the drill string are then converted to angular
accelerations, or used as torque values directly assuming the torque variation
is
generated at various points along the drill string, as explained above with
reference to Figure 12, to determine if a safe torque on components of the BHA
is
being exceeded. Calculating whether a safe torque is being exceeded may
include
assuming torque is being applied at selected points along the BHA, and
calculating torque from inertia of the BHA components disposed above and below
each selected point.
Another embodiment, which is described with reference to Figure 15,
includes measurement of RPM (rotational speed) using measurements from the
magnetometers or accelerometers in the MWD system (37 in Figure 1).
Maximum and minimum values of RPM may be determined by the processor (46
in Figure 2). At the surface, after communicating maximum and minimum RPM
to the surface such as by mud telemetry, a periodicity of the RPM is estimated
by
determining a periodicity of variations in torque measured at the surface. A
periodic waveform is then fitted to the RPM values communicated to the
surface.
The periodic waveform will have an amplitude that corresponds to the
difference
between the maximum and minimum RPM, and a periodicity that corresponds to
the periodicity of the torque variations. Then, maximum and minimum angular
accelerations may be estimated from the periodic waveform. The values of
angular acceleration may be used as in the embodiment described above with
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CA 02620905 2008-03-12
respect to Figures 12 and 13 to determine whether a safe torque is being
exceeded
in any of the components of the drill string or BHA. Alternatively, the RPM
values measured by the MWD system (37 in Figure 1) may be conducted to the
processor (46 in Figure 2) and fitted to a periodic waveform in the processor
(46
in Figure 2). Angular accelerations may then be determined from the periodic
waveform.
Another aspect of the invention is the determination of drill string
component wear rate by combining the determination of drill string movement
mode with calculated side forces, rotation rate and well bore and component
material properties. Referring to Figure 13, first at 80, the mode of motion
of the
drill string may be determined as previously explained with respect to Figures
9
and 11. If the mode of motion is determined to be stick slip or whirl, at 82,
the
process continues. If the mode is normal, at 84, models known in the art may
be
used to estimate wear. Next, at 86. expected side forces on the various
components of the drill string are determined, for example, using any one of a
number of "torque and drag" simulation programs known in the art. One such
torque and drag simulation computer program or "model" is sold under the trade
name WELLPLAN by Landmark Graphics Corp., Houston, TX. Such models
predict, for example, a necessary hookload and surface torque, using as
inputs,
among others, the drill string configuration, expected wellbore trajectory and
the
formations expected to be drilled in the form of friction factors. Such models
output, at any selected position along the drill string, a lateral force and
internal
stresses on the components of the drill string. In situations where the drill
string
rotates without destructive mode of motion ("normal rotation") the side
forces,
combined with wear rates calculable from the material properties of the
components of the drill string, the earth formations, and the composition of
the
drilling mud can provide a reasonable estimate of the rate of wear of the
various
components of the drill string as a result of the rubbing motion of the
various
components of the drill string on the wall of the wellbore. This is shown at
86 in
Figure 13. Alternatively, friction factors, normal rotation axial forces and
normal
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CA 02620905 2008-03-12
rotation drill string side forces (including buckling side forces) can be
determined
using as inputs for the torque and drag modeling actual parameters such as
free
rotating, up- and down-weights (hookloads of the drill string while raising
and
lowering the drill string) together with actual weight on bit, torque, RPM,
drill
string component lengths, diameters, stiffness and other descriptions,
wellbore
trajectory and diameters, and drilling fluid properties such as density.
As will be appreciated from the previous description of destructive modes
of motion, in particular stick-slip and forward whirl (wherein a precession of
the
drill string axis is in the same direction as the rotation of the drill
string), side
forces and the rates of rotation may change rapidly in such destructive modes.
For example, in stick-slip motion where forward whirl is occurring, the
rotational
speed of the drill string may vary from zero to several times the nominal rate
or
average rate of rotation of the drill string. Side force on the drill string
resulting
from forward whirl is related to the square of the rotational speed of the
drill
string. Therefore, a total side force on the drill string is related to the
sum of the
side force from normal rotation plus the forward whirl induced force.
In an embodiment of a method according to this aspect of the invention, a
next step is to estimate rotational speed of the drill string at selected
positions
along the drill string. How to make such estimates can be explained as
follows.
The surface rotation rate of the top drive (14 in Figure 1) or other surface
drive on
the drill string, and the average rpm over the entire drill string must be
substantially identical even over a relatively short time interval (typically
on the
order of 5 to 10 seconds). Rotational speed within one or more components of
the
BHA may be measured by using magnetometer measurements or angular
acceleration measurements as previously explained with respect to Figures 5
through 10. In one embodiment, the rotational speed of the drill string at any
position along the drill string can be determined by a linear interpolation of
rotational speed from the measured speed at the BHA to the measured speed at
the
surface. This is shown at 90 in Figure 13.
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CA 02620905 2008-03-12
In another embodiment, variation of the rotational speed at any position
along the length of the drill string can be estimated by linear interpolation
along
each drill string section of equal torsional stiffness. To account for
different
torsional stiffnesses of individual drill string components, it is first
necessary to
calculate angular position at the BHA with respect to time, and angular
position at
the surface with respect to time. Change in angular position is converted to
torque. The torque is converted to an equivalent angular displacement using as
a
scaling factor the torsional stiffness and length of each drill string
component.
The angular displacement or orientation at each position may then be converted
to
a rotational speed at each position, typically by differentiation with respect
to
time.
Discontinuities in rotational speed (in cases where the drill string
momentarily stops rotation at at least one location) can be modeled as
torsional
force increasing linearly with respect to time and increasing linearly over
the
length of the drill string from the earth's surface down to the stuck drill
string
location. While the stuck portion remains rotationally fixed, the torque
applied to
each section of the drill string is converted to an equivalent angular
displacement
using as a scaling factor the torsional stiffness and length of each drill
string
component. The angular displacement at each position may then be converted to
a rotational speed at each position. When the stuck portion of the drill
string
releases, stored torque above the stuck portion is applied to the previously
stuck
portion of the drill string. In an embodiment which accounts for stick slip
motion,
a position at which the drill string is stuck must be selected. Rotational
displacement or position with respect to time can then be interpolated, taking
into
account the torsional stiffness of each drill string component from the stuck
position to the earth's surface, just as in the previous embodiment. This is
shown
at 88 in Figure 13.
As is known in the art, forward whirl velocity is substantially equal to the
rotation rate of the drill string. The side force attributable to the forward
whirl is
then calculated based upon the rotation rate of the drill string (RPM) at each
CA 02620905 2008-03-12
position along the drill string, mass of each of the drill string components
and
whirl radius (the welibore radius less the drill string component radius). As
shown in Figure 14, the frictional torque per unit length r,,sf can be
calculated as
follows.
S=mx(R-r)x0)Z
in which S represents the centripetal force acting on the drill string
component, m represents the mass of the component, r represents the component
radius and R represents the wellbore radius. w represents the whirl velocity.
From the above expression, the torque can be calculated by the expression:
Vwsf =,uRS
In the preceding expression, g represents a coefficient of friction between
the welibore wall (100 in Figure 14) and the outer surface of the BHA
components (102 in Figure 14).
Next, based upon such inputs as axial loading at each position along the
drill string (which is determinable using a torque and drag model), bending
stiffness of each drill string component, drill string component dimensions
and the
previously determined whirl velocities, a contact length along a drill string
component (that may be variable if some components have tool joint upsets) is
calculated. Contact length is a length of rubbing contact between the drill
string
component and the welibore wall. The vector sum of the normal rotation drill
string side force and the calculated whirl dynamic centripetal force is then
distributed over the contact length for computing such parameters as total
dynamic side force along the affected drill string components. This is shown
generally at 94 in Figure 13.
The next step in the method includes calculating wear rate using the RPM,
total dynamic side force, contact length, wellbore friction factors (from the
torque
and drag model) and wear factors. Wear factors may be estimated, at 96 in
Figure
13, from empirical data derived from historical wear data and such related
26
CA 02620905 2008-03-12
parameters as drill string component material properties, hard-banding type
and
hard-banding thickness of any applied hardfacing materials, estimated dynamic
side forces, wellbore friction factors and duration of rotation. Calculating
the
wear rate for the drill string under observation is shown at 98 in Figure 13.
Another aspect of the invention is a method for determining the fatigue
rate of drill string components. One embodiment of the invention includes
adding
bending fatigue rates attributable to particular modes of motion of the drill
string
to fatigue rates computed from the bending, around wellbore trajectory
changes,
of normally rotating drill string components. The bending fatigue from normal
rotation may be calculated using the previously described torque and drag
models
such as the WELLPLAN model.
The first step in determining bending fatigue rate, and referring to Figure
15, is determining the drill string movement mode, at 104, including the
detection
of "backward whirl", at 106, "lateral bending", at 108, and "stick-slip" RPM
variation at any location in the drill string. Determining mode of motion of
the
drill string and the RPM at any point along the drill string may be performed
using embodiments such as previously explained herein. A speed of backward
whirl, if detected, may be calculated by methods known in the art. Existence
of
lateral bending may also be detected as previously explained. If no
destructive
mode of motion is detected, at 110, a conventional wear model known in the art
may be used to estimate wear and/or fatigue.
Axial forces and side forces (including buckling side forces) at each
position along the drill string can be determined using a torque and drag
model
such as the WELLPLAN model. Inputs to the torque and drag model may include
either estimates or actual parameters such as actual free rotating, up- and
down-
weights together with applied weight on bit, torque, RPM, drill string
component
lengths, diameters, stiffness and other descriptions, wellbore trajectory and
diameters, and fluid properties such as density.
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CA 02620905 2008-03-12
When backward whirl is detected, whirl velocity is then calculated using
the diameter of the affected drill string component, the wellbore diameter and
RPM applied at the surface. The rate of whirl bending is directly related to
the
whirl velocity and the RPM. The centripetal whirling side force attributable
to the
whirling is calculated from the mass of the affected component and the whirl
speed. A bending amplitude for affected components of the drill string can be
calculated from the whirl side force, normal side force, the lateral bending
stiffness of the affected components and the diameter of the affected
components
and proximate drill string components, at 118 in Figure 15.. The fatigue rate
is
then calculated for each laterally bending component using the calculated
bending
rates, RPM, bending amplitudes, and fatigue factors estimated from empirical
data derived from tracking historical fatigue measurements and such related
parameters as drill string component material properties, estimated dynamic
bending rates and duration of rotation.
In another embodiment, a fatigue rate attributable to lateral bending is
calculated. The frequency at which lateral bending takes place is related to
its
frequency, and lateral bending amplitude for each drill string component can
be
estimated from the dimensions of the affected drill string components and the
wellbore diameter. As previously explained, existence of lateral bending and
the
drill string component in which lateral bending is taking place may be
determined
by spectral analysis of acceleration data, for example. The fatigue rate is
then
calculated for each laterally bending component using the measured bending
rates, estimated bending amplitudes, and fatigue factors estimated from
empirical
data derived from tracking historical fatigue measurements and such related
parameters as drill string component material properties, historically
measured
dynamic bending rates, drill string component and wellbore dimensions, and
duration of bending.
As explained above with respect to Figures 13 and 14, frictional forces on
various components of the drill string, due to rotational movement of the
drill
string against the wall of the wellbore, can be estimated from the mode of
motion
28
CA 02620905 2008-03-12
of the drill string, the mass of the drill string components, and the rotation
rate of
the drill string. In one embodiment, the calculated frictional forces can be
used to
estimate an amount of torque which may be attributable to the condition of the
wellbore. In one embodiment, this amount of torque is estimated as an excess
of
an amount of torque needed to rotate the drill string from the surface (such
as by
top drive 14 in Figure 1) over the estimated drill string frictional forces
and
amount of torque needed to turn the drill bit (40 in Figure 1).
Referring to Figure 16, at 126, the amount of torque exerted as rotating
friction due to side forces on the drill string are determined as previously
explained above with respect to Figures 13 and 14. Note that if the mode of
motion determined (see, e.g., 84 in Figure 13) does not include forward whirl
or
rotational stick-slip, the amount of side force torque determined at 126 will
be
substantially equal to zero.
At 128, the so-called "normal" torque needed to turn the drill string is
estimated. In one embodiment, normal side forces on the various components of
the drill string can be estimated using a torque and drag model known in the
art,
such as the model previously noted sold under the trade name WELLPLAN.
Using the rotary speed of the drill string, normal forces estimated from the
model,
and coefficients of friction of the earth formations (13 in Figure 1) and the
components of the drill string, a good estimate of the amount of torque needed
to
turn the drill string from the earth's surface can be made.
At 130 in Figure 16, an amount of torque needed to turn the drill bit (40 in
Figure 1) is estimated or measured. Measuring torque needed to turn the drill
bit
can be performed by various torque sensors known in the art which are included
in the BHA (42 in Figure 1). One such sensor is sold under the trade name
COPILOT by Baker Hughes, Inc., Houston, Texas. Alternatively, the torque used
to turn the bit can be estimated by, for example, historical data on similar
earth
formations to the one being drilled, and for drill bits the same as or similar
to the
bit being used. Other data used to estimate bit torque may include rotary
speed of
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CA 02620905 2008-03-12
the bit and amount of axial force (weight) applied to the bit. As is known in
the
art, the axial force on the bit can be determined by a sensor in the BHA such
as
the previously referred to COPILOT sensor, or may be estimated from the
surface
measurements (such as by sensor 14B in Figure 1).
At 132 in Figure 16, the values of torque measured and/or estimated as
explained above at 126, 128 and 130 are added and are compared to the amount
of
torque actually exerted by the top drive (14 in Figure 1). As explained above
with
respect to Figure 1, the torque can be measured by a suitable sensor, such as
shown at 14B. If the condition of the wellbore is such that nothing in the
wellbore causes any additional friction, the sum of the measured/estimated
torques should substantially equal the torque exerted by the top drive (14 in
Figure 1). In this embodiment, an amount of torque exerted by the top drive
which exceeds the sum of the measured/estimated torques by a selected
threshold
amount can be used as an indication of unsuitable or even dangerous conditions
in
the wellbore. In some embodiments, the recording unit (12 in Figure 1) may be
programmed to send an alarm or other warning indicator to the drilling rig
operator if the threshold is exceeded.
Various embodiments of the invention provide a method and system for
identifying destructive modes of motion and excessive wear and/or fatigue
rates
of a drill string, such that a drilling rig operator may take corrective
measures
before a drill string component fails.
While the invention has been described with respect to a limited number
of embodiments, those skilled in the art, having benefit of this disclosure,
will
appreciate that other embodiments can be devised which do not depart from the
scope of the invention as disclosed herein. Accordingly, the scope of the
invention should be limited only by the attached claims.
