U.S. patent application number 17/026542 was filed with the patent office on 2021-01-14 for method for measuring surface torque oscillation performance index.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Ramakrishna Madhireddy, Nathaniel Wicks, Jian Wu.
Application Number | 20210010882 17/026542 |
Document ID | / |
Family ID | 1000005107668 |
Filed Date | 2021-01-14 |
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United States Patent
Application |
20210010882 |
Kind Code |
A1 |
Wu; Jian ; et al. |
January 14, 2021 |
METHOD FOR MEASURING SURFACE TORQUE OSCILLATION PERFORMANCE
INDEX
Abstract
A system and method for drilling a wellbore with a drill rig by:
rotating a drillstring and a drill bit with a drill rig drive
system; applying a weight of the drillstring on the drill rig;
measuring surface torque oscillations of the drill string via:
determining a fundamental oscillation time period; select a time
window based on the fundamental oscillation time period; collecting
torque present value data of the drill string for the selected time
window; determining an amplitude of torque oscillation from the
collected torque present value data; determining a reference
torque; and dividing the determined amplitude of torque oscillation
by the determined reference torque to obtain a surface torque
oscillation performance index, whereby the measurement of the
surface torque oscillations of the drill string is a fractional
value to indicate the magnitude and severity of surface torque
fluctuations of the drilling string; and modifying a drilling
parameter based on the surface torque oscillation performance
index.
Inventors: |
Wu; Jian; (Houston, TX)
; Madhireddy; Ramakrishna; (Houston, TX) ; Wicks;
Nathaniel; (Somerville, MA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
1000005107668 |
Appl. No.: |
17/026542 |
Filed: |
September 21, 2020 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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15846265 |
Dec 19, 2017 |
10782197 |
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17026542 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 19/166 20130101;
G01L 3/108 20130101; E21B 45/00 20130101; E21B 44/04 20130101; E21B
47/007 20200501 |
International
Class: |
G01L 3/10 20060101
G01L003/10; E21B 19/16 20060101 E21B019/16; E21B 45/00 20060101
E21B045/00; E21B 44/04 20060101 E21B044/04; E21B 47/007 20060101
E21B047/007 |
Claims
1-22. (canceled)
23. A method for drilling a wellbore with a drill rig, comprising:
rotating a drill string and a drill bit with a drill rig drive
system; and measuring surface torque oscillations of the drill
string, comprising: determining a fundamental oscillation time
period; selecting a time window based on the fundamental
oscillation time period; collecting torque present value data of
the drill string for the selected time window; determining an
amplitude of torque oscillation from the collected torque present
value data; determining a reference torque; and dividing the
determined amplitude of torque oscillation by the determined
reference torque to obtain a surface torque oscillation performance
index, whereby the measurement of the surface torque oscillations
of the drill string is a fractional value to indicate the magnitude
and severity of surface torque fluctuations of the drilling
string.
24. The method for drilling a wellbore as claimed in claim 23,
further comprising modifying at least one drilling parameter based
on the surface torque oscillation performance index.
25. The method for drilling a wellbore as claimed in claim 23,
further comprising displaying the surface torque oscillation
performance index on a display.
26. The method for drilling a wellbore as claimed in claim 23,
wherein the determining a fundamental oscillation time period
comprises determining based on at least one drill string parameter
selected from: drill string length, drill string shear modulus, and
drill string density.
27. The method for drilling a wellbore as claimed in claim 23,
wherein the determining the fundamental oscillation time period
comprises estimating based on at least one drill string parameter
selected from: drill string length, drill pipe length, drill collar
length, string shear modulus, string stiffness, drill string moment
of inertia, drill string density, drill pipe polar moment, and
drill collar polar moment.
28. The method for drilling a wellbore as claimed in claim 23,
wherein determining the reference torque comprises measuring at
least one of: an off-bottom torque, an at-bottom torque, and a top
drive rated torque.
29. The method for drilling a wellbore as claimed in claim 23,
wherein measuring the surface torque oscillations of the drill
string further comprises: filtering the collected torque present
value data; sorting the filtered torque present value data to
obtain a set of large values p and a set of small values q;
averaging the set of large values p and averaging the set of small
values q; and subtracting the average of the set of small values q
from the average of the set of large values p to obtain an
amplitude of torsional fluctuations; wherein the dividing collected
torque present value data by the determined reference torque
comprises dividing the amplitude of torsional fluctuations by the
determined reference torque to obtain the surface torque
oscillation performance index.
30. The method for drilling a wellbore as claimed in claim 28,
wherein the filtering the collected torque present value data
comprises at least one of: low pass filtering of frequencies at a
predetermined fixed value, and band pass filtering of frequencies
at predetermined fixed values.
31. The method for drilling a wellbore as claimed in claim 24,
wherein the modifying at least one drilling parameter comprises
modifying at least one drilling parameter selected from: drill
string rotational speed, weight of the drill string on the drilling
rig, slip stick mitigation control, and rate of penetration.
32. The method for drilling a wellbore as claimed in claim 23,
further comprising averaging the surface torque oscillation
performance indexes for selected fundamental oscillation time
periods.
33. The method for drilling a wellbore as claimed in claim 23,
further comprising polling the surface torque oscillation
performance indexes for selected fundamental oscillation time
periods.
34. A controller of a drill rig system having a drill string and a
drill bit, the controller comprising: a rotation receptor that
receives a signal corresponding to drill string rotation speed at
the drill rig; a torque receptor that receives a signal
corresponding to torque applied to the drill string at the drill
rig; a non-transitory storage medium that stores a set of computer
readable instructions; a processor to execute the instructions; and
a controller configured to: determine a fundamental oscillation
time period; select a time window based on the fundamental
oscillation time period; collect torque present value data of the
drill string for the selected time window; determine an amplitude
of torque oscillation from the collected torque present value data;
determine a reference torque; and divide the determined amplitude
of torque oscillation by the determined reference torque to obtain
a surface torque oscillation performance index, whereby the
measurement of the surface torque oscillations of the drill string
is a fractional value to indicate the magnitude and severity of
surface torque fluctuations of the drilling string.
35. The controller of a drill rig system as claimed in claim 34,
wherein the determining a fundamental oscillation time period using
a drill string parameter selected from: drill string length, drill
string shear modulus, and drill string density.
36. The controller of a drill rig system as claimed in claim 34,
wherein the determining the fundamental oscillation time period
comprises a drill string parameter selected from: drill string
length, drill pipe length, drill collar length, string shear
modulus, string stiffness, drill string moment of inertia, drill
string density, drill pipe polar moment, and drill collar polar
moment.
37. The controller of a drill rig system as claimed in claim 34,
wherein determining the reference torque comprises measuring at
least one of: an off-bottom torque, an at-bottom torque, and a top
drive rated torque.
38. The controller of a drill rig system as claimed in claim 34,
wherein the set of computer readable instructions stored in the
non-transitory storage medium comprise further instructions,
wherein when the further instructions are executed by the processor
allow the controller to measure the surface torque oscillations of
the drill string by: filtering the collected torque present value
data; sorting the filtered torque present value data to obtain a
set of large values p and a set of small values q; averaging the
set of large values p and averaging the set of small values q; and
subtracting the average of the set of small values q from the
average of the set of large values p to obtain an amplitude of
torsional fluctuations; wherein the dividing collected torque
present value data by the determined reference torque comprises
dividing the amplitude of torsional fluctuations by the determined
reference torque to obtain the surface torque oscillation
performance index.
39. The controller of a drill rig system as claimed in claim 38,
wherein the filtering the collected torque present value data
comprises at least one of: low pass filtering of frequencies at a
predetermined fixed value, and band pass filtering of frequencies
at predetermined fixed values.
40. The controller of a drill rig system as claimed in claim 34,
wherein the set of computer readable instructions stored in the
non-transitory storage medium comprise further instructions,
wherein when the further instructions are executed by the processor
allow the controller to modify at least one drilling parameter
selected from: drill string rotational speed, weight of the drill
string on the drilling rig, slip stick mitigation control, and rate
of penetration.
41. The controller of a drill rig system as claimed in claim 34,
wherein the set of computer readable instructions stored in the
non-transitory storage medium comprise further instructions,
wherein when the further instructions are executed by the processor
allow the controller to display the surface torque oscillation
performance index.
42. The controller of a drill rig system as claimed in claim 34,
wherein the set of computer readable instructions stored in the
non-transitory storage medium comprise further instructions,
wherein when the further instructions are executed by the processor
allow the controller to average the surface torque oscillation
performance indexes for selected fundamental oscillation time
periods.
43. The controller of a drill rig system as claimed in claim 34,
wherein the set of computer readable instructions stored in the
non-transitory storage medium comprise further instructions,
wherein when the further instructions are executed by the processor
allow the controller to poll the surface torque oscillation
performance indexes for selected fundamental oscillation time
periods.
44. The controller of a drill rig system as claimed in claim 34,
wherein the non-transitory storage medium is implemented in a
control device selected from PLC at Level 1 (Bottom), and an
industrial PC running middleware software at Level 2 (Middle).
Description
TECHNICAL FIELD
[0001] The present disclosure relates generally to the field of
drilling wells. More particularly, the invention concerns measuring
a surface torque oscillation performance index for controlling
drilling operations, starting/stopping stick slip mitigation
controls, and performance comparisons between drill rigs and stick
slip mitigation control algorithms.
BACKGROUND
[0002] Top drive is a drilling rig equipment that is located above
the rig floor and moves vertically along the derrick. It is a
rotational mechanical device providing primarily the torque that is
needed by the drilling bit to drill through formations. Top drive
is mostly controlled by an AC/DC variable frequency drive (VFD).
The VFD calculates and reports the torque values to the rig control
system.
[0003] High amplitude rotational oscillations of the drillstring
are a common problem while drilling. They are generated by the
combination of the torque generated by the interaction of the bit
with the hole-bottom and of the drillstring with the borehole
walls, and the lack of damping of the rotational oscillations. One
of the reasons that there is so little damping is that the bit-rock
interaction does not provide any damping, and indeed can amplify
the oscillations.
[0004] As explained in SPE 18049, slip-stick motion of the bottom
hole assembly can be regarded as extreme, self-sustained
oscillations of the lowest torsional mode, called the pendulum
mode. Such a motion is characterized by finite time intervals
during which the bit is non-rotating and the drill pipe section is
twisted by the rotary table or top drive. When the drillstring
torque reaches a certain level (determined by the static friction
resistance of the bottom hole assembly), the bottom hole assembly
breaks free and speeds up to more than twice the nominal speed
before it slows down and again comes to a complete stop. It is
obvious that such motion represents a large cyclic stress in the
drill pipe that can lead to fatigue problems. In addition, the high
bit speed level in the slip phase can induce severe axial and
lateral vibrations in the bottom hole assembly which can be
damaging to the connections. Finally, it is likely that drilling
with slip-stick motion leads to excessive bit wear and also a
reduction in the penetration rate. Frequency analysis of the
driving torque associated with torsional drillstring vibrations, in
particular slip-stick oscillations, reveals that a large number of
torsional drillstring resonances. The sharpness of the curve at the
drillstring resonance frequencies suggest there is little damping
of torsional drillstring vibrations. Halsey, Kyllingstad, and
Kylling, "Torque Feedback Used to Cure Slip-Stick Motion," SPE
18049, 1988.
[0005] Stick slip generates torsional waves travelling from the
bottom of the drillstring back to the surface which are seen at the
top drive torque readings, which show oscillations in different
degrees of magnitude. Few prior art methods systematically
establish a surface torque oscillation measure. US2016/0076354,
incorporated herein in its entirety, discloses a method for
detecting stick-slip in a drill string by measuring the surface
torque values from at least one sensor over a selected time period.
The measured values are filtered using a band pass filter and the
frequency band of the filter is dynamically adjusted based on the
determined bit depth. The minimum and maximum torque values are
captured from the filtered data and a difference is determined
using these two values. The surface stick slip index (SSSI) is
determined by dividing the difference of the maximum and minimum
torque values by a moving average torque (times 2) over a contant
selected time period.
[0006] Potential concerns regarding this method of determining the
SSSI include: (1) the variable reference torque at the denominator;
and (2) a fixed time period. First, SSSI is a fractional value with
both numerator and denominator changing. The values of both
numberator and denominator at the time have to be known to
determine the magnitude of oscillation. Using a moving average
torque over a selected time period to calculate the SSSI may not be
an ideal way of representation of the stick slip when encountering
different formations where the average torque could be
significantly different for the same amount of magnitude (Max
Torque-Min Torque) of the oscillation. Second, SSSI uses a sliding
time window of selected time period to determine the maximum and
minimum torque values. It may not be efficient to use a fixed time
period as the oscillation time period varies greatly with hole
depth or string length. A fixed time period may have to use an
unnecessarily large value to be long enough to cover the cycle.
[0007] Thus, there is a need for a method and system that
systematically establishes the surface torque oscillation
measure.
SUMMARY
[0008] In accordance with the teachings of the present disclosure,
disadvantages and problems associated with providing a measure of
rotational oscillations are overcome by providing a Surface Torque
Oscillation Performance Index (STOPI). STOPI is a fractional value
to indicate the magnitude and severity of surface torque
fluctuations of a drilling rig, whose numerator is the difference
between the calculated maximum surface torque value and the minimum
one in a dynamically specified time period, and denominator is a
configurable constant torque value, e.g., top drive rated torque.
STOPI is calculated in real time, updated in a preset short time
period and reported to an external display. Therefore, the
denominator is a constant reference torque, and the varying time
window corresponds to the fundamental frequency of the drill string
so as to provide a more reponsive and current solution. The STOPI
provides a good way for a human drilling operator or a computer
controller to visualize whether slip stick oscillations are
happening, and if yes, mitigate via human or computer
interventions.
[0009] It may be helpful to drilling personnel, particularly when
downhole measurements are not available, to establish an effective
measure of surface torque oscillations (STOPI). On aspect of the
invention is for drilling personnel to use STOPI to: (1) be aware
of how much the surface torque oscillates during drilling operation
and accordingly adjust the rotational speed, weight on bit, and/or
rate of penetration to improve the situation; (2) decide whether to
start, stop or modify slip stick mitigation controls, if the
drilling rig is equipped with slip stick mitigation controls; and
(3) provide a universal standard for performance comparisons
between drilling rigs and/or mitigation control algorithms.
[0010] Another aspect of the invention is to provide a method for
drilling a wellbore with a drill rig, the method comprising:
rotating a drillstring and a drill bit with a drill rig drive
system; applying a weight of the drillstring on the drill rig;
measuring surface torque oscillations of the drill string,
comprising: determining a fundamental oscillation time period;
selecting a time window based on the fundamental oscillation time
period; collecting torque present value data of the drill string
for the selected time window; determining an amplitude of torque
oscillation from the collected torque present value data;
determining a reference torque; and dividing the determined
amplitude of torque oscillation by the determined reference torque
to obtain a surface torque oscillation performance index, whereby
the measurement of the surface torque oscillations of the drill
string is a fractional value to indicate the magnitude and severity
of surface torque fluctuations of the drilling string; and
modifying a drilling parameter based on the surface torque
oscillation performance index.
[0011] Another aspect of the invention provides a controller of a
drill rig system having a drillstring and a drill bit, the
controller comprising: a rotation receptor that receives a signal
corresponding to drillstring rotation speed at the drill rig; a
torque receptor that receives a signal corresponding to torque
applied to the drillstring at the drill rig; a processor; a
non-transitory storage medium; and a set of computer readable
instructions stored in the non-transitory storage medium, wherein
when the instructions are executed by the processor allow the
controller to measure surface torque oscillations of the drill
string by: determining a fundamental oscillation time period;
selecting a time window based on the fundamental oscillation time
period; collecting torque present value data of the drill string
for the selected time window; determining an amplitude of torque
oscillation from the collected torque present value data;
determining a reference torque; and dividing the determined
amplitude of torque oscillation by the determined reference torque
to obtain a surface torque oscillation performance index, whereby
the measurement of the surface torque oscillations of the drill
string is a fractional value to indicate the magnitude and severity
of surface torque fluctuations of the drilling string.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] A more complete understanding of the present embodiments may
be acquired by referring to the following description taken in
conjunction with the accompanying drawings, in which like reference
numbers indicate like features.
[0013] FIG. 1 illustrates a basic diagram of a drill rig in the
process of drilling a well wherein there is a control system.
[0014] FIG. 2 shows a schematic diagram of a rig control system and
other drilling rig components.
[0015] FIG. 3 is a flow chart of an algorithm for measuring surface
torque oscillations of a drill string.
[0016] FIG. 4 is a schematic diagram illustrating levels of control
devices in a control architecture.
[0017] FIG. 5A is a plot of raw torque values for a drill string
simulation model.
[0018] FIG. 5B is a plot of low pass and band pass filtered torque
values for the drill string simulation model.
[0019] FIG. 5C is a double y-axis plot of data for the drill string
simulation model, wherein the left axis shows STOPI values and the
right axis shows the oscillation magnitudes.
[0020] FIG. 6A is a plot of raw torque values for a drill string
field test.
[0021] FIG. 6B is a plot of low pass and band pass filtered torque
values for the drill string field.
[0022] FIG. 6C is a double y-axis plot of data for the drill string
field test, wherein the left axis shows STOPI values and the right
axis shows the oscillation magnitudes.
DETAILED DESCRIPTION
[0023] Preferred embodiments are best understood by reference to
FIGS. 1-6C below in view of the following general discussion. The
present disclosure may be more easily understood in the context of
a high level description of certain embodiments.
[0024] FIG. 1 is a basic diagram of a drill rig 10 in the process
of drilling a well. The drilling rig 10 comprises a drilling rig
floor 11 that is elevated and a derrick 12 that extends upwardly
from the floor. A crown block 13 is positioned at the top of the
derrick 12 and a traveling block 14 is suspended therefrom. The
traveling block 14 may support a top drive 15. A quill 16 extends
from the bottom side of the top drive 15 and is used to suspend
and/or turn tubular drilling equipment as it is raised/lowered in
the wellbore 30. A drillstring 17 is made up to the quill 16,
wherein the drillstring 17 comprises a total length of connected
drill pipe stands, or the like, extending into the well bore 30.
One or more motors housed in the top drive 15 rotate the
drillstring 17. A drawworks 18 pays out and reels in drilling line
19 relative to the crown block 13 and traveling block 14 so as to
hoist/lower various drilling equipment.
[0025] As shown in FIG. 1, a new stand of drillstring 17 has been
made up as the lower portion of the drillstring 17 is suspended
from the rig floor 11 by a rotary table 20. Slips 21 secure the
suspended portion of the drillstring 17 in the rotary table 20. A
bottom hole assembly 22 is fixed to the lower end of the
drillstring 17 and includes: a drill bit 23 for drilling through a
formation 24; a positive displacement motor (PDM) 32; and a
measurement while drilling (MWD) module 33.
[0026] During the drilling process, drilling mud may be circulated
through the wellbore 30 to remove cuttings from around the drill
bit 23. A mud pump 25 pumps the drilling mud through a discharge
line 26, stand pipe 27, and rotary hose 28 to supply drilling mud
to the top drive 15. Drilling mud flows from the top drive 15 down
through the drillstring 17, where it exits the drillstring 17
through the drill bit 23. From the drill bit 23, the drilling mud
flows up through an annulus 31 existing between the wellbore 30 and
the drillstring 17 so as to carry cuttings away from the drill bit
23. A return line 29 allows the drilling mud to flow from the top
of the annulus 31 into a mud pit 33. Of course, the mud pump 25 is
supplied drilling mud from the mud pit 33. The drilling mud
typically passes through a series of shakers, separators, etc. (not
shown) to separate the cuttings from the drilling mud before the
mud is circulated again by the mud pump 25.
[0027] Referring again to FIG. 1, a rig control system 40 may be
used to determine whether slip stick oscillations are occurring.
The rig control system 40 may be configured to receive drilling
parameter data and drilling performance data related to operations
of the drilling rig 10. The drilling parameter data and drilling
performance data may comprise measurements monitored by a number of
sensors 41 placed about the drilling rig 10, e.g., a top drive VFD,
a torque sub, the drawworks 18, the traveling block 14, the top
drive 15, the mud pump 25, and the measurement while drilling (MWD)
module 33 as shown in the illustrated embodiment. The sensors 41
may monitor current, voltage, resistivity, force, position, torque,
weight, strain, speed, rotational speed, oscillation or any other
measurement related to drilling parameters or drilling performance,
and relevant input may be aggregated as raw sensor measurements or
as scaled engineering values. The rig control system 40 may receive
drilling parameter data and drilling performance data directly from
the sensors 41, retrofitted to certain pieces of equipment on the
drilling rig 10, such that the sensors 41 effectively form part of
the drilling system. This type of data acquisition may allow for
higher sampling rates to be used for monitoring relevant drilling
parameters and drilling performance metrics.
[0028] Several components of the drill rig 10 may also comprise
control actuators 42. For example, the drawworks 18 may comprise an
actuator 42 that allows a controller to control the workings of the
drawworks 18. The top drive 15 and mud pump 25 may also have
actuators 42. The actuators 42 allow a supervisory controller to
control various aspects of the drilling process, for example: bit
rotation speed, drillstring rotation direction, weight on bit,
drilling mud fluid pressure, drilling mud fluid flow rate, drilling
mud density, etc.
[0029] Referring to FIG. 2, a schematic of a rig control system 40
and other drilling rig components is illustrated. The rig control
system 40 may comprise a processor 43 that may receive various
inputs, such as the drilling parameter data and drilling
performance data, from sensors 41. In addition, the processor 43
may be operably coupled to a memory 47 and a storage 48 to execute
computer executable instructions for carrying out the presently
disclosed techniques. These instructions may be encoded in
software/hardware programs and modules that may be executed by the
processor 43. The computer codes may be stored in any suitable
article of manufacture that includes at least one tangible
non-transitory, computer-readable medium (e.g., a hard drive) that
at least collectively stores these instructions or routines, such
as the memory 47 or the storage 48. A STOPI module 49 may comprise
hardware/software for providing STOPI measurements and
determinations.
[0030] In some embodiments, the STOPI algorithms may be located in
the STOPI module 49. In other embodiments, the STOPI algorithms may
be located on programmable logic controllers (PLCs) that control
the drilling rig actuators themselves. In some embodiments, the
STOPI algorithms may be implemented in a software layer above the
PLC layer. Systems and methods that reduce or dampen torsional
drillstring vibrations, in particular slip-stick oscillations and
torsional drillstring resonances (mitigation slip stick control),
may be used with a rig control system as disclosed in US
Publication No. 2016/0290046, incorporated herein by reference in
its entirety.
[0031] Referring to FIG. 3, a block diagram of algorithm 300
according to one aspect of the present invention is illustrated.
The first step of algorithm 300 is to collect 310 the torque
present value (RawTrqPv), which may be collected from either the
VFD related to the top drive 15 (not shown in FIG. 1), or a torque
sub located between the top drive 15 and the drillstring 17 (also
not shown in FIG. 1).
[0032] Next, the torque present value (RawTrqPv) data is low pass
or band pass filtered 320. The cutoff frequencies are predetermined
fixed values. If the formations to be drilled for the well are
known as fairly constant, low pass filter may apply, otherwise,
band pass filter should apply.
[0033] Parameters of the drill string length (hole depth) and drill
string properties are then collected 330 from either local control
or supervisory control at higher level of a hierarchical control
network.
[0034] The algorithm 300 then calculates 340 the length of the
moving window by first estimating the fundamental oscillation time
period T.sub.1. Any existing technique may be used to derive the
fundamental time period T.sub.1. For example, one method is to use
equations (1)-(3) from A. Kyllinstad and G. W. Halsey, "A Study of
Slip/Stick Motion of the Bit," SPE Drilling Engineering, pgs.
369-373, December 1988, incorporated herein in its entirety. For a
drillstring composed of a drillpipe section of length L.sub.1 and a
uniform drill-collar section of length L.sub.2, a good
approximation for inertia is
J = .rho. I 1 L 1 3 + .rho. I 2 L 2 ( 1 ) ##EQU00001##
where J is the moment of inertia of the drill string, .rho. is
density, and I.sub.1 and I.sub.2, respectively, are the
cross-sectional polar moments of drilling pipe and drill collar.
The torsional stiffness K is just
K = G I 1 L 1 ( 2 ) ##EQU00002##
where G is the shear modulus of the drillstring material. Where
K J ##EQU00003##
is the angular eigen frequency, the fundamental time period T.sub.1
is calculated as
T 1 = 2 .pi. K J ( 3 ) ##EQU00004##
Equation (4) establishes the time interval T for the moving window
where a is a safety factor typically set between 1.0 and 2.0to
ensure the moving window covers a full cycle of oscillation at the
time. Based on T, the length of moving window can be determined by
dividing the control system sampling time .DELTA.T with T. If
necessary, the window length is rounded to be an integer.
T=.alpha.T.sub.1 (4)
[0035] Next, the algorithm 300 sorts 350 the stored torque value
array (with the size of window length) to obtain the largest values
p and lowest values q, where p and q are integers equal to or
larger than 1.
[0036] Algorithm 300 then subtracts 360 the average of the q values
from the average of the p values derived from the sorted torque
value array. The difference between the two resulting average
values provides an amplitude of torsional fluctuations.
[0037] The next step in the algorithm 300 is to divide 370 the
resulting difference value (amplitude of torsional fluctuations) by
selected constant reference torque values. The default setting is a
rated torque of the top drive 15. The reference torque values can
also be off-bottom torque, at-bottom torque, etc. Off-bottom torque
is measured by rotating off bottom (ROffB), which is where the pipe
rotates without any axial movement, such as rate of penetration or
tripping, there is no weight on bit (WOB) or torque on bit (TOB)
because the bit is not engaged with the formation. At-bottom torque
is measured by rotating on bottom (ROnB), which is where the pipe
rotates without any axial movement, such as rate of penetration or
tripping, but weight on bit (WOB) and torque on bit (TOB) are
present because bit is engaged with the formation. The selection of
reference torque may be dependent on the availability and the
choice of rig personnel. The quotient of the division is a Surface
Torque Oscillation Performance Index (STOPI).
[0038] According to a further step of the algorithm 300, the STOPI
value calculated from the division step is limited 380 between a
configurable maximum and minimum.
[0039] Finally, the algorithm 300 displays 390 the STOPI on an
external display such as a HMI or a computer screen. The display
update time is generally longer than .DELTA.T. Therefore, the
algorithm 300 may use either a polling method or the average value
for the purpose of display.
[0040] In addition, the algorithm 300 steps are executed as STOPI
calculation is enabled. When the calculation is disabled based on
preset conditions (such as bit not at bottom, TD speed setpoint
changes, and drilling controller off), a `null` value or a high
mark integer value would be assigned to STOPI for logging, which
also clarifies the `disabled` status without misleading.
[0041] The STOPI algorithm can be implemented as part of the rig
control system. Referring to FIG. 4, control levels are illustrated
for a drilling rig control system. A significant difference between
each of the control levels is to what degree software programs or
algorithms may be edited or reprogrammed after the original
software programs or algorithms have been embedded in the hardware.
A further distinction between the levels is the speed of the
communications between devices at the control level.
[0042] Level 0 (Field) comprises sensors and actuators for a
variety of drilling subsystems. Example subsystems include a
drilling fluid circulation system (which may include mud pumps,
valves, fluid reconditioning equipment, etc.), a rig control system
(which may include hoisting equipment, drillstring rotary mover
equipment (such as a top drive and/or rotary table), a PHM, a
catwalk, etc.), a managed pressure drilling system, a cementing
system, a rig walk system, etc. Level 0 (Field) may comprise a high
speed controller, such as a variable frequency drive (VFD). Level 0
(Field) hardware devices may be programmed with software by the
manufacturer and the software may be less suitable for modification
unless performed by the manufacturer.
[0043] Level 1 (Bottom) comprises direct control devices for
directly controlling the Level 0 (Field) subsystems. Level 1
(Bottom) direct controllers can include programmable logic
controllers (PLCs), processors, industrial computers, personal
computer based controllers, soft PLCs, the like, and/or any example
controller configured and operable to receive sensor data from
subsystem sensors and/or transmit control instructions to subsystem
equipment. Level 1 (Bottom) processors may be, comprise, or be
implemented by one or more processors of various types operable in
the local application environment, and may include one or more
general purpose processors, special-purpose processors,
microprocessors, digital signal processors (DSPs),
field-programmable gate arrays (FPGAs), application-specific
integrated circuits (ASICs), processors based on a multi-core
processor architecture, and/or other processors. More particularly,
examples of a processor include one or more INTEL microprocessors,
microcontrollers from the ARM and/or PICO families of
microcontrollers, embedded soft/hard processors in one or more
FPGAs, etc. Sensors and various other components may transmit
sensor data and/or status data to a direct controller, and
controllable components may receive commands from a direct
controller to control operations of the controllable components.
One or more aspects disclosed herein may allow communication
between direct controllers of different subsystems through virtual
networks. Sensor data and/or status data may be communicated
through virtual networks and a common data bus between direct
controllers of different subsystems. Level 1 (Bottom) direct
controllers may be programmed and deployed, but with relative
difficulty. Programmed software may thereafter be configured and
edited, but with relative difficulty. Only very rigid computer
programing is possible. A field bus is used to communicate with
Level 1 (Bottom) direct controllers via protocols, such as Ethernet
CAT, ProfiNET, ProfiBus, Modbus, etc. Processor 43 is an example of
a Level 1 (Bottom) device. (See FIG. 2).
[0044] Level 2 (Middle) comprises coordinated control devices.
These include a variety of computing devices, for example,
computers, such as industrial PC, processors, domain controllers,
programmable logic controllers (PLCs), industrial computers,
personal computers based controllers, soft PLCs, the like, and/or
any example controller configured and operable to receive
information and data available on a Level 2 network, and transmit
control commands and instructions to direct controllers at Level 1,
which directly control subsystem equipment. Level 2 (Middle)
processors may be, comprise, or be implemented by one or more
processors of various types operable in the local application
environment, and may include one or more general purpose
processors, special-purpose processors, microprocessors, digital
signal processors (DSPs), field-programmable gate arrays (FPGAs),
application-specific integrated circuits (ASICs), processors based
on a multi-core processor architecture, and/or other processors.
More particularly, examples of a processor include one or more
INTEL microprocessors, microcontrollers from the ARM and/or PICO
families of microcontrollers, embedded soft/hard processors in one
or more FPGAs, etc. Level 2 (Middle) coordinated controllers may be
programmed and deployed relatively easily as high level programming
languages, such as C/C++, may be used with software program running
in a real time operating system (RTOS). A real time communication
databus is used to communicate with Level 2 (Middle) coordinated
controllers via protocols, such as TCP/IP and UDP.
[0045] Level 3 (Top) comprises process monitoring devices that do
not control, but merely monitor activity and provide information to
the controlling devices at lower levels. Any computing device known
to persons of skill in the art may perform Level 3 functions.
[0046] A control system implementing the STOPI algorithm may either
be implemented in PLC at Level 1 (Bottom), or in an industrial PC
running a real time operating system at Level 2 (Middle), or in a
server computer or a virtual machine at any level. Typically, the
STOPI algorithm may be implemented either on PLCs at Level 1
(Bottom) or in a middleware software layer at Level 2 (Middle). A
supervisory controller that may implement mitigation slip stick
controls may be implemented either in a middleware software layer
at Level 2 (Middle) or at Level 3 (Top).
[0047] According to one embodiment of the invention, a surface
torque oscillation performance index (STOPI) is displayed on a
display 46 (see FIG. 2) and a human drilling operator may then use
the STOPI to decide whether to modify a drilling parameter. For
example, in response to a displayed STOPI, the drilling operator
may decide whether to modify the drill string rotational speed, the
weight of the drill string on the drilling rig, and/or the rate of
penetration. As a further example, the drilling operator may decide
whether to start, stop or modify a slip stick mitigation
control.
[0048] Referring to FIGS. 5A through 5C, example data collected
from a drill string simulation model is illustrated for the STOPI
algorithm. FIG. 5A shows raw torque values from the drill string
simulation model. FIG. 5B illustrates the low pass and band pass
filtered torque values from the drill string simulation model. FIG.
5C shows a double y-axis plot as left axis shows STOPI values and
right axis shows the oscillation magnitudes. TD rated torque of
50,000 N.m is used as reference torque (denominator). In this drill
string simulation model example, the moving window time T is at 5
secs where the oscillation frequency is at about 0.21 Hz. A polling
method shows a new STOPI value every 500 ms and .DELTA.T=1 ms.
[0049] Referring to FIGS. 6A through 6C, example data collected
from a drill string field test is illustrated for the STOPI
algorithm. FIG. 6A shows raw torque values from the drill string
simulation model. FIG. 6B illustrates the low pass and band pass
filtered torque values from the drill string simulation model. FIG.
6C shows a double y-axis plot as left axis shows STOPI values and
right axis shows the oscillation magnitudes. TD rated torque of
50,000 N.m is used as reference torque (denominator). In this drill
string field test example, the moving window time T=2 sec and the
fundamental frequency is about 0.67 Hz. STOPI values are shown
every .DELTA.T=5 ms.
[0050] In alternative embodiments, drilling control methods
implement a combination of control algorithms based on at least one
of the algorithms disclosed in this specification with any other
known control algorithm. It is specifically contemplated that
control algorithms are implemented in combination. [0051] [1]
Although the disclosed embodiments are described in detail in the
present disclosure, it should be understood that various changes,
substitutions and alterations can be made to the embodiments
without departing from their spirit and scope.
* * * * *