U.S. patent application number 15/705393 was filed with the patent office on 2018-01-04 for automated directional drilling apparatus and methods.
The applicant listed for this patent is Nabors Drilling Technologies USA, Inc.. Invention is credited to Scott Gilbert BOONE, Brian ELLIS, Colin GILLAN, Beat KUTTEL.
Application Number | 20180003026 15/705393 |
Document ID | / |
Family ID | 40522313 |
Filed Date | 2018-01-04 |
United States Patent
Application |
20180003026 |
Kind Code |
A1 |
BOONE; Scott Gilbert ; et
al. |
January 4, 2018 |
AUTOMATED DIRECTIONAL DRILLING APPARATUS AND METHODS
Abstract
A system and method for calculating a path during drilling of a
BHA between first and second survey points. The method includes
calculating an amount of first incremental progress made by the BHA
since the first survey point; calculating a first estimate of a
first current location based on the first survey point and the
amount of first incremental progress; causing at least one drilling
parameter to be modified in order to alter a drilling direction of
the BHA based on the first estimate; calculating an amount of
second incremental progress made by the BHA; calculating a second
estimate of the second current location based on the amount of
second incremental progress and an aggregation of data received
from the BHA, including data associated with the first survey
point; and causing at least one drilling parameter to be modified
in order to alter the drilling direction of the BHA.
Inventors: |
BOONE; Scott Gilbert;
(Houston, TX) ; ELLIS; Brian; (Spring, TX)
; GILLAN; Colin; (Houston, TX) ; KUTTEL; Beat;
(Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Nabors Drilling Technologies USA, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
40522313 |
Appl. No.: |
15/705393 |
Filed: |
September 15, 2017 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
14174522 |
Feb 6, 2014 |
9784089 |
|
|
15705393 |
|
|
|
|
12234584 |
Sep 19, 2008 |
8672055 |
|
|
14174522 |
|
|
|
|
11859378 |
Sep 21, 2007 |
7823655 |
|
|
12234584 |
|
|
|
|
11952511 |
Dec 7, 2007 |
7938197 |
|
|
11859378 |
|
|
|
|
11859378 |
Sep 21, 2007 |
7823655 |
|
|
11952511 |
|
|
|
|
11847048 |
Aug 29, 2007 |
9410418 |
|
|
12234584 |
|
|
|
|
11668388 |
Jan 29, 2007 |
8215417 |
|
|
11847048 |
|
|
|
|
11747110 |
May 10, 2007 |
7860593 |
|
|
12234584 |
|
|
|
|
60869047 |
Dec 7, 2006 |
|
|
|
60985869 |
Nov 6, 2007 |
|
|
|
60886259 |
Jan 23, 2007 |
|
|
|
60985869 |
Nov 6, 2007 |
|
|
|
61016093 |
Dec 21, 2007 |
|
|
|
61026323 |
Feb 5, 2008 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 44/02 20130101;
E21B 7/04 20130101 |
International
Class: |
E21B 44/02 20060101
E21B044/02; E21B 7/04 20060101 E21B007/04 |
Claims
1. A method for calculating a path during drilling which comprises:
receiving, by a surface steerable system coupled to a drilling rig,
first survey data corresponding to survey sensor information from a
bottom hole assembly (BHA) located in a borehole and coupled to a
drill string, wherein the first survey data corresponds to a
location of the BHA at a first survey point; receiving, by the
surface steerable system coupled to the drilling rig, a first tool
face measurement set from the BHA located in the borehole and
coupled to the drill string, wherein the first tool face
measurement set corresponds to a first current location of the BHA
between the first survey point that has been passed and a second
directly sequential survey point that has not yet been reached;
calculating, by the surface steerable system, an amount of first
incremental progress made by the BHA since the first survey point;
calculating, by the surface steerable system, a first estimate of
the first current location based on the first tool face measurement
set, the first survey data from the first survey point, and the
amount of first incremental progress; causing, by the surface
steerable system, at least one drilling parameter to be modified in
order to alter a drilling direction of the BHA based on the first
estimate if the surface steerable system determines that the first
estimate indicates the drilling direction needs to be altered;
receiving, by the surface steerable system coupled to the drilling
rig, a second tool face measurement set from the BHA located in the
borehole and coupled to the drill string, wherein the second tool
face measurement set corresponds to a second current location of
the BHA between the first survey point that has been passed and the
second directly sequential survey point that has not yet been
reached; calculating, by the surface steerable system, an amount of
second incremental progress made by the BHA since the first
incremental progress was calculated; calculating, by the surface
steerable system, a second estimate of the second current location
based on the amount of second incremental progress and an
aggregation of the second tool face measurement set, the first tool
face measurement set, and the first, survey data; and causing, by
the surface steerable system, at least one drilling parameter to be
modified in order to alter the drilling direction of the BHA based
on the second estimate if the surface steerable system determines
that the second estimate indicates the drilling direction needs to
be altered.
2. The method of claim 1, further comprising: receiving, by the
surface steerable system, second survey data corresponding to
survey sensor information from the second directly sequential
measured survey point; updating, by the surface steerable system, a
current toolface and a third current estimate of a third current
location of the BHA based on the second survey data; wherein the
third current location of the BHA, the second current location of
the BHA, and the first current location of the BHA together form a
first plurality of locations representing a path of the BHA between
the first survey point and the second survey point; and repeating,
by the surface steerable system, the steps of receiving and
calculating to estimate a second plurality of locations
representing a path of the BHA between the second directly
sequential measured survey point and a directly sequential third
measured survey point.
3. The method of claim 2, further comprising modifying, by the
surface steerable system, how the amount of incremental progress is
calculated for the second plurality of locations based on the
second survey data.
4. The method of claim 1, wherein the second estimate of the second
current location is further based on the resultant effect of an
average of data from the second tool face measurement set, the
first tool face measurement set, and the first survey data.
5. The method of claim 1, wherein the BHA is performing a sliding
operation, and wherein the method further comprises displaying a
progress of the sliding operation on a graphical user
interface.
6. The method of claim 5, wherein displaying the progress of the
sliding operation comprises displaying the first estimate and the
second estimate.
7. The method of claim 1, further comprising drilling, by the
drilling rig, using the altered direction of the BHA.
8. The method of claim 1, wherein the amount of first incremental
progress is about a foot.
9. The method of claim 1, wherein the first tool face measurement
set further corresponds to a first current orientation of the BHA
at the first current location of the BHA; and wherein causing, by
the surface steerable system, at least one drilling parameter to be
modified is further based on the first current orientation of the
BHA.
10. The method of claim 1, further comprising calculating a
projected path based on the first survey data, the first estimate,
and the second estimate.
11. A method for calculating a path during drilling of a bottom
hole assembly (BHA) between a first survey point that has been
passed and a second directly sequential survey point that has not
been reached, which comprises: calculating, by a surface steerable
system, an amount of first incremental progress made by the BHA
since the first survey point; calculating, by the surface steerable
system, a first estimate of a first current location based at least
on the first survey point and the amount of first incremental
progress; causing, by the surface steerable system, at least one
drilling parameter to be modified in order to alter a drilling
direction of the BHA based on the first estimate if the surface
steerable system determines that the first estimate indicates the
drilling direction needs to be altered; calculating, by the surface
steerable system, an amount of second incremental progress made by
the BHA since the first incremental progress was calculated;
calculating, by the surface steerable system, a second estimate of
a second current location based at least on the amount of second
incremental progress occurring since the first estimate and an
aggregation of data received from the BHA, wherein the data
received from the BHA comprises data associated with the first
survey point; and causing, by the surface steerable system, at
least one drilling parameter to be modified in order to alter the
drilling direction of the BHA based on the second estimate if the
surface steerable system determines that the second estimate
indicates the drilling direction needs to be altered.
12. The method of claim 11 wherein the BHA is performing a sliding
operation, and wherein the method further comprises displaying a
progress of the sliding operation on a graphical user
interlace.
13. The method of claim 12, wherein displaying the progress of the
sliding operation comprises displaying the first estimate and the
second estimate.
14. The method of claim 11, wherein the surface steerable system is
coupled to a drilling rig, and wherein the method further comprises
drilling, by the drilling rig, using the altered direction of the
BHA.
15. The method of claim 11, wherein the amount of first incremental
progress is about a foot.
16. The method of claim 11, receiving, by the surface steerable
system, a tool face measurement that corresponds to a current
orientation of the BHA at the first current location of the BHA;
and wherein causing, by the surface steerable system, at least one
drilling parameter to be modified is further based on the current
orientation of the BHA.
17. The method of claim 11, further comprising calculating a
projected path based on the first estimate and the second
estimate.
18. The method of claim 11, wherein the second estimate of the
second current location is further based on the resultant effect of
an average of data received from the BHA.
19. A surface steerable system for use with a drilling rig which
comprises: a network interface; a processor coupled to the network
interface; and a memory coupled to the processor, the memory
storing a plurality of instructions for execution by the processor,
the plurality of instructions including: instructions for
calculating, by the surface steerable system, an amount of first
incremental progress made by a bottom hole assembly (BHA) that is
coupled to the surface steerable system since a first survey point;
instructions for calculating, by the surface steerable system, a
first estimate of a first current location based at least on the
first survey point and the amount of first incremental progress;
instructions for causing, by the surface steerable system, at least
one drilling parameter to be modified in order to alter a drilling
direction of the BHA based on the first estimate if the surface
steerable system determines that the first estimate indicates the
drilling direction needs to be altered; instructions for
calculating, by the surface steerable system, an amount of second
incremental progress made by the BHA since the first incremental
progress was calculated; instructions for calculating, by the
surface steerable system, a second estimate of a second current
location, based at least on the amount of second incremental
progress occurring since the first estimate and an aggregation of
data received from the BHA, wherein the data received from the BHA
comprises data associated with the first survey point; and
instructions for causing, by the surface steerable system, at least
one drilling parameter to be modified in order to alter the
drilling direction of the BHA based on the second estimate if the
surface steerable system determines that the second estimate
indicates the drilling direction needs to be altered.
20. The surface steerable system of claim 19, wherein the plurality
of instructions further includes instructions for displaying a
progress of a sliding operation on a graphical user interface.
21. The surface steerable system of claim 19, wherein the plurality
of instructions further includes instructions for calculating, by
the surface steerable system, a current orientation of the BHA at
the first current location of the BHA; and wherein the instructions
for causing, by the surface steerable system, at least one drilling
parameter to be modified is further based on the current
orientation of the BHA.
22. The surface steerable system of claim 19, wherein the second
estimate of the second current location is further based on the
resultant effect of an average of data received from the BHA.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. patent
application Ser. No. 14/174,522, filed Feb. 6, 2014, now allowed
(Attorney Docket No, 38496.319), which is a continuation of U.S.
patent application Ser. No. 12/234,584, filed Sep. 19, 2008, now
U.S. Pat. No. 8,672,055 (Attorney Docket No. 38496.61), which is a
(1) a continuation-in-part of U.S. patent application Ser. No.
11/859,378, filed Sep. 21, 2007, now U.S. Pat. No. 7,823,655,
issued Nov. 2, 2010 (Attorney Docket No. 38496.12); (2) a
continuation-in-part of U.S. patent application Ser. No.
11/952,511, filed Dec. 1, 2007, now U.S. Pat. No. 7,938,197, issued
May 10, 2011 (Attorney Docket No. 38496.19), which is a
continuation-in-part of Ser. No. 11/859,378, filed Sep. 21, 2007,
now U.S. Pat. No. 7,823,655, issued Nov. 2, 2010 and which, claims
the benefit of (i) U.S. Provisional Patent Application No.
60/869,047, filed Dec. 7, 2006, now expired (Attorney Docket No.
38496.13) and (ii) U.S. Provisional Application No. 60/985,869,
filed Nov. 6, 2007, now expired (Attorney Docket No. (38496.45);
(3) a continuation-in-part of U.S. patent application Ser. No.
11/847,048, filed Aug. 29, 2007, now U.S. Pat. No. 9,410,418
(Attorney Docket No. 38496.14); (4) a continuation-in-part of U.S.
patent application Ser. No. 11/668,388, filed Jan. 29, 2007, now
U.S. Pat. No. 8,215,417, issued Jul. 10, 2012 (Attorney Docket No.
38496.21), which claims the benefit of U.S. Provisional Application
No, 60/886,259, filed Jan. 23, 2007, now expired (Attorney Docket
No. 38496.11); and (5) a continuation-in-part of U.S. patent
application Ser. No. 11/747,110, filed May 10, 2007, now U.S. Pat.
No. 7,860.593, issued Dec. 28, 2010 (Attorney Docket No. 38496.16);
and (6) which claims the benefit of: U.S. Provisional Patent
Application No. 60/985,869, filed Nov. 6, 2007, now expired
(Attorney Docket No, 38496.45): U.S. Provisional Patent Application
No. 61/016,093, filed Dec. 21, 2007, now expired (Attorney Docket
No. 38496.43); and U.S. Provisional Patent Application No,
61/026,323, filed Feb. 5, 2008, now expired (Attorney Docket No.
38496.46). The disclosure of each of the foregoing patent
applications is hereby incorporated herein in its entirety by
express reference thereto.
BACKGROUND
[0002] At the outset of a drilling operation, drillers typically
establish a drilling plan that includes a target location and a
drilling path to the target location. Once drilling commences, the
bottom hole assembly is directed or "steered" from a vertical
drilling path in any number of directions, to follow the proposed
drilling plan. For example, to recover an underground hydrocarbon
deposit, a drilling plan might include a vertical well to a point
above the reservoir, then a directional or horizontal well that
penetrates the deposit. The operator may then steer the drill,
through both the vertical and horizontal aspects in accordance with
the plan.
[0003] In some embodiments, such directional drilling requires
accurate orientation of a bent segment of the downhole motor that
drives the bit. In such embodiments, rotating the drill string
changes the orientation of the bent segment and the toolface. To
effectively steer the assembly, the operator must first determine
the current toolface orientation, such as via a
measurement-while-drilling (MWD) apparatus. Thereafter, if the
drilling direction needs adjustment, the operator must rotate the
drill string to change the toolface orientation. In other
embodiments, such as rotary steerable systems, the operator still
must determine the current tool face orientation.
[0004] During drilling, a "survey" identifying locational and
directional data of a BHA in a well is obtained at various
intervals or other times. Each survey yields a measurement of the
inclination and azimuth (or compass heading) of a location in a
well (typically the total depth at the time of measurement). In
directional wellbores, particularly, the position of the wellbore
must be known with reasonable accuracy to ensure the correct
wellbore path. The measurements themselves include inclination from
vertical and the azimuth of the wellbore. In addition to the
toolface data, and inclination, and azimuth, the data obtained
during each survey may also include hole depth data, pipe
rotational data, hook load data, delta pressure data (across the
downhole drilling motor), and modeled dogleg data, for example.
[0005] These measurements may be made at discrete points in the
well, and the approximate path of the wellbore may be computed from
these discrete points. Conventionally, a standard survey is
conducted at each drill pipe connection to obtain an accurate
measurement of inclination and azimuth for the new survey position.
However, if directional drilling operations call for one or more
transitions between sliding and rotating within the span of a
single drill pipe joint or connection, the driller cannot rely on
the most recent survey to accurately assess the progress or
effectiveness of the operation. For example, the driller cannot
utilize the most recent survey data to assess the effectiveness or
accuracy of a "slide" that is initiated after the survey was
obtained. The conventional use of surveys does not provide the
directional driller with any feedback on the progress or
effectiveness of operations that are performed after the most
recent survey measurements are obtained.
[0006] When deviation from the planned drilling path occurs,
drillers must consider the factors available to them to try to
direct the drill back to the original path. This typically requires
the operator to manipulate the drawworks brake, and rotate the
rotary table or top drive quill to find the precise combinations of
hook load, mud motor differential pressure, and drill string
torque, to properly position the toolface. This can be difficult,
time consuming, and complex. Each adjustment has different effects
on the toolface orientation, and each must be considered in
combination with other drilling requirements to drill the hole.
Thus, reorienting the toolface in a bore is very complex, labor
intensive, and often inaccurate. A more efficient, reliable method
for steering a BHA is needed.
SUMMARY OF THE INVENTION
[0007] In one exemplary aspect, the present disclosure is directed
to a method of drilling to a target location. The method includes
receiving an input comprising a planned drilling path to a target
location and determining a projected location of a bottom hole
assembly of a drilling system. The projected location of the bottom
hole assembly is compared to the planned drilling path, and a
modified drilling path to the target location is created. Drilling
rig control signals, typically at the surface of the well, are
generated that steer the bottom hole assembly of the drilling
system to the target location along the modified drilling path.
[0008] In one aspect, creating a modified drilling path to the
target location includes calculating curves from the projected
location of the bottom hole assembly that intersect the planned
drilling path. In another aspect, creating a modified drilling path
to the target location includes calculating a new planned drilling
path that does not intersect the planned drilling path and that is
directed from the projected location of the bottom hole assembly to
the target location, the method further including again determining
a projected location of a bottom hole assembly of the drilling
system. The projected location of the bottom hole assembly is
compared to the new modified drilling path and a second modified
drilling path to the target location is created. One or more
drilling rig control signals are automatically and electronically
generated at the well surface that steer the bottom hole assembly
of the drilling system along the second modified drilling path to
the target location.
[0009] In one aspect, determining a projected location of the
bottom hole assembly includes determining a projected location of a
bit of the bottom hole assembly, and determining a projected
location of the bit includes considering data from one or more
survey results.
[0010] In one aspect, creating a modified drilling path based upon
whether the amount of deviation from the planned path exceeds a
threshold includes creating a modified drilling path that
intersects the planned drilling path if the amount of deviation
from the planned path exceeds a first threshold amount of
deviation, and creating a modified drilling path that does not
intersect the planned drilling path if the amount of deviation from
the planned path exceeds a second threshold amount of deviation.
The method may include receiving a user-initiated input indicating
whether to create a new planned path to the target that does not
intersect the planned drilling path when the bottom hole assembly
exceeds the second threshold amount of deviation from the planned
path.
[0011] In one aspect the planned drilling path includes a tolerance
zone and creating the modified drilling path occurs when the
projected location of the bottom hole assembly intersects the
tolerance zone boundary and does not occur when the projected
location of the bottom hole assembly is within the tolerance zone.
In another aspect, the method includes calculating a toolface
inclination value and a measured depth required to steer the bottom
hole assembly to the target location.
[0012] In one aspect, creating a modified drilling path to the
target location includes calculating a first 3D curve, calculating
a hold section, and optionally calculating a second 3D curve. The
first and optional second 3D curves may be a portion of the
modified drilling path. The optional second 3D curve may merge the
modified path, with the original planned drilling path at a
location prior to the target location. In a preferred embodiment
herein, all curve calculations are achieved electronically, such as
with a computer or other suitable logic device as described
herein.
[0013] In one aspect, the method includes defining a tolerance
zone, an intervention zone, and a correction zone about the planned
drilling path. Comparing the projected location of the bottom hole
assembly to the planned drilling path includes determining which
zone contains the determined projection of the bottom hole
assembly. After creating a modified drilling path to the target
location, defining a new tolerance zone, a new intervention zone,
and a new correction zone about the modified drilling path.
[0014] In one aspect, determining a projected location of a bottom
hole assembly includes using a real-time survey projection as a
directional trend. The real-time projection is performed using a
method comprising at least one of: a minimum curvature arc,
direction trends, and a straight line. The real-time projection may
include a tool face orientation input.
[0015] In one aspect, the method includes creating a modified
drilling path to the target location includes calculating a first
3D curve, a hold section, and an optional second 3D curve that
directs the bottom hole assembly along the planned drilling path.
The first and optional second 3D curves may be calculated,
preferably electronically, by calculating any curves required to
intersect the planned drilling path at the target location,
calculating any curves required to intersect the planned drilling
path at a first location before the target location. Each curve may
have an acceptable rate of curvature for the BHA. The curves may be
further calculated, preferably electronically, by calculating any
curves required to intersect the planned drilling path at a second
location before the first location, the curves each having an
acceptable rate of curvature, the first and second location being
separated by a selected measurement distance, and selecting the
calculated curves to intersect the planned path at the first
location before reaching the target location.
[0016] In another exemplary aspect, the present disclosure is
directed to a system for drilling to a target location. The system
includes a receiving device adapted to receive an input comprising
a planned drilling path to a target location, a sensory device
adapted to determine a projected location of a bottom hole assembly
of a drilling system, and a logic device adapted to compare the
projected location of the bottom hole assembly to the planned
drilling path to determine a deviation amount from the planned
path. The second logic device is adapted to create a modified
drilling path to the target location as selected based on the
amount of deviation from the planned drilling path. A drilling rig
control signal generator is adapted to automatically and
electronically generate one or more drilling rig control signals at
the surface of the well that steer the bottom hole assembly of the
drilling system to the target location along the modified drilling
path.
[0017] In one aspect, the system includes a drawworks drive, a top
drive, and a mudpump. The control signal generator transmits the
one or more signals to control the drawworks, the top drive, and
the mudpump to change a direction of the bottom hole assembly as
drilling proceeds. In one aspect, the second logic device creates a
modified drilling path based upon whether the amount of deviation
from the planned path exceeds a threshold. It includes means for
creating a modified drilling path that intersects the planned
drilling path if the amount of deviation from the planned path
exceeds a first threshold amount of deviation from the planned path
and means for creating a modified drilling path that does not
intersect the planned drilling path if the amount of deviation from
the planned path exceeds a second threshold amount of deviation
from the planned path.
[0018] In another exemplary aspect, the present disclosure is
directed to a method of directionally steering a bottom hole
assembly during a drilling operation from a drilling rig to an
underground target location. The method includes the steps of:
generating a drilling plan having a drilling path and an acceptable
margin of error as a tolerance zone; receiving data indicative of
one or more directional trends and a projection to bit depth;
determining the actual location of the bottom hole assembly based
on the one or more directional trends and the projection to bit
depth; and determining whether the bit is within the tolerance
zone. The method also includes comparing the actual location of the
bottom hole assembly to the planned drilling path to identify an
amount of deviation from the planned path of the bottom hole
assembly from the actual drilling path and creating a modified
drilling path based on the amount of deviation from the planned
path. This includes creating a modified drilling path that
intersects the planned drilling path if the amount of deviation
from the planned path exceeds a first threshold amount of deviation
from the planned path, and creating a modified drilling path to the
target location that does not intersect the planned drilling path
if the amount of deviation from the planned path exceeds a second
threshold amount of deviation from the planned path. The method
further includes determining a desired tool face orientation to
steer the bottom hole assembly along the modified drilling path;
automatically and electronically generating one or more drilling
rig control signals at the well surface at a directional steering
controller; and outputting the one or more drilling rig control
signals to a drawworks and a top drive to steer the bottom hole
assembly along the modified drilling path.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The present disclosure is best understood from the following
detailed description when read with the accompanying figures. It is
emphasized that, in accordance with the standard practice in the
industry, various features are not drawn to scale. In fact, the
dimensions of the various features may be arbitrarily increased or
reduced for clarity of discussion.
[0020] FIG. 1 is a schematic diagram of a drilling rig apparatus
according to one or more aspects of the present disclosure.
[0021] FIGS. 2A and 2B are flow-chart diagrams of methods according
to one or more aspects of the present disclosure.
[0022] FIG. 3 is a schematic diagram of an apparatus according to
one or more aspects of the present disclosure.
[0023] FIGS. 4A-4C are schematic diagrams of apparatuses
accordingly to one or more aspects of the present disclosure.
[0024] FIG. 5A is a flow-chart diagram of a method according to one
or more aspects of the present disclosure.
[0025] FIG. 5B is an illustration of a tolerance cylinder about
drilling path.
[0026] FIG. 6A is a flow-chart diagram of a method according to one
or more aspects of the present disclosure.
[0027] FIG. 6B is a schematic diagram of an apparatus according to
one or more aspects of the present disclosure.
[0028] FIGS. 6C-6D are flow-chart diagrams of methods according to
one or more aspects of the present disclosure.
[0029] FIGS. 7A-7C are flow-chart diagrams of methods according to
one or more aspects of the present disclosure.
[0030] FIGS. 8A-8B are schematic diagrams of apparatuses according
to one or more aspects of the present disclosure.
[0031] FIG. 8C is a flow-chart diagram of a method according to one
or more aspects of the present disclosure.
[0032] FIGS. 9A-9B are flow-chart diagrams of methods according to
one or more aspects of the present disclosure.
[0033] FIGS. 10A-10B are schematic diagrams of a display apparatus
according to one or more aspects of the present disclosure.
[0034] FIG. 11 is a schematic diagram of an apparatus according to
one or more aspects of the present disclosure.
[0035] FIG. 12 is a schematic diagram of a modified drilling plan
according to one or more aspects of the present disclosure.
DETAILED DESCRIPTION
[0036] It is to be understood that the present disclosure provides
many different embodiments, or examples, for implementing different
features of various embodiments. Specific examples of components
and arrangements are described below to simplify the present
disclosure. These are, of course, merely examples and are not
intended to be limiting. In addition, the present disclosure may
repeat reference numerals and/or letters in the various examples.
This repetition is for the purpose of simplicity and clarity and
does not in itself dictate a relationship between the various
embodiments and/or configurations discussed. Moreover, the
formation of a first feature over or on a second feature in the
description that follows may include embodiments in which the first
and second features are formed in direct contact, and may also
include embodiments in which additional features may be formed
interposing the first and second features, such that the first and
second features may not be in direct contact.
[0037] The systems and methods disclosed herein provide increased
control of BHAs, resulting in increased BHA responsiveness and
faster BHA operations compared to conventional systems that require
significantly more manual input or pauses to provide for input. The
invention can advantageously achieve this through the use of data
feedback and location detection, processing received data, and
optimizing a drilling path based on the projected actual bit
location. Prior to drilling, a target location is typically
identified and an optimal wellbore profile or planned path is
established. Such proposed drilling paths are generally based upon
the most efficient or effective path to the target location or
locations. As drilling proceeds, the BHA might begin to deviate
from the optimal pre-planned drilling path for one or more of a
variety of factors. The systems and methods disclosed herein are
adapted to detect the deviation from the planned path and generate
corrections to return the BHA to the drilling path or if more
effective, generate an alternative drilling path to the target
location, each preferably in the most efficient manner possible
while preferably avoiding over-correction.
[0038] Referring to FIG. 1, illustrated is a schematic view of
apparatus 100 demonstrating one or more aspects of the present
disclosure. The apparatus 100 is or includes a land-based drilling
rig. However, one or more aspects of the present disclosure are
applicable or readily adaptable to any type of drilling rig, such
as jack-up rigs, semisubmersibles, drill ships, coil tubing rigs,
well service rigs adapted for drilling and/or re-entry operations,
and casing drilling rigs, among others within the scope of the
present disclosure.
[0039] Apparatus 100 includes a mast 105 supporting lifting gear
above a rig floor 110. The lifting gear includes a crown block 115
and a traveling block 120. The crown block 115 is coupled at or
near the top of the mast 105, and the traveling block 120 hangs
from the crown block 115 by a drilling line 125. One end of the
drilling line 125 extends from the lifting gear to drawworks 130,
which is configured to reel out and reel in the drilling line 125
to cause the traveling block 120 to be lowered and raised relative
to the rig floor 110. The other end of the drilling line 125, known
as a dead line anchor, is anchored to a fixed position, possibly
near the drawworks 130 or elsewhere on the rig.
[0040] A hook 135 is attached to the bottom of the traveling block
120. A top drive 140 is suspended from the hook 135. A quill 145
extending from the top drive 140 is attached to a saver sub 150,
which is attached to a drill string 155 suspended within a wellbore
160. Alternatively, the quill 145 may be attached to the drill
string 155 directly.
[0041] The term "quill" as used herein is not limited to a
component which directly extends from the top drive, or which is
otherwise conventionally referred to as a quill. For example,
within the scope of the present disclosure, the "quill" may
additionally or alternatively include a main shaft, a drive shall,
an output shaft, and/or another component which transfers torque,
position, and/or rotation from the top drive or other rotary
driving element to the drill string, at least indirectly.
Nonetheless, albeit merely for the sake of clarity and conciseness,
these components may be collectively referred to herein as the
"quill."
[0042] The drill string 155 includes interconnected sections of
drill pipe 165, a bottom hole assembly (BHA) 170, and a drill bit
175. The bottom hole assembly 170 may include stabilizers, drill
collars, and/or measurement-while-drilling (MWD) or wireline
conveyed instruments, among other components. The drill bit 175,
which may also be referred to herein as a tool, is connected to the
bottom of the BHA 170 or is otherwise attached to the drill string
155. One or more pumps 180 may deliver drilling fluid to the drill
string 155 through a hose or other conduit 185, which may be
connected to the top drive 140.
[0043] The downhole MWD or wireline conveyed instruments may be
configured for the evaluation of physical properties such as
pressure, temperature, torque, weight-on-bit (WOB), vibration,
inclination, azimuth, toolface orientation in three-dimensional
space, and/or other downhole parameters. These measurements may be
made downhole, stored in solid-state memory for some time, and
downloaded from the instrument(s) at the surface and/or transmitted
real-time to the surface. Data transmission methods may include,
for example, digitally encoding data and transmitting the encoded
data to the surface, possibly as pressure pulses in the drilling
fluid or mud system, acoustic transmission through the drill string
155, electronic transmission through a wireline or wired pipe,
and/or transmission as electromagnetic pulses. The MWD tools and/or
other portions of the BHA 170 may have the ability to store
measurements for later retrieval via wireline and/or when the BHA
170 is tripped out of the wellbore 160.
[0044] In an exemplary embodiment, the apparatus 100 may also
include a rotating blow-out preventer (BOP) 158, such as if the
well 160 is being drilled utilizing under-balanced or
managed-pressure drilling methods. In such embodiment, the annulus
mud and cuttings may be pressurized at the surface, with the actual
desired flow and pressure possibly being controlled by a choke
system, and the fluid and pressure being retained at the well head
and directed down the flow line to the choke by the rotating BOP
158. The apparatus 100 may also include a surface casing annular
pressure sensor 159 configured to detect the pressure in the
annulus defined between, for example, the wellbore 160 (or casing
therein) and the drill string 155.
[0045] In the exemplary embodiment depicted in FIG. 1, the top
drive 140 is utilized to impart rotary motion to the drill string
155. However, aspects of the present disclosure are also applicable
or readily adaptable to implementations utilizing other drive
systems, such as a power swivel, a rotary table, a coiled tubing
unit, a downhole motor, and/or a conventional rotary rig, among
others.
[0046] The apparatus 100 also includes a controller 190 configured
to control or assist in the control of one or more components of
the apparatus 100. For example, the controller 190 may be
configured to transmit operational control signals to the drawworks
130, the top drive 140, the BHA 170 and/or the pump 180. The
controller 190 may be a stand-alone component installed near the
mast 105 and/or other components of the apparatus 100. In an
exemplary embodiment, the controller 190 includes one or more
systems located in a control room proximate the apparatus 100, such
as the general purpose shelter often referred to as the "doghouse"
serving as a combination tool shed, office, communications center,
and general meeting place. The controller 190 may be configured to
transmit the operational control signals to the drawworks 130, the
top drive 140, the BHA 170, and/or the pump 180 via wired or
wireless transmission means which, for the sake of clarity, are not
depicted in FIG. 1.
[0047] The controller 190 is also configured to receive electronic
signals via wired or wireless transmission means (also not shown in
FIG. 1) from a variety of sensors included in the apparatus 100,
where each sensor is configured to detect an operational
characteristic or parameter. One such sensor is the surface casing
annular pressure sensor 159 described above. The apparatus 100 may
include a downhole annular pressure sensor 170a coupled to or
otherwise associated with the BHA 170. The downhole annular
pressure sensor 170a may be configured to detect a pressure value
or range in the annulus-shaped region defined between the external
surface of the BHA 170 and the internal diameter of the wellbore
160, which may also be referred to as the casing pressure, downhole
casing pressure, MWD casing pressure, or downhole annular pressure.
These measurements may include both static annular pressure (pumps
off) and active annular pressure (pumps on).
[0048] It is noted that the meaning of the word "detecting," in the
context of the present disclosure, may include detecting, sensing,
measuring, calculating, and/or otherwise obtaining data. Similarly,
the meaning of the word "detect" in the context of the present
disclosure may include detect, sense, measure, calculate, and/or
otherwise obtain data.
[0049] The apparatus 100 may additionally or alternatively include
a shock/vibration sensor 170b that is configured for detecting
shock and/or vibration in the BHA 170. The apparatus 100 may
additionally or alternatively include a mud motor delta pressure
(.DELTA.P) sensor 172a that is configured to detect a pressure
differential value or range across one or more motors 172 of the
BHA 170. The one or more motors 172 may each be or include a
positive displacement drilling motor that uses hydraulic power of
the drilling fluid to drive the bit 175, also known as a mud motor.
One or more torque sensors 172b may also be included in the BHA 170
for sending data to the controller 190 that is indicative of the
torque applied to the bit 175 by the one or more motors 172.
[0050] The apparatus 100 may additionally or alternatively include
a toolface sensor 170c configured to detect the current toolface
orientation. The toolface sensor 170c may be or include a
conventional or future-developed magnetic toolface sensor which
detects toolface orientation relative to magnetic north or true
north. Alternatively, or additionally, the toolface sensor 170c may
be or include a conventional or future-developed gravity toolface
sensor which detects toolface orientation relative to the Earth's
gravitational field. The toolface sensor 170cmay also, or
alternatively, be or include a conventional or future-developed
gyro sensor. The apparatus 100 may additionally or alternatively
include a WOB sensor 170d integral to the BHA 170 and configured to
detect WOB at or near the BHA 170.
[0051] The apparatus 100 may additionally or alternatively include
a torque sensor 140a coupled to or otherwise associated with the
top drive 140. The torque sensor 140a may alternatively be located
in or associated with the BHA 170. The torque sensor 140a may be
configured to detect a value or range of the torsion of the quill
145 and/or the drill string 155 (e.g., in response to operational
forces acting on the drill string). The top drive 140 may
additionally or alternatively include or otherwise be associated
with a speed sensor 140b configured to detect a value or range of
the rotational speed of the quill 145.
[0052] The top drive 140, draw works 1 30, crown or traveling
block, drilling line or dead line anchor may additionally or
alternatively include or otherwise be associated with a WOB sensor
140c (WOB calculated from a hook load sensor that can be based on
active and static hook load) (e.g., one or more sensors installed
somewhere in the load path mechanisms to detect and calculate WOB,
which can vary from rig-to-rig) different from the WOB sensor 170d.
The WOB sensor 140c may be configured to detect a WOB value or
range, where such detection may be performed at the top drive 140,
draw works 130, or other component of the apparatus 100.
[0053] The detection performed by the sensors described herein may
be performed once, continuously, periodically, and/or at random
intervals. The detection may be manually triggered by an operator
or other person accessing a human-machine interface (HMI), or
automatically triggered by, for example, a triggering
characteristic or parameter satisfying a predetermined condition
(e.g., expiration of a time period, drilling progress reaching a
predetermined depth, drill bit usage reaching a predetermined
amount, etc.). Such sensors and/or other detection means may
include one or more interlaces which may be local at the well/rig
site or located at another, remote location with a network link to
the system.
[0054] Referring to FIG. 2A, illustrated is a flow-chart diagram of
a method 200a of manipulating a tool face orientation to a desired
orientation according to one or more aspects of the present
disclosure. The method 200a may be performed in association with
one or more components of the apparatus 100 shown in FIG. 1 during
operation of the apparatus 100. For example, the method 200a may be
performed for tool face orientation during drilling operations
performed via the apparatus 100.
[0055] The method 200a includes a step 210 during which the current
toolface orientation TF.sub.M is measured. The TF.sub.M may be
measured using a conventional or future-developed magnetic toolface
sensor which detects toolface orientation relative to magnetic
north or true north. Alternatively, or additionally, the TF.sub.M
may be measured using a conventional or future-developed gravity
toolface sensor which detects toolface orientation relative to the
Earth's gravitational field. In an exemplary embodiment, the
TF.sub.M may be measured using a magnetic tool face sensor when the
end of the wellbore is less than about 7.degree. from vertical, and
subsequently measured using a gravity toolface sensor when the end
of the wellbore is greater than about 7.degree. from vertical.
However, gyros and/or other means for determining the TF.sub.M are
also within the scope of the present disclosure.
[0056] In a subsequent step 220, the TF.sub.M is compared to a
desired toolface orientation TF.sub.D. If the TF.sub.M is
sufficiently equal to the TF.sub.D, as determined during decisional
step 230, the method 200a is iterated and the step 210 is repeated.
"Sufficiently equal" may mean substantially equal, such as varying
by no more than a few percentage points, or may alternatively mean
varying by no more than a predetermined angle, such as about
5.degree.. Moreover, the iteration of the method 200a may be
substantially immediate, or there may be a delay period before the
method 200a is iterated and the step 210 is repeated.
[0057] If the TF.sub.M is not sufficiently equal to the TF.sub.D,
as determined during decisional step 230, the method 200a continues
to a step 240 during which the quill is rotated by the drive system
by, for example, an amount about equal to the difference between
the TF.sub.M and the TF.sub.D. However, other amounts of rotational
adjustment performed during the step 240 are also within the scope
of the present disclosure. After step 240 is performed, the method
200a is iterated and the step 210 is repeated. Such iteration may
be substantially immediate, or there may be a delay period before
the method 200a is iterated and the step 210 is repeated.
[0058] Referring to FIG. 2B, illustrated is a flow-chart diagram of
another embodiment of the method 200a shown in FIG. 2A, herein
designated by reference numeral 200b. The method 200b includes an
information gathering step when the toolface orientation is in the
desired orientation and may be performed in association with one or
more components of the apparatus 100 shown in FIG. 1 during
operation of the apparatus 100. For example, the method 200b may be
performed for toolface orientation during drilling operations
performed via the apparatus 100.
[0059] The method 200b includes steps 210, 220, 230 and 240
described above with respect to method 200a and shown in FIG. 2A.
However, the method 200b also includes a step 233 during which
current operating parameters are measured if the TF.sub.M is
sufficiently equal to the TF.sub.D, as determined during decisional
step 230. Alternatively, or additionally, the current operating
parameters may be measured at periodic or scheduled time intervals,
or upon the occurrence of other events. The method 200b also
includes a step 236 during which the operating parameters measured
in the step 233 are recorded. The operating parameters recorded
during the step 236 may be employed in future calculations of the
amount of quill rotation performed during the step 240, such as may
be determined by one or more intelligent adaptive controllers,
programmable logic controllers, artificial neural networks, and/or
other adaptive and/or "learning" controllers or processing
apparatus.
[0060] Each of the steps of the methods 200a and 200b may be
performed automatically. For example, the controller 190 of FIG. 1
may be configured to automatically perform the toolface comparison
of step 230, whether periodically, at random intervals, or
otherwise. The controller 190 may also be configured to
automatically generate and transmit control signals directing the
quill rotation of step 240, such as in response to the toolface
comparison performed during steps 220 and 230.
[0061] Referring to FIG. 3, illustrated is a block diagram of an
apparatus 300 according to one or more aspects of the present
disclosure. The apparatus 300 includes a user interface 305, a BHA
310, a drive system 315, a drawworks 320, and a controller 325. The
apparatus 300 may be implemented within the environment and/or
apparatus shown in FIG. 1. For example, the BHA 310 may be
substantially similar to the BHA 170 shown in FIG. 1, the drive
system 315 may be substantially similar to the top drive 340 shown
in FIG. 1, the drawworks 320 may be substantially similar to the
drawworks 130 shown in FIG. 1, and/or the controller 325 may be
substantially similar to the controller 190 shown in FIG. 1. The
apparatus 300 may also be utilized in performing the method 200a
shown in FIG. 2A and/or the method 200b shown in FIG. 2B, among
other methods described herein or otherwise within the scope of the
present disclosure.
[0062] The user-interface 305 and the controller 325 may be
discrete components that are interconnected via wired or wireless
means. Alternatively, the user-interface 305 and the controller 325
may be integral components of a single system or controller 327, as
indicated by the dashed lines in FIG. 3.
[0063] The user-interface 305 includes means 330 for user-input of
one or more toolface set points, and may also include means for
user-input of other set points, limits, and other input data. The
data input means 330 may include a keypad, voice-recognition
apparatus, dial, button, switch, slide selector, toggle, joystick,
mouse, data base and/or other conventional or future-developed data
input device. Such data input means may support data input from
local and/or remote locations. Alternately, or additionally, the
data input means 330 may include means for user-selection of
predetermined toolface set point values or ranges, such as via one
or more drop-down menus. The toolface set point data may also or
alternatively be selected by the controller 325 via the execution
of one or more database look-up procedures. In general, the data
input means 330 and/or other components within the scope of the
present disclosure support operation and/or monitoring from
stations on the rig site as well as one or more remote locations
with a communications link to the system, network, local area
network (LAN), wide area network (WAN), Internet, satellite-link,
and/or radio, among other means.
[0064] The user-interface 305 may also include a display 335 for
visually presenting information to the user in textual, graphic, or
video form. The display 335 may also be utilized by the user to
input the toolface set point data in conjunction with the data
input means 330. For example, the toolface set point data input
means 330 may be integral to or otherwise communicably coupled with
the display 335.
[0065] The BHA 310 may include an MWD casing pressure sensor 340
that is configured to detect an annular pressure value or range at
or near the MWD portion of the BHA 310, and that may be
substantially similar to the pressure sensor 170a shown in FIG. 1.
The casing pressure data detected via the MWD casing pressure
sensor 340 may be sent via electronic signal to the controller 325
via wired or wireless transmission.
[0066] The BHA 310 may also include an MWD shock/vibration sensor
345 that is configured to detect shock and/or vibration in the MWD
portion of the BHA 310, and that may be substantially similar to
the shock/vibration sensor 170b shown in FIG. 1. The
shock/vibration data detected via the MWD shock/vibration sensor
345 may be sent via electronic signal to the controller 325 via
wired or wireless transmission.
[0067] The BHA 310 may also include a mud motor .DELTA.P sensor 350
that is configured to detect a pressure differential value or range
across the mud motor of the BHA 310, and that may be substantially
similar to the mud motor .DELTA.P sensor 172a shown in FIG. 1. The
pressure differential data detected via the mud motor .DELTA.P
sensor 350 may be sent via electronic signal to the controller 325
via wired or wireless transmission. The mud motor .DELTA.P may be
alternatively or additionally calculated, detected, or otherwise
determined at the surface, such as by calculating the difference
between the surface standpipe pressure just off-bottom and pressure
once the bit touches bottom and starts drilling and experiencing
torque.
[0068] The BHA 310 may also include a magnetic toolface sensor 355
and a gravity toolface sensor 360 that are cooperatively configured
to detect the current toolface, and that collectively may be
substantially similar to the toolface sensor 170c shown in FIG. 1.
The magnetic toolface sensor 355 may be or include a conventional
or future-developed magnetic toolface sensor which detects toolface
orientation relative to magnetic north or true north. The gravity
toolface sensor 360 may be or include a conventional or
future-developed gravity toolface sensor which detects toolface
orientation relative to the Earth's gravitational field. In an
exemplary embodiment, the magnetic toolface sensor 355 may detect
the current toolface when the end of the well bore is less than
about 7.degree. from vertical, and the gravity toolface sensor 360
may detect the current toolface when the end of the wellbore is
greater than about 7.degree. from vertical. However, other toolface
sensors may also be utilized within the scope of the present
disclosure, including non-magnetic toolface sensors and
non-gravitational inclination sensors. In any case, the toolface
orientation detected via the one or more toolface sensors (e.g.,
sensors 355 and/or 360) may be sent via electronic signal to the
controller 325 via wired or wireless transmission.
[0069] The BHA 310 may also include an MWD torque sensor 365 that
is configured to detect a value or range of values for torque
applied to the bit by the motor(s) of the BHA 310, and that may be
substantially similar to the torque sensor 172b shown in FIG. 1.
The torque data detected via the MWD torque sensor 365 may be sent
via electronic signal to the controller 325 via wired or wireless
transmission.
[0070] The BHA 310 may also include an MWD WOB sensor 370 that is
configured to detect a value or range of values for WOB at or near
the BHA 310, and that may be substantially similar to the WOB
sensor 170d shown in FIG. 1. The WOB data detected via the MWD WOB
sensor 370 may be sent via electronic signal to the controller 325
via wired or wireless transmission.
[0071] The drawworks 320 includes a controller 390 and/or other
means for controlling feed-out and/or feed-in of a drilling line
(such as the drilling line 125 shown in FIG. 1). Such control may
include rotational control of the drawworks (in v. out) to control
the height or position of the hook, and may also include control of
the rate the hook ascends or descends. However, exemplary
embodiments within the scope of the present disclosure include
those in which the drawworks drill string feed off system may
alternatively be a hydraulic ram or rack and pinion type hoisting
system rig, where the movement of the drill string up and down is
via something other than a drawworks. The drill string may also
take the form of coiled tubing, in which case the movement of the
drill string in and out of the hole is controlled by an injector
head which grips and pushes/pulls the tubing in/out of the hole.
Nonetheless, such embodiments may still include a version of the
controller 390, and the controller 390 may still be configured to
control feed-out and/or feed-in-of the drill string.
[0072] The drive system 315 includes a surface torque sensor 375
that is configured to detect a value or range of the reactive
torsion of the quill or drill string, much the same as the torque
sensor 140a shown in FIG. 1. The drive system 315 also includes a
quill position sensor 380 that is configured to detect a value or
range of the rotational position of the quill, such as relative to
true north or another stationary reference. The surface torsion and
quill position data detected via sensors 375 and 380, respectively,
may be sent via electronic signal to the controller 325 via wired
or wireless transmission. The drive system 315 also includes a
controller 385 and/or other means for controlling the rotational
position, speed and direction of the quill or other drill string
component coupled to the drive system 315 (such as the quill 145
shown in FIG. 1).
[0073] In an exemplary embodiment, the drive system 315, controller
385, and/or other component of the apparatus 300 may include means
for accounting for friction between the drill string and the
wellbore. For example, such friction accounting means may be
configured to detect the occurrence and/or severity of the
friction, which may then be subtracted from the actual "reactive"
torque, perhaps by the controller 385 and/or another control
component of the apparatus 300.
[0074] The controller 325 is configured to receive one or more of
the above-described parameters from the user interface 305, the BHA
310, and/or the drive system 315, and utilize such parameters to
continuously, periodically, or otherwise determine the current
toolface orientation. The controller 325 may be further configured
to generate a control signal, such as via intelligent adaptive
control, and provide the control signal to the drive system 315
and/or the drawworks 320 to adjust and/or maintain the toolface
orientation. For example, the controller 325 may execute the method
202 shown in FIG. 2B to provide one or more signals to the drive
system 315 and/or the drawworks 320 to increase or decrease WOB
and/or quill position, such as may be required to accurately
"steer" the drilling operation.
[0075] Moreover, as in the exemplary embodiment depicted in FIG. 3,
the controller 385 of the drive system 315 and/or the controller
390 of the drawworks 320 may be configured to generate and transmit
a signal to the controller 325. Consequently, the controller 385 of
the drive system 315 may be configured to influence the control of
the BHA 310 and/or the drawworks 320 to assist in obtaining and/or
maintaining a desired toolface orientation. Similarly, the
controller 390 of the drawworks 320 may be configured to influence
the control of the BHA 310 and/or the drive system 315 to assist in
obtaining and/or maintaining a desired toolface orientation.
Alternatively, or additionally, the controller 385 of the drive
system 315 and the controller 390 of the drawworks 320 may be
configured to communicate directly, such as indicated by the
dual-directional arrow 392 depicted in FIG. 3. Consequently, the
controller 385 of the drive system 315 and the controller 390 of
the drawworks 320 may be configured to cooperate in obtaining
and/or maintaining a desired toolface orientation. Such cooperation
may be independent of control provided to or from the controller
325 and/or the BHA 310.
[0076] Referring to FIG. 4A, illustrated is a schematic view of at
least a portion of an apparatus 400a according to one or more
aspects of the present disclosure. The apparatus 400a is an
exemplary implementation of the apparatus 100 shown in FIG. 1
and/or the apparatus 300 shown in FIG. 3, and is an exemplary
environment in which the method 200a shown in FIG. 2A and/or the
method 200b shown in FIG. 2B may be performed. The apparatus 400a
includes a plurality of user inputs 410 and at least one main
steering module 420, which may include one or more processors. The
user inputs 410 include a quill torque positive limit 410a, a quill
torque negative limit 410b, a quill speed positive limit 410c, a
quill speed negative limit 410d, a quill oscillation positive limit
410e, a quill oscillation negative limit 410f, a quill oscillation
neutral point input 410g, and a toolface orientation input 410h.
Some embodiments include a survey data input from prior surveys
410p, a planned drilling path 410q, or preferably both. These
inputs may be used to derive the toolface orientation input 410h
intended to maintain the BHA on the planned drilling path. However,
in other embodiments, the toolface orientation is directly entered.
Other embodiments within the scope of the present disclosure may
utilize additional or alternative user inputs 410. The user inputs
410 may be substantially similar to the user input 330 or other
components of the user interface 305 shown in FIG. 3. The at least
one steering module 420 may form at least a portion of, or be
formed by at least a portion of, the controller 325 shown in FIG. 3
and/or the controller 385 of the drive system 315 shown in FIG. 3.
In the exemplary embodiment depicted in FIG. 4A, the at least one
steering module 420 includes a toolface controller 420a and a
drawworks controller 420b. In some embodiments, it also includes a
mud pump controller.
[0077] The apparatus 400a also includes or is otherwise associated
with a plurality of sensors 430. The plurality of sensors 430
includes a bit torque sensor 430a, a quill torque sensor 430b, a
quill speed sensor 430c, a quill position sensor 430d, a mud motor
.DELTA.P sensor 430e, and a toolface orientation sensor 430f. Other
embodiments within the scope of the present disclosure, however,
may utilize additional or alternative sensors 430. In an exemplary
embodiment, each of the plurality of sensors 430 may be located at
the surface of the wellbore, and not located downhole proximate the
bit, the bottom hole assembly, and/or any
measurement-while-drilling tools. In other embodiments, however,
one or more of the sensors 430 may not be surface sensors. For
example, in an exemplary embodiment, the quill torque sensor 430b,
the quill speed sensor 430c, and the quill position sensor 430d may
be surface sensors, whereas the bit torque sensor 430a, the mud
motor .DELTA.P sensor 430e, and the toolface orientation sensor
430f may be downhole sensors, (e.g., MWD sensors). Moreover,
individual ones of the sensors 430 may be substantially similar to
corresponding sensors shown in FIG. 1 or FIG. 3.
[0078] The apparatus 400a also includes or is associated with a
quill drive 440. The quill drive 440 may form at least a portion of
a top drive or another rotary drive system, such as the top drive
140 shown in FIG. 1 and/or the drive system 315 shown in FIG. 3.
The quill drive 440 is configured to receive a quill drive control
signal from the at least one steering module 420, if not also from
other components of the apparatus 400a. The quill drive control
signal directs the position (e.g., azimuth), spin direction, spin
rate, and/or oscillation of the quill. The toolface controller 420a
is configured to generate the quill drive control signal, utilizing
data received from the user inputs 410 and the sensors 430.
[0079] The toolface controller 420a may compare the actual torque
of the quill to the quill torque positive limit received from the
corresponding user input 410a. The actual torque of the quill may
be determined utilizing data received from the quill torque sensor
430b. For example, if the actual torque of the quill exceeds the
quill torque positive limit, then the quill drive control signal
may direct the quill drive 440 to reduce the torque being applied
to the quill. In an exemplary embodiment, the toolface controller
420a may be configured to optimize drilling operation parameters
related to the actual torque of the quill, such as by maximizing
the actual torque of the quill without exceeding the quill torque
positive limit.
[0080] The toolface controller 420a may alternatively or
additionally compare the actual torque of the quill to the quill
torque negative limit received from the corresponding user input
410b. For example, if the actual torque of the quill is less than
the quill torque negative limit, then the quill drive control
signal may direct the quill drive 440 to increase the torque being
applied to the quill. In an exemplary embodiment, the toolface
controller 420a may be configured to optimize drilling operation
parameters related to the actual torque of the quill, such as by
minimizing the actual torque of the quill while still exceeding the
quill torque negative limit.
[0081] The toolface controller 420a may alternatively or
additionally compare the actual speed of the quill to the quill
speed positive limit received from the corresponding user input
410c. The actual speed of the quill may be determined utilizing
data received from the quill speed sensor 430c. For example, if the
actual speed of the quill exceeds the quill speed positive limit,
then the quill drive control signal may direct the quill drive 440
to reduce the speed at which the quill is being driven. In an
exemplary embodiment, the toolface controller 420a may be
configured to optimize drilling operation parameters related to the
actual speed of the quill, such as by maximizing the actual speed
of the quill without exceeding the quill speed positive limit.
[0082] The toolface controller 420a may alternatively or
additionally compare the actual speed of the quill to the quill
speed negative limit received from the corresponding user input
410d. For example, if the actual speed of the quill is less than
the quill speed negative limit, then the quill drive control signal
may direct the quill drive 440 to increase the speed at which the
quill is being driven. In an exemplary embodiment, the toolface
controller 420a may be configured to optimize drilling operation
parameters related to the actual speed of the quill, such as by
minimizing the actual speed of the quill while still exceeding the
quill speed negative limit.
[0083] The toolface controller 420a may alternatively or
additionally compare the actual orientation (azimuth) of the quill
to the quill oscillation positive limit received from the
corresponding user input 410e. The actual orientation of the quill
may be determined utilizing data received from the quill position
sensor 430d. For example, if the actual orientation of the quill
exceeds the quill oscillation positive limit, then the quill drive
control signal may direct the quill drive 440 to rotate the quill
to within the quill oscillation positive limit, or to modify quill
oscillation parameters such that the actual quill oscillation in
the positive direction (e.g., clockwise) does not exceed the quill
oscillation positive limit. In an exemplary embodiment, the
toolface controller 420a may be configured to optimize drilling
operation parameters related to the actual oscillation of the
quill, such as by maximizing the amount of actual oscillation of
the quill in the positive direction without exceeding the quill
oscillation positive limit.
[0084] The toolface controller 420a may alternatively or
additionally compare the actual orientation of the quill to the
quill oscillation negative limit received from the corresponding
user input 410f. For example, if the actual orientation of the
quill is less than the quill oscillation negative limit, then the
quill drive control signal may direct the quill drive 440 to rotate
the quill to within the quill oscillation negative limit, or to
modify quill oscillation parameters such that the actual quill
oscillation in the negative direction (e.g., counter-clockwise)
does not exceed the quill oscillation negative limit. In an
exemplary embodiment, the toolface controller 420a may be
configured to optimize drilling operation parameters related to the
actual oscillation of the quill, such as by maximizing the actual
amount of oscillation of the quill in the negative direction
without exceeding the quill oscillation negative limit.
[0085] The toolface controller 420a may alternatively or
additionally compare the actual neutral point of quill oscillation
to the desired quill oscillation neutral point input received from
the corresponding user input 410g. The actual neutral point of the
quill oscillation may be determined utilizing data received from
the quill position sensor 430d. For example, if the actual quill
oscillation neutral point varies from the desired quill oscillation
neutral point by a predetermined amount, or falls outside a desired
range of the oscillation neutral point, then the quill drive
control signal may direct the quill drive 440 to modify quill
oscillation parameters to make the appropriate correction.
[0086] The toolface controller 420a may alternatively or
additionally compare the actual orientation of the toolface to the
toolface orientation input received from the corresponding user
input 410h. The toolface orientation input received from the user
input 410h may be a single value indicative of the desired toolface
orientation. This may be directly input or derived from the survey
data files 410p and the planned drilling path 410q using, for
example, the process described in FIGS. 4C, 5A, and 5B. If the
actual toolface orientation differs from the toolface orientation
input value by a predetermined amount, then the quill drive control
signal may direct the quill drive 440 to rotate the quill an amount
corresponding to the necessary correction of the toolface
orientation. However, the toolface orientation input received from
the user input 410h may alternatively be a range within which it is
desired that the toolface orientation remain. For example, if the
actual toolface orientation is outside the toolface orientation
input range, then the quill drive control signal may direct the
quill drive 440 to rotate the quill an amount necessary to restore
the actual toolface orientation to within the toolface orientation
input range. In an exemplary embodiment, the actual toolface
orientation is compared to a toolface orientation input that is
directly input or derived from the survey data files 410p and the
planned drilling path 410q using an automated process. In some
embodiments, this is based on a predetermined and/or constantly
updating well plan (e.g., a "well-prog"), possibly taking into
account drilling progress path error.
[0087] In each of the above-mentioned comparisons and/or
calculations performed by the toolface controller, the actual mud
motor .DELTA.P, and/or the actual bit torque may also be utilized
in the generation of the quill drive signal. The actual mud motor
.DELTA.P may be determined utilizing data received from the mud
motor .DELTA.P sensor 430e, and/or by measurement of pump pressure
before the bit is on bottom and tare of this value, and the actual
bit torque may be determined utilizing data received from the bit
torque sensor 430a. Alternatively, the actual bit torque may be
calculated utilizing data received from the mud motor .DELTA.P
sensor 430e, because actual bit torque, and actual mud motor
.DELTA.P are proportional.
[0088] One example in which the actual mud motor .DELTA.P and/or
the actual bit torque may be utilized is when the actual toolface
orientation cannot be relied upon to provide accurate or fast
enough data. For example, such may be the case during "blind"
drilling, or other instances in which the driller is no longer
receiving data from the toolface orientation sensor 430f. In such
occasions, the actual bit torque and/or the actual mud motor
.DELTA.P can be utilized to determine the actual toolface
orientation. For example, if ail other drilling parameters remain
the same, a change in the actual bit torque and or the actual mud
motor .DELTA.P can indicate a proportional rotation of the toolface
orientation in the same or opposite direction of drilling. For
example, an increasing torque or .DELTA.P may indicate that the
toolface is changing in the opposite direction of drilling, whereas
a decreasing torque or .DELTA.P may indicate that the toolface is
moving in the same direction as drilling. Thus, in this manner, the
data received from the bit torque sensor 430a and/or the mud motor
.DELTA.P sensor 430e can be utilized by the toolface controller 420
in the generation of the quill drive signal, such that the quill
can be driven in a manner which corrects for or otherwise takes
into account any change of toolface, which is indicated by a change
in the actual bit torque and/or actual mud motor .DELTA.P.
[0089] Moreover, under some operating conditions, the data received
by the toolface controller 420 from the toolface orientation sensor
430f can lag the actual toolface orientation. For example, the
toolface orientation sensor 430f may only determine the actual
toolface periodically, or a considerable time period may be
required for the transmission of the data from the toolface to the
surface. In fact, it is not uncommon for such delay to be 30
seconds or more in the systems of the prior art. Consequently, in
some implementations within the scope of the present disclosure, it
may be more accurate or otherwise advantageous for the toolface
controller 420a to utilize the actual torque and pressure data
received from the bit torque sensor 430a and the mud motor .DELTA.P
sensor 430e in addition to, if not in the alternative to, utilizing
the actual toolface data received from the toolface orientation
sensor 430f. However, in some embodiments of the present
disclosure, real-time survey projections as disclosed in FIGS. 9A
and 9B may be used to provide data regarding the BHA direction and
toolface orientation.
[0090] As shown in FIG. 4A, the user inputs 410 of the apparatus
400a may also include a WOB tare 410i, a mud motor .DELTA.P tare
410j, an HOP input 410k, a WOB input 410l, a mud motor .DELTA.P
input 410m, and a hook load limit 410n, and the at least one
steering module 420 may also include a drawworks controller 420b.
The plurality of sensors 430 of the apparatus 400a may also include
a hook load sensor 430g. a mud pump pressure sensor 430h, a bit
depth sensor 430i, a casing pressure sensor 430j and an ROP sensor
430k. Each of the plurality of sensors 430 may be located at the
surface of the wellbore, downhole (e.g., MWD), or elsewhere.
[0091] As described above, the toolface controller 420a is
configured to generate a quill drive control signal utilizing data
received from ones of the user inputs 410 and the sensors 430, and
subsequently provide the quill drive control signal to the quill
drive 440, thereby controlling the toolface orientation by driving
the quill orientation and speed. Thus, the quill drive control
signal is configured to control (at least partially) the quill
orientation (e.g., azimuth) as well as the speed and direction of
rotation of the quill (if any).
[0092] The drawworks controller 420b is configured to generate a
drawworks drum (or brake) drive control signal also utilizing data
received from ones of the user inputs 410 and the sensors 430.
Thereafter, the drawworks controller 420b provides the drawworks
drive control signal to the drawworks drive 450, thereby
controlling the feed direction and rate of the drawworks. The
drawworks drive 450 may form at least a portion of, or may be
formed by at least a portion of, the drawworks 130 shown in FIG. 1
and/or the drawworks 320 shown in FIG. 3. The scope of the present
disclosure is also applicable or readily adaptable to other means
for adjusting the vertical positioning of the drill string. For
example, the drawworks controller 420b may be a hoist controller,
and the drawworks drive 450 may be or include means for hoisting
the drill string other than or in addition to a drawworks apparatus
(e.g., a rack and pinion apparatus).
[0093] The apparatus 400a also includes a comparator 430c which
compares current hook load data with the WOB tare to generate the
current WOB. The current hook load data is received from the hook
load sensor 430g, and the WOB tare is received from the
corresponding user input 410i.
[0094] The drawworks controller 420b compares the current WOB with
WOB input data. The current WOB is received from the comparator
420c, and the WOB input data is received from the corresponding
user input 410l. The WOB input data received from the user input
410l may be a single value indicative of the desired WOB. For
example, if the actual WOB differs from the WOB input by a
predetermined amount, then the drawworks drive control signal may
direct the drawworks drive 450 to feed cable in or out an amount
corresponding to the necessary correction of the WOB. However, the
WOB input data received from the user input 410l may alternatively
be a range within which it is desired that the WOB be maintained.
For example, if the actual WOB is outside the WOB input range, then
the drawworks drive control signal may direct the drawworks drive
450 to feed cable in or out an amount necessary to restore the
actual WOB to within the WOB input range. In an exemplary
embodiment, the drawworks controller 420b may be configured to
optimize drilling operation parameters related to the WOB, such as
by maximizing the actual WOB without exceeding the WOB input value
or range.
[0095] The apparatus 400a also includes a comparator 420d which
compares mud pump pressure data with the mud motor .DELTA.P tare to
generate an "uncorrected" mud motor .DELTA.P. The mud pump pressure
data is received from the mud pump pressure sensor 430h, and the
mud motor .DELTA.P tare is received from the corresponding user
input 410j.
[0096] The apparatus 400a also includes a comparator 420e which
utilizes the uncorrected mud motor .DELTA.P along with bit depth
data and casing pressure data to generate a "corrected" or current
mud motor .DELTA.P. The bit depth data is received from the bit
depth sensor 430i, and the casing pressure data is received from
the casing pressure sensor 430j. The casing pressure sensor 430j
may be a surface casing pressure sensor, such the sensor 159 shown
in FIG. 1, and/or a downhole casing pressure sensor, such as the
censor 170a shown in FIG. 1, and in either case may detect the
pressure in the annulus defined between the casing or wellbore
diameter and a component of the drill string.
[0097] The drawworks controller 420b compares the current mud motor
.DELTA.P with mud motor .DELTA.P input data. The current mud motor
.DELTA.P is received from the comparator 420e, and the mud motor
.DELTA.P input data is received from the corresponding user input
410m. The mud motor .DELTA.P input data received from the user
input 410m may be a single value indicative of the desired mud
motor .DELTA.P. For example, if the current mud motor .DELTA.P
differs from the mud motor .DELTA.P input by a predetermined
amount, then the drawworks drive control signal may direct the
drawworks drive 450 to feed cable in or out an amount corresponding
to the necessary correction of the mud motor .DELTA.P. However, the
mud motor .DELTA.P input data received from the user input 410m may
alternatively be a range within which it is desired that the mud
motor .DELTA.P be maintained. For example, if the current mud motor
.DELTA.P is outside this range, then the drawworks drive control
signal may direct the drawworks drive 450 to feed cable in or out
an amount necessary to restore the current mud motor .DELTA.P to
within the input range. In an exemplary embodiment, the drawworks
controller 420b may be configured to optimize drilling operation
parameters related to the mud motor .DELTA.P, such, as by
maximizing the mud motor .DELTA.P without exceeding the input value
or range.
[0098] The drawworks controller 420b may also or alternatively
compare actual ROP data with ROP input data. The actual ROP data is
received from the ROP sensor 430k, and the ROP input data is
received from the corresponding user input 410k. The ROP input data
received from the user input 410k may be a single value indicative
of the desired ROP. For example, if the actual ROP differs from the
ROP input by a predetermined amount, then the drawworks drive
control signal may direct the drawworks drive 450 to feed cable in
or out an amount corresponding to the necessary correction of the
ROP. However, the ROP input data received from the user input 410k
may alternatively be a range within which it is desired that the
ROP be maintained. For example, if the actual ROP is outside the
ROP input range, then the drawworks drive control signal may direct
the drawworks drive 450 to feed cable in or out an amount necessary
to restore the actual ROP to within the ROP input range. In an
exemplary embodiment, the drawworks controller 420b may be
configured to optimize drilling operation parameters related to the
ROP, such as by maximizing the actual ROP without exceeding the ROP
input value or range.
[0099] The drawworks controller 420b may also utilize data received
from the toolface controller 420a when generating the drawworks
drive control signal. Changes in the actual WOB can cause changes
in the actual bit torque, the actual mud motor .DELTA.P, and the
actual toolface orientation. For example, as weight is increasingly
applied to the bit, the actual toolface orientation can rotate
opposite the direction of bit rotation (due to reactive torque),
and the actual bit torque and mud motor pressure can proportionally
increase. Consequently, the toolface controller 420a may provide
data to the drawworks controller 420b indicating whether the
drawworks cable should be fed in or out, and perhaps a
corresponding feed rate, as necessary to bring the actual toolface
orientation into compliance with the toolface orientation input
value or range provided by the corresponding user input 410h. In an
exemplary embodiment, the drawworks controller 420b may also
provide data to the toolface controller 420a to rotate the quill
clockwise or counterclockwise by an amount and/or rate sufficient
to compensate for increased or decreased WOB, bit depth, or casing
pressure.
[0100] As shown in FIG. 4A, the user inputs 410 may also include a
pull limit input 410n. When generating the drawworks drive control
signal, the drawworks controller 420b may be configured to ensure
that the drawworks does not pull past the pull limit received from
the user input 410n. The pull limit is also known as a hook load
limit, and may be dependent upon the particular configuration of
the drilling rig, among other parameters.
[0101] In an exemplary embodiment, the drawworks controller 420b
may also provide data to the toolface controller 420a to cause the
toolface controller 420a to rotate the quill, such as by an amount,
direction, and/or rate sufficient to compensate for the pull limit
being reached or exceeded. The toolface controller 420a may also
provide data to the drawworks controller 420b to cause the
drawworks controller 420b to increase or decrease the WOB, or to
adjust the drill string feed, such as by an amount, direction,
and/or rate sufficient to adequately adjust the tool face
orientation.
[0102] Referring to FIG. 4B, illustrated is a high level schematic
view of at least a portion of another embodiment of the apparatus
400a, herein designated by the reference numeral 400b. Like the
apparatus 400a, the apparatus 400b is an exemplary implementation
of the apparatus 100 shown in FIG. 1 and/or the apparatus 300 shown
in FIG. 3, and is an exemplary environment in which the method 200a
shown in FIG. 2A and/or the method 200b shown in FIG. 2B may be
performed.
[0103] Like the apparatus 400a, the apparatus 400b includes the
plurality of user inputs 410 and the at least one steering module
420. The at least one steering module 420 includes the toolface
controller 420a and the drawworks controller 420b, described above,
and also a mud pump controller 420c. The apparatus 400b also
includes or is otherwise associated with the plurality of sensors
430, the quill drive 440, and the drawworks drive 450, like the
apparatus 400a. The apparatus 400b also includes or is otherwise
associated with a mud pump drive 460, which is configured to
control operation of a mud pump, such as the mud pump 180 shown in
FIG. 1. In the exemplary embodiment of the apparatus 400b shown in
FIG. 4B, each of the plurality of sensors 430 may be located at the
surface of the wellbore, downhole (e.g., MWD), or elsewhere.
[0104] The mud pump controller 420c is configured to generate a mud
pump drive control signal utilizing data received from ones of the
user inputs 410 and the sensors 430. Thereafter, the mud pump
controller 420c provides the mud pump drive control signal to the
mud pump drive 460, thereby controlling the speed, flow rate,
and/or pressure of the mud pump. The mud pump controller 420c may
form at least a portion of, or may be formed by at least a portion
of, the controller 190 shown in FIG. 1 and/or the controller 325
shown in FIG. 3.
[0105] As described above, the mud motor .DELTA.P may be
proportional or otherwise related to toolface orientation, WOB,
and/or bit torque. Consequently, the mud pump controller 420c may
be utilized to influence the actual mud motor .DELTA.P to assist in
bringing the actual toolface orientation into compliance with the
toolface orientation input value or range provided by the
corresponding user input. Such operation of the mud pump controller
420c may be independent of the operation of the toolface controller
420a and the drawworks controller 420b. Alternatively, as depicted
by the dual-direction arrows 462 shown in FIG. 4B, the operation of
the mud pump controller 420c to obtain or maintain a desired
toolface orientation may be in conjunction or cooperation with the
toolface controller 420a and the drawworks controller 420b.
[0106] The controllers 420a, 420b, and 420c shown in FIGS. 4A and
4B may each be or include intelligent or model-tree adaptive
controllers, such as those commercially available from CyberSoft,
General Cybernation Group, Inc. The controllers 420a, 420b, and
420c may also be collectively or independently implemented on any
conventional or future-developed computing device, such as one or
more personal computers or servers, hand-held devices, PLC systems,
and/or mainframes, among others.
[0107] FIG. 4C is another high-level block diagram identifying
exemplary components of another alternative rigsite drilling
control system 400c of the apparatus 100 in FIG. 1. In this
exemplary embodiment, the block diagram includes a main controller
402 including a toolface calculation engine 404, a steering module
420 including a toolface controller 420a, a drawworks controller
420b, and a mudpump controller 420f. In addition, the control
system includes a user input device 470 that may receive inputs 410
in FIG. 4A, an output display 472, and sensors 430 in communication
with the main controller 402. In the embodiment shown, the toolface
calculation engine 404 and the steering module 420 are applications
that may share the same processor or operate using separate
processors to perform different, but cooperative functions.
Accordingly, the main controller 402 is shown encompassing
drawworks, toolface, and mudpump controllers as well as the
toolface calculation engine 404. In other embodiments, however, the
toolface calculation engine 404 operates using a separate processor
for its calculations and path determinations. The user input device
470 and the display 472 may include at least a portion of a user
interface, such as the user interface 305 shown in FIG. 3. The
user-interface and the controller may be discrete components that
are interconnected via wired or wireless means. However, they may
alternatively be integral components of a single system, for
example.
[0108] As indicated above, a drilling plan includes a wellbore
profile or planned drilling path. This is the pre-selected pathway
for the wellbore to be drilled, typically until conditions require
a change in the drilling plan. It typically specifies key points of
inflection along the wellbore and optimum rates of curvature to be
used to arrive at the wellbore positional objective or objectives,
referred to as target locations. To the extent possible, the main
controller 402 controls the drilling rig to steer the BHA toward
the target location along the planned drilling path within a
specified tolerance zone.
[0109] The calculation engine 404 is a controller or a part of a
controller configured to calculate a control drilling path for the
BHA. This path adheres to the planned wellbore drilling path within
an acceptable margin of error known as a tolerance zone, (also
referred to herein as a "tolerance cylinder" merely for exemplary
purposes). Based upon locational and other feedback, and based upon
the original planned drilling path, the toolface calculation engine
404 will either produce a recommended toolface angular setting
between 0 and 360 degrees and a distance to drill in feet or meters
on this toolface setting, or produce a recommendation to continue
to drill ahead in rotary drilling mode. Preferably, the angular
setting is as minimally different from the drilled section as
possible to minimize drastic curvatures that can complicate
insertion of casing. These recommendations ensure that the BHA
travels in the desired direction to arrive at the target location
in an efficient and effective manner.
[0110] The toolface calculation engine 404 makes its
recommendations based on a number of factors. For example, the
toolface calculation engine 404 considers the original control
drilling path, it considers directional trends, and it considers
real time projection to bit depth. In some embodiments, this engine
404 considers additional information that helps identify the
location and direction of the BHA. In others, the engine 404
considers only the directional trends and the original drilling
path.
[0111] The original control drilling path may have been directly
entered by a user or may have been calculated by the toolface
calculation engine 404 based upon parameters entered by the user.
The directional trends may be determined based upon historical or
existing locational data from the periodic or real-time survey
results to predict bit location. This may include, for example, the
rates of curvature, or dogleg severity, generated over user
specified drilling intervals of measured depths. These rates can be
used as starting points for the next control curve to be drilled,
and can be provided from an analysis of the current drilling
behavior from the historical drilling parameters. The calculation
of normal plane distance to the planned target location can be
carried out from a real-time projection to the bit position. This
real-time projection to bit depth may be calculated by the toolface
calculation engine 404 or the steering module 420 based upon static
and/or dynamic information obtained from the sensors 430. If
calculated by the steering module 420, the values may be fed to the
toolface calculation engine 404 for additional processing. These
projection to bit depth values may be calculated using any number
of methods, including, for example, the minimum curvature arc
method, the directional trend method, and the straight line method.
Once the position is calculated, it is used as the start point for
the normal plane clearance calculation and any subsequent control
path or correction path calculations.
[0112] Using these inputs, the toolface calculation engine 404
makes a determination of where the actual drilling path lies
relative to the planned or control drilling path. Based on its
findings, the toolface calculation engine 404 creates steering
instructions to help keep the actual drilling path aligned with the
planned drilling path, i.e., within the tolerance zone. These
instructions may be output as toolface orientation instructions,
which may be used in input 410h in FIG. 4A. In some embodiments,
the created steering instructions are based on the extent of
deviation of the actual drilling path relative the planned drilling
path, as discussed further below. An exemplary method 500 performed
by the toolface calculation engine 404 for determining the amount
of deviation from the desired path and for determining a corrective
path is shown in FIG. 5A.
[0113] In FIG. 5A, the method 500 can begin at step 502, with the
toolface calculation engine 404 receiving a user-input control or
planned drilling path. The control or planned drilling path is the
desired path that may be based on multiple factors, but frequently
is intended to provide a most efficient or effective path from the
drilling rig to the target location.
[0114] At step 504, the toolface calculation engine 404 considers
the current desired drilling path, directional trends, and
projection to bit depth. As discussed above, the directional trends
are based on prior survey readings and the projection to bit depth
or bit position is determined by the toolface calculation engine
404, the steering module 420, or other controller or module in the
main controller 402. This information is conveyed from the
calculating component to the toolface calculation engine 404 and
includes a dogleg severity value that is used to calculate
corrective curves when needed, as discussed below. Here, as a first
iteration, the current desired drilling path may correspond to the
control or planned drilling path defined in the drill plan received
in step 502.
[0115] At step 506, the toolface calculation engine 404 determines
the actual drilling path based upon the directional trends and the
projection to bit depth. As indicated above, additional data may be
used to determine the actual drilling path and in some embodiments,
the directional trends may be used to estimate the actual drilling
path if the actual drilling path measurement is suspect or the
needed sensory input for the calculation is limited. At step 508,
the toolface calculation engine 404 determines whether the actual
path is within a tolerance zone defined by the current desired
drilling path. A tolerance zone or drill-ahead zone is shown and
described with reference to FIG. 5B.
[0116] FIG. 5B shows an exemplary planned well bore drilling path
530 as a dashed line. The planned well bore path 530 forms the axis
of a hypothetical tolerance cylinder 532, an intervention zone 534,
and a correction zone 536. So long as the actual drilling path is
within the tolerance cylinder 532, the actual drilling path is
within an acceptable range of deviation from the planned drilling
path, and the drilling can continue without steering adjustments.
The tolerance cylinder may be specified within certain percentages
of distance from the desired path or from the borehole diameter,
and can be dependent in part on considerations that are different
for each proposed well. For example, the correction zone may
alternatively be set at about 50% different, or about 20%
different, from the planned path, while the intervention zone may
be set at about 25%, or about 10%, different from the planned path.
Accordingly, returning to FIG. 5A, if the toolface calculation
engine 404 determines that the actual path is within the tolerance
zone about the planned drilling path at step 508, then the process
can simply return to step 504 to await receipt of the next
directional trend and/or projection to bit depth.
[0117] If at step 508, the toolface calculation engine 404
determines that the actual drilling path is outside the tolerance
cylinder 532 shown in FIG. 5B, then the toolface calculation engine
404 determines whether the actual path is within the intervention
zone 534, where the steering module 420 may generate one or more
control signals to intervene to keep the BHA heading in the desired
direction. The intervention zone 534 in FIG. 5B extends
concentrically about the tolerance cylinder 532. It includes an
inner boundary defined by the tolerance cylinder 532 and an outer
boundary defined by the correction zone 536. If the actual drilling
path were in the intervention zone 534, the actual drilling path
may be considered to be moderately deviating from the planned
drilling path 530. In this embodiment, the correction zone 536 is
concentric about the intervention zone 534 and defines the entire
region outside the intervention zone 534. If the actual drilling
path were in the correction zone 536, the actual drilling path may
be considered to be significantly deviating from the planned
drilling path 530.
[0118] Returning now to FIG. 5A, if the actual drilling path is
within the intervention zone 534 at step 510, then the toolface
calculation engine 404 can calculate a 3D curved section path from
the projected bit position towards the planned drilling path 530 at
step 512. As mentioned above, this calculation can be based on data
obtained from current or prior survey files, and may include a
projection of bit depth or bit position and a dogleg severity
value. The calculated curved section path preferably includes the
toolface orientation required to follow the curved section and the
measured depth ("MD") to drill in feet or meters, for example, to
bring the BHA back into the tolerance zone as efficiently as
possible but while minimizing any overcorrection.
[0119] This corrected direction path, as one or more steering
signals, is then output to the steering module 420 at step 514.
Accordingly, one or more of the controllers 420a, b, f in FIG. 4C
receives the desired tool face orientation data and other advisory
information that enable the controllers to generate one or more
command signals that steer the BHA. From the planned drilling path,
the steering module 420 and/or other components of the rigsite
drilling control system 400c can control the drawworks, the top
drive, and the mud pump to directionally steer the BHA according to
the corrected path.
[0120] From here, the process returns to step 504 where the
toolface calculation engine 404 considers the current planned path,
directional trends, and projection to bit depth. Here, the current
planned path is now modified by the curved section path calculated
at step 512. Accordingly during the next iteration, the drilling
path considered the "planned" drilling path is now the corrective
path.
[0121] If at step 510, the actual drilling path is not within the
intervention zone 534, then the toolface calculation engine 404
determines that the actual drilling path must then be in the
correction zone 536 and determines whether the planned path is a
critical drilling path at step 516. A critical drilling path is
typically one where reasons exist that limit the desirability of
creating a new planned drilling path to the target location. For
example, a critical drilling path may be one where a path is chosen
to avoid underground rock formations and the region outside the
intervention zone 534 includes the rock formation. Of course,
designation of a planned drilling path as a critical path may be
made for any reason.
[0122] If the planned drilling path is not a critical path at step
516, then the toolface calculation engine 404 generates a new
planned path from the projected current location of the bit to the
target location. This new planned path may be independent of, or
might not intersect with, the original planned path and may be
generated based on, for example, the most efficient or effective
path to the target from the current location. For example, the new
path may include the minimum amount of curvature required from the
projected current bit location to the target. The new planned path
might show measured depth ("MD"), inclination, azimuth, North-South
and East-West, toolface, and dogleg severity ("DLS") or curvature,
at regular station intervals of about 100 feet or 30 meters, for
example. The path, toolface orientation data, and other data may be
output to the steering module 420 so that the steering module 420
can steer the BHA to follow the new path as closely as possible.
This output may include the calculated toolface advisory angle and
distance to drill. Again the process returns to step 504 where the
toolface calculation engine 404 considers the current planned path,
directional trends, and projection to bit depth. Now the current
planned path is the new planned path calculated at step 518.
[0123] If the planned path is determined to be a critical path at
step 516, however, the toolface calculation engine 404 creates a
path that steers the bit to intersect with the original planned
path for continued drilling. To do this, as indicated at step 520,
the toolface calculation engine 404 calculates at least a first 3D
curved section path (an "intersection path") from the projected bit
position toward the planned drilling path or toward the target.
Optionally, the toolface calculation engine 404 can additionally
calculate a second 3D curved section path to merge the BHA into the
planned path from the intersection path before reaching the target.
These curved section paths may be divided by a hold, or straight
section, depending on how far into the correction zone the BHA has
strayed. Of course, if the intersection path is planned without a
second 3D curved section path, the revised plan will be a hold, or
straight section, from the deviation to the new target, either the
ultimate target or a location on the original planned path.
[0124] The toolface calculation engine 404 outputs the revised
steering path including the newly generated curve(s) as one or more
steering signals to the steering module 420 at step 514. As above,
the revised planned path might include measured depth (MD),
inclination, azimuth, North-South and East-West, toolface, and DLS
at regular station intervals of about 100 feet or 30 meters, for
example. During the next iteration, the toolface calculation engine
404 considers the current planned path, directional trends, and
projection to bit depth with the current planned path being the
corrected planned path at step 504.
[0125] The method 500 iterates during the drilling process to seek
to maintain the actual drilling path with the planned path, and to
adjust the planned path as circumstances require. In some
embodiments, the process occurs continuously in real-time. This can
advantageously permit expedited drilling without need for stopping
to rely on human consultation of a well plan or to evaluate survey
data. In other embodiments, the process iterates after a preset
drilling period or interval, such as, for example, about 90
seconds, about five minutes, about ten minutes, about thirty
minutes, or some other duration. Alternatively, the iteration may
be a predetermined drilling progress depth. For example, the
process may be iterated when the existing wellbore is extended
about five feet, about ten feet, about fifty feet, or some other
depth. The process interval may also include both a time and a
depth component. For example, the process may include drilling for
at least about thirty minutes or until the wellbore is extended
about ten feet. In another example, the interval may include
drilling until the wellbore is extended up to about twenty feet,
but no longer than about ninety minutes. Of course, the
above-described time and depth values for the interval are merely
examples, and many other values are also within the scope of the
present disclosure.
[0126] Once calculated by the toolface calculation engine 404,
typically electronically, the correction path to the original
drilling plan and the correction path to the target location are
passed to the control components of the rigsite control system.
After calculating a correction, the toolface calculation engine 404
or other rigsite control component, including the steering module
420, make tool face recommendations or commands that can be carried
out on the rig.
[0127] In some embodiments, a user may selectively control whether
the toolface calculation engine 404 creates a new planned path to
target or creates a corrected planned path to the original plan
when the actual drilling path is in the correction zone 536. For
example, a user may select a default function that instructs the
correction option to calculate a path to "target" or to "original
plan." In some embodiments, the default may be active during only
designated portions of the original drilling path.
[0128] Because directional control decisions are based on the
amount of deviation of the drilling well from the planned path,
after each survey, a normal plan proximity scan to the planned well
can be carried out. If the drilling position is in the intervention
zone, a nudge of the drilling well back towards the plan will
typically be recommended. If the well continues to diverge from the
plan and enters the correction zone, a re-planned path will
typically be calculated as a correction to target or correction to
original plan.
[0129] Some embodiments consider one or more variables in addition
to, or in place of, the real time projection to bit depth or
directional trends. Input variables may vary for each calculation.
In addition, the dogleg severity, or rate of curvature, may be used
to calculate a suitable curve that limits the amount of oscillation
and avoids drilling path overshoot. Referring to FIG. 12, curve
1202 is an example of a curve with an unacceptably high rate of
curvature. Curve 1204 is an example of a curve with too much
drilling path overshoot and a high amount of oscillation. The
dogleg severity, or rate of curvature, may be derived by analysis
using the current drilling behavior of the BHA, from the historical
drilling parameters, or a combination thereof.
[0130] When creating a modified drill plan that returns the BHA to
the original bit path, as when the projected bit location is within
the intervention zone 534 or when the planned drilling path has
deviated significantly and is a critical path, the goal is to
return to the original planned drilling path prior to arriving at
the target location. The curve profile is still a consideration,
however, as the curve profile can influence friction, oscillation,
and other factors. The dogleg severity value may be used to
calculate one or both curve calculations as before--the first curve
1206 turning the bit toward the original planned path or to the
target, and the optional second curve 1208--permitting the BHA to
more rapidly align with and follow the planned path with a limited
amount, or no amount of overshoot or overcorrection. One method of
determining a curve profile includes calculating a curve-hold or a
curve-hold-curve profile to the final point or target location 1210
in the original plan, and then re-running the calculation on the
final target-minus-1 point, survey time period, or distance
calculation, or other period. The calculating is preferably
achieved electronically. This continues on, going to the
final-minus-2 point and so on, until the calculation fails. The
last successful calculation of the profile can be arranged to
produce one or two arcs having the smallest acceptable rates of
curvature with associated drilled lengths, such as seen in
acceptable curves 1206 and 1208. These values determine the tool
face advisory information for the first correction curve that is
used to develop the new drilling path and that is used to steer the
BHA. When the actual drilling path reaches the final curve to
intersect the original drill plan, in the optional embodiment where
a second, final curve back to the original drill plan is used, this
final curve is drilled at the second calculated drilled length and
rate of curvature.
[0131] It should be noted that, although the tolerance cylinder 532
and the intervention zone 534 are shown as cylinders without a
circular cross-section, they may have other shapes, including
without limitation, oval, conical, parabolic or others, for
example, or may be non-concentric about the planned drilling path
530. Alternative shapes may, e.g., permits the bit to stray more in
one direction than another from the planned path, such as depending
on geological deposits on one side of the planned path.
Furthermore, although the example described includes three zones
(the tolerance zone, the intervention zone, and the correction
zone), this is merely for sake of explanation. In other
embodiments, additional zones may be included, and additional
factors may be weighed when considering whether to create a path
that intersects with the original planned path, whether to create a
path that travels directly to the target location without
intersecting the original planned drilling path, or how gentle the
DLS can be on the corrective curve(s).
[0132] In some exemplary embodiments, a driller can increase or
decrease the size of the tolerance on the fly while drilling by
inputting data to the toolface calculation engine 404. This may
help minimize or avoid overcorrection, or excessive oscillation, in
the drilling path.
[0133] Once calculated, data output from the toolface calculation
engine 404 may act as the input to the steering module 420 in FIG.
4C, or the steering module 420 in FIG. 4A. For example, the data
output from the toolface calculation engine 404 may include, among
others, a toolface orientation usable as the input 410h in FIG. 4A.
In this figure, toolface orientation 410h is an input to the
apparatus 400a and is used by the toolface controller 420a to
control the quill drive 440. Additional data output from toolface
calculation engine 404 may be used as inputs to the to the
apparatus 400a. Using these inputs, the toolface controller 420a,
the drawworks controller 420b, and the mudpump controller 420f can
control drilling rig or the BHA itself to steer the BHA along the
desired drilling path.
[0134] In some embodiments, an alerts module may be used to alert
drillers and/or a well monitoring station of a deviation of the bit
from the planned drilling path, of any potential problem with the
drilling system, or of other information requiring attention. When
drillers are not at the drilling rig, i.e., the driller(s) are
remotely located from the rig, the alerts module may be associated
with the toolface calculation engine 404 in a manner that when the
toolface calculation engine 404 detects deviation of the bit from
the planned drilling path, the alerts module signals the driller,
and in some cases, can be arranged to await, manual user
intervention, such as an approval, before steering the bit along a
new path. This alert may occur on the drilling rig through any
suitable means, and may appear on the display 472 as a visual
alert. Alternatively, it may be an audible alert or may trigger
transmission of an alert signal via an RF signal to designated
locations or individuals.
[0135] In addition to communicating the alert to the display 472 or
other location about the drilling rig, the alert module may
communicate the alert to an offsite location. This may permit
offsite monitoring and may allow a driller to make remote
adjustments. These alerts may be communicated via any suitable
transmission link. For example, in some embodiments where the alert
module sends the alert signal to a remote location, the alert may
be through a satellite communication system. More particularly, one
or more orbital (generally fixed position) satellites may be used
to relay communication signals (potentially bi-directional) between
a well monitoring station and the alerts module on the offshore
platform. Alternatively, radio, cellular, optical, or hard wired
signal transmission methods may be used for communication between
the alerts module and the drillers or the well monitoring station.
In situations where the oil drilling location is an offshore
platform, a satellite communications system may be used, as
cellular, hard wire, and ship to shore-type systems are in some
situations impractical or unreliable. It should be noted that
offsite monitoring and adjustments may be made without specific
alerts, but through using the remote access systems described.
[0136] A centralized well monitoring station may generally be a
computer or server configured to interlace with a plurality of
alerts modules each positioned at a different one of a plurality of
well platforms. The well monitoring station may be configured to
receive various types of signals (satellite, RF, cellular, hard
wired, optical, ship to shore, and telephone, for example) from a
plurality of well drilling locations having an alerts module
thereon. The well monitoring station may also be configured to
transmit selected information from the alerts module to a specific
remote user terminal of a plurality of remote user terminals in
communication with the alerts module. The well monitoring station
may also receive information or instructions from the remote user
terminal. The remote user terminal, via the well monitoring station
and the alerts module, is configured to display drilling or
production parameters for the well associated with the alerts
module.
[0137] The well monitoring station may generally be positioned at a
central data hub, and may be in communication with the alerts
module at the drilling site via a satellite communications link,
for example. The monitoring station may be configured to allow
users to define alerts based on information and data that is
gathered from the drilling site(s) by various data replication and
synchronization techniques. As such, received data may not be truly
real time in every embodiment of the invention, as the alerts
depend upon data that has been transmitted from a drilling site to
the central data hub over a radio or satellite communications
medium (which inherently takes some time to accomplish).
[0138] In one embodiment, an exemplary alerts module monitors one,
two, or more specific applications or properties. The operation
section and the actual values that the alert is setup against are
also generally database and metadata driven, and therefore, when
the property is of a particular data type, then the appropriate
operations may be made available for the user to select.
[0139] Turning now to FIG. 6A, illustrated is a flow-chart diagram
of a method 600a according to one or more aspects of the present
disclosure. The method 600a may be performed in association with
one or more components of the apparatus 100 shown in FIG. 1 during
operation of the apparatus 100. For example, the method 600a may be
performed to optimize drilling efficiency during drilling
operations performed via the apparatus 100, may be carried out by
any of the control systems disclosed in any of the figures herein,
including FIGS. 3 and 4A-C, among others.
[0140] The method 600a includes a step 602 during which parameters
for calculating mechanical specific energy (MSE) are detected,
collected, or otherwise obtained. These parameters may be referred
to herein as MSE parameters and may be used as input in FIGS. 4A-C
and others. The MSE parameters include static and dynamic
parameters. That is, some MSE parameters change on a substantially
continual basis. These dynamic MSE parameters include the weight on
bit (WOB), the drill bit rotational speed (RPM), the drill string
rotational torque (TOR), and the rate of penetration (ROP) of the
drill bit through the formation being drilled. Other MSE parameters
change infrequently, such as after tripping out, reaching a new
formation type, and changing bit types, among other events. These
static MSE parameters include a mechanical efficiency ratio (MER)
and the drill bit diameter (DIA).
[0141] The MSE parameters may be obtained substantially or entirely
automatically, with little or no user input required. For example,
during the first iteration through the steps of the method 600a,
the static MSE parameters may be retrieved via automatic query of a
database. Consequently, during subsequent iterations, the static
MSE parameters may not require repeated retrieval, such as where
the drill bit type or formation data has not changed from the
previous iteration of the method 600a. Therefore, execution of the
step 602 may, in many iterations, require only the detection of the
dynamic MSE parameters. The detection of the dynamic MSE parameters
may be performed by or otherwise in association with a variety of
sensors, such as the sensors shown in FIGS. 1, 3, 4A and/or 4B.
[0142] A subsequent step 604 in the method 600a includes
calculating MSE. In an exemplary embodiment, MSE is calculated
according to the following formula:
MSE=MER.times.[(4.times.WOB)/(.pi..times.DIA.sup.2)+(480.times.RPM.times-
.TOR)/(ROP.times.DIA.sup.2)]
where: MSE=mechanical specific energy (pounds per square inch);
[0143] MER=mechanical efficiency (ratio); [0144] WOB=weight on bit
(pounds); [0145] DIA=drill bit diameter (inches); [0146] RPM=bit
rotational speed (rpm); [0147] TOR=drill string rotational torque
(foot-pounds); and [0148] ROP=rate of penetration (feet per
hour).
[0149] MER may also be referred to as a drill bit efficiency
factor. In an exemplary embodiment, MER equals 0.35. However, MER
may change based on one or more various conditions, such as the bit
type, formation type, and/or other factors.
[0150] The method 600a also includes a decisional step 606, during
which the MSE calculated during the previous step 604 is compared
to an ideal MSE. The ideal MSE used for comparison during the
decisional step 606 may be a single value, such as 100%.
Alternatively, the ideal MSE used for comparison during the
decisional step 606 may be a target range of values, such as
90-100%. Alternatively, the ideal MSE may be a range of values
derived from an advanced analysis of the area being drilled that
accounts for the various formations that are being drilled in the
current operation.
[0151] If it is determined during step 606 that the MSE calculated
during step 604 equals the ideal MSE, or fells within the ideal MSE
range, the method 600a may be iterated by proceeding once again to
step 602. However, if it is determined during step 606 that the
calculated MSE does not equal the ideal MSE, or does not fall
within the ideal MSE range, an additional step 608 is performed.
During step 608, one or more operating parameters are adjusted with
the intent of bringing the MSE closer to the ideal MSE value or
within the ideal MSE range. For example, referring to FIGS. 1 and
6A, collectively, execution of step 608 may include increasing or
decreasing WOB, RPM, and/or TOR by transmitting a control signal
from the controller 190 to the top drive 140 and/or the drawworks
130 to change RPM. TOR, and/or WOB. After step 608 is performed,
the method 600a may be iterated by proceeding once again to step
602.
[0152] Each of the steps of the method 600a may be performed
automatically. For example, automated detection of dynamic MSE
parameters and database look-up of static MSE parameters have
already been described above with respect to step 602. The
controller 190 of FIG. 1 (and others described herein) may be
configured to automatically perform the MSE calculation of step
604, and may also be configured to automatically perform the MSE
comparison of decisional step 606, where both the MSE calculation
and comparison may be performed periodically, at random intervals,
or otherwise. The controller may also be configured to
automatically generate and transmit the control signals of step
608, such as in response to the MSE comparison of step 606.
[0153] FIG. 6B illustrates a block diagram of apparatus 690
according to one or more aspects of the present disclosure.
Apparatus 690 includes a user interface 692, a draw-works 694, a
drive system 696, and a controller 698. Apparatus 690 may be
implemented within the environment and/or apparatus shown in FIGS.
1, 3, and 4A-4C. For example, the draw-works 694 may be
substantially similar to the draw-works 130 shown in FIG. 1, the
drive system 696 may be substantially similar to the top drive 140
shown in FIG. 1, and/or the controller 698 may be substantially
similar to the controller 190 shown in FIG. 1. Apparatus 690 may
also be utilized in performing the method 200a shown in FIG. 2A,
the method 200b shown in FIG. 2B, the method 500 in FIG. 5A, and/or
the method 600a shown in FIG. 6A.
[0154] The user-interface 692 and the controller 698 may be
discrete components that are interconnected via wired or wireless
means. However, the user-interface 692 and the controller 698 may
alternatively be integral components of a single system 699, as
indicated by the dashed lines in FIG. 6B.
[0155] The user-interface 692 includes means 692a for user-input of
one or more predetermined efficiency data (e.g., MER) values and/or
ranges, and means 692b for user-input of one or more predetermined
bit diameters (e.g., DIA) values and/or ranges. Each of the data
input means 692a and 692b may include a keypad, voice-recognition
apparatus, dial, button, switch, slide selector, toggle, joystick,
mouse, data base (e.g., with offset information) and/or other
conventional or future-developed data input device. Such data input
means may support data input from local and/or remote locations.
Alternatively, or additionally, the data input means 692a and/or
692b may include means for user-selection of predetermined MER and
DIA values or ranges, such as via one or more drop-down menus. The
MER and DIA data may also or alternatively be selected by the
controller 698 via the execution of one or more database look-up
procedures. In general, the data input means and/or other
components within the scope of the present disclosure may support
system operation and/or monitoring from stations on the rig site as
well as one or more remote locations with a communications link to
the system, network, local area network (LAN), wide area network
(WAN), Internet, and/or radio, among other means.
[0156] The user-interlace 692 may also include a display 692c for
visually presenting information to the user in textual, graphical
or video form. The display 692c may also be utilized by the user to
input the MER and DIA data in conjunction with the data input means
692a and 692b. For example, the predetermined efficiency and bit
diameter data input means 692a and 692b may be integral to or
otherwise communicably coupled with the display 692c.
[0157] The draw-works 694 includes an ROP sensor 694a that is
configured for detecting an ROP value or range, and may be
substantially similar to the ROP sensor 130a shown in FIG. 1. The
ROP data detected via the ROP sensor 694a may be sent via
electronic signal to the controller 698 via wired or wireless
transmission. The draw-works 694 also includes a control circuit
694b and/or other means for controlling feed-out and/or feed-in of
a drilling line (such as the drilling line 125 shown in FIG.
1).
[0158] The drive system 696 includes a torque sensor 696a that is
configured for detecting a value or range of the reactive torsion
of the drill string (e.g., TOR), much the same as the torque sensor
140a and drill string 155 shown in FIG. 1. The drive system 696
also includes a bit speed sensor 696b that is configured for
detecting a value or range of the rotational speed of the drill bit
within the wellbore (e.g., RPM), much the same as the bit speed
sensor 140b, drill bit 175 and wellbore 160 shown in FIG. 1. The
drive system 696 also includes a WOB sensor 696c that is configured
for detecting a WOB value or range, much the same as the WOB sensor
140c shown in FIG. 1. Alternatively, or additionally, the WOB
sensor 696c may be located separate from the drive system 696,
whether in another component shown in FIG. 6B or elsewhere. The
drill string torsion, bit speed, and WOB data detected via sensors
696a, 696b and 696c, respectively, may be sent via electronic
signal to the controller 698 via wired or wireless transmission.
The drive system 696 also includes a control circuit 696d and/or
other means for controlling the rotational position, speed and
direction of the quill or other drill string component coupled to
the drive system 696 (such as the quill 145 shown in FIG. 1). The
control circuit 696d and/or other component of the drive system 696
may also include means for controlling downhole mud motor(s). Thus,
RPM within the scope of the present disclosure may include mud pump
flow data converted to downhole mud motor RPM, which may be added
to the string RPM to determine total bit RPM.
[0159] The controller 698 is configured to receive the
above-described MSE parameters from the user interface 692, the
draw-works 694, and the drive system 696 and utilize the MSE
parameters to continuously, periodically, or otherwise calculate
MSE. The controller 698 is further configured to provide a signal
to the draw-works 694 and/or the drive system 696 based on the
calculated MSE. For example, the controller 6980 may execute the
method 200a shown in FIG. 2A and/or the method 200b shown in FIG.
2B, and consequently provide one or more signals to the draw-works
694 and/or the drive system 696 to increase or decrease WOB and/or
bit speed, such as may be required to optimize drilling efficiency
(based on MSE).
[0160] Referring to FIG. 6C, illustrated is a flow-chart diagram of
a method 600b for optimizing drilling operation based on real-time
calculated MSE according to one or more aspects of the present
disclosure. The data obtained may be used in cooperation with any
of the systems disclosed herein. The method 600b may be performed
via the apparatus 100 shown in FIG. 1, the apparatus 300 shown in
FIG. 3, the apparatus 400a shown in FIG. 4A, the apparatus 400b
shown in FIG. 4B, and/or the apparatus 690 shown in FIG. 6B. The
method 600b may also be performed in conjunction with the
performance of the method 200a shown in FIG. 2A, the method 200b
shown in FIG. 2B, under the method 600a shown in FIG. 6A. The
method 600b shown in FIG. 6C may include or form at least a portion
of the method 600a shown in FIG. 6A.
[0161] During a step 6122 of the method 600b, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
varying WOB. Because the baseline MSE determined in step 612 will
be utilized for optimization by varying WOB, the convention
MSE.sub.BLWOB will be used herein.
[0162] In a subsequent step 614, the WOB is changed. Such change
can include either increasing or decreasing the WOB. The increase
or decrease of WOB during step 614 may be within certain,
predefined WOB limits. For example, the WOB change may be no
greater than about 10%. However, other percentages are also within
the scope of the present disclosure, including where such
percentages are within or beyond the predefined WOB limits. The WOB
may be manually changed via operator input, or the WOB may be
automatically changed via signals transmitted by a controller,
control system, and/or other component of the drilling rig and
associated apparatus. As above, such signals may be via remote
control from another location.
[0163] Thereafter, during a step 616, drilling continues with the
changed WOB during a predetermined drilling interval .DELTA.WOB.
The .DELTA.WOB interval may be a predetermined time period, such as
five minutes, ten minutes, thirty minutes, or some other duration.
Alternatively, the .DELTA.WOB interval may be a predetermined
drilling progress depth. For example, step 616 may include
continuing drilling operation with the changed WOB until the
existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The .DELTA.WOB interval may also include both a
time and a depth component. For example, the .DELTA.WOB interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the .DELTA.WOB
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes. Of course, the
above-described time and depth values for the .DELTA.WOB interval
are merely examples, and many other values are also within the
scope of the present disclosure.
[0164] After continuing drilling operation through the .DELTA.WOB
interval with the changed WOB, a step 618 is performed to determine
the MSE.sub..DELTA.WOB resulting from operating with the changed
WOB during the .DELTA.WOB interval. In a subsequent decisional step
620, the changed MSE.sub..DELTA.WOB is compared to the baseline
MSE.sub.BLWOB. If the changed MSE.sub..DELTA.WOB is desirable
relative to the MSE.sub.BLWOB, the method 600b continues to a step
622. However, if the changed MSE.sub..DELTA.WOB is not desirable
relative to the MSE.sub.BLWOB, the method 600b continues to a step
624 where the WOB is restored to its value before step 614 was
performed, and the method then continues to step 622.
[0165] The determination made during decisional step 620 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub..DELTA.WOB to be desirable if it is substantially equal to
and/or less than the MSE.sub.BLWOB. However, additional or
alternative factors may also play a role in the determination made
during step 620.
[0166] During step 622 of the method 600b, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
varying the bit rotational speed, RPM. Because the baseline MSE
determined in step 622 will be utilized for optimization by varying
RPM, the convention MSE.sub.BLRPM will be used herein.
[0167] In a subsequent step 626, the RPM is changed. Such change
can include either increasing or decreasing the RPM. The increase
or decrease of RPM during step 626 may be within certain,
predefined RPM limits. For example, the RPM change may be no
greater than about 10%. However, other percentages are also within
the scope of the present disclosure, including where such
percentages are within or beyond the predefined RPM limits. The RPM
may be manually changed via operator input, or the RPM may be
automatically changed via signals transmitted by a controller,
control system, and/or other component of the drilling rig and
associated apparatus.
[0168] Thereafter, during a step 628, drilling continues with the
changed RPM during a predetermined drilling interval .DELTA.RPM.
The .DELTA.RPM interval may be a predetermined time period, such as
five minutes, ten minutes, thirty minutes, or some other duration.
Alternatively, the .DELTA.RPM interval may be a predetermined
drilling progress depth. For example, step 628 may include
continuing drilling operation with the changed RPM until the
existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The .DELTA.RPM interval may also include both a
time and a depth component. For example, the .DELTA.RPM interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the .DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes. Of course, the
above-described time and depth values for the .DELTA.RPM interval
are merely examples, and many other values are also within the
scope of the present disclosure.
[0169] After continuing drilling operation through the .DELTA.RPM
interval with the changed RPM, a step 630 is performed to determine
the MSE.sub..DELTA.RPM resulting from operating with the changed
RPM during the .DELTA.RPM interval. In a subsequent decisional step
632, the changed MSE.sub..DELTA.RPM is compared to the baseline
MSE.sub.BLRPM. If the changed MSE.sub..DELTA.RPM is desirable
relative to the MSE.sub.BLRPM, the method 600b returns to step 612.
However, if the changed MSE.sub..DELTA.RPM is not desirable
relative to the MSE.sub.BLRPM, the method 600b continues to step
634 where the RPM is restored to its value before step 626 was
performed, and the method then continues to step 612.
[0170] The determination made during decisional step 632 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub..DELTA.RPM to be desirable if it is substantially equal to
and/or less than the MSE.sub.BLRPM. However, additional or
alternative factors may also play a role in the determination made
during step 632.
[0171] Moreover, after steps 632 and/or 634 are performed, the
method 600b may not immediately return to step 612 for a subsequent
iteration. For example, a subsequent iteration of the method 600b
may be delayed for a predetermined time interval or drilling
progress depth. Alternatively, the method 600b may end after the
performance of steps 632 and/or 634.
[0172] Referring to FIG. 6D, illustrated is a flow-chart diagram of
a method 600c for optimizing drilling operation based on real-time
calculated MSE according to one or more aspects of the present
disclosure. The method 600c may be performed via the apparatus 100
shown in FIG. 1, the apparatus 300 shown in FIG. 3, the apparatus
400a shown in FIG. 4A, the apparatus 400b shown in FIG. 4B, and/or
the apparatus 690 shown in FIG. 6B. The method 600c may also be
performed in conjunction with the performance of the method 200a
shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a
shown in FIG. 6A, and/or the method 600b shown in FIG. 6C. The
method 600c shown in FIG. 6D may include or form at least a portion
of the method 600a shown in FIG. 6A and/or the method 600b shown in
FIG. 6C.
[0173] During a step 640 of the method 600c, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
decreasing WOB. Because the baseline MSE determined in step 640
will be utilized for optimization by decreasing WOB, the convention
MSE.sub.BLWOB will be used herein.
[0174] In a subsequent step 642, the WOB is decreased. The decrease
of WOB during step 642 may be within certain, predefined WOB
limits. For example, the WOB decrease may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined WOB limits. The WOB may be manually decreased
via operator input, or the WOB may be automatically decreased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0175] Thereafter, during a step 644, drilling continues with the
decreased WOB during a predetermined drilling interval -.DELTA.WOB.
The -.DELTA.WOB interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the -.DELTA.WOB interval may be a
predetermined drilling progress depth, for example, step 644 may
include continuing drilling operation with the decreased WOB until
the existing wellbore is extended five feet, ten feet., fifty feet,
or some other depth. The -.DELTA.WOB interval may also include both
a time and a depth component. For example, the -.DELTA.WOB interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the -.DELTA.WOB
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes. Of course, the
above-described time and depth values for the -.DELTA.WOB interval
are merely examples, and many other values are also within the
scope of the present disclosure.
[0176] After continuing drilling operation through the -.DELTA.WOB
interval with the decreased WOB, a step 646 is performed to
determine the MSE.sub.-.DELTA.WOB resulting from operating with the
decreased WOB during the -.DELTA.WOB interval. In a subsequent
decisional step 648, the decreased MSE.sub.-.DELTA.WOB is compared
to the baseline MSE.sub.BL-WOB. If the decreased MSE.sub..DELTA.WOB
is desirable relative to the MSE.sub.BL-WOB, the method 600c
continues to a step 652. However, if the decreased
MSE.sub.-.DELTA.WOB is not desirable relative to the
MSE.sub.BI-WOB, the method 600c continues to a step 650 where the
WOB is restored to its value before step 642 was performed, and the
method then continues to step 652.
[0177] The determination made during decisional step 648 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub.-.DELTA.WOB to be desirable if it is substantially equal to
and/or less than the MSE.sub.BL-WOB. However, additional or
alternative factors may also play a role in the determination, made
during step 648.
[0178] During step 652 of the method 6.00c, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
increasing the WOB. Because the baseline MSE determined in step 652
will be utilized for optimization by increasing WOB, the convention
MSE.sub.BL+WOB will be used herein.
[0179] In a subsequent step 654, the WOB is increased. The increase
of WOB during step 654 may be within certain, predefined WOB
limits. For example, the WOB increase may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined WOB limits. The WOB may be manually increased
via operator input, or the WOB may be automatically increased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0180] Thereafter, during a step 656, drilling continues with the
increased WOB during a predetermined drilling interval +.DELTA.WOB.
The +.DELTA.WOB interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the +.DELTA.WOB interval may be a
predetermined drilling progress depth. For example, step 656 may
include continuing drilling operation with the increased WOB until
the existing wellbore is extended five feet, ten feet, fifty feel,
or some other depth. The +.DELTA.WOB interval may also include both
a time and a depth component. For example, the +.DELTA.WOB interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the +.DELTA.WOB
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0181] After continuing drilling operation through the +.DELTA.WOB
interval with the increased WOB, a step 658 is performed to
determine the MSE.sub.+.DELTA.WOB resulting from operating with the
increased WOB during the +.DELTA.WOB interval. In a subsequent
decisional step 660, the changed MSE.sub.+.DELTA.WOB is compared to
the baseline MSE.sub.BL+WOB. If the changed MSE.sub.+.DELTA.WOB is
desirable relative to the MSE.sub.BL+WOB, the method 600c continues
to a step 664. However, if the changed MSE.sub.+.DELTA.WOB is not
desirable relative to the MSE.sub.BL+WOB, the method 600c continues
to a step 662 where the WOB is restored to its value before step
654 was performed, and the method then continues to step 664.
[0182] The determination made during decisional step 660 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub.+.DELTA.WOB to be desirable if it is substantially equal to
and/or less than the MSE.sub.BL+WOB. However, additional or
alternative factors may also play a role in the determination made
during step 660.
[0183] During step 664 of the method 600c, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
decreasing the bit rotational speed, RPM. Because the baseline MSE
determined in step 664 will be utilized for optimization by
decreasing RPM, the convention MSE.sub.BL-RPM will be used
herein.
[0184] In a subsequent step 666, the RPM is decreased. The decrease
of RPM during step 666 may be within certain, predefined RPM
limits. For example, the RPM decrease may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined RPM limits. The RPM may be manually decreased
via operator input, or the RPM may be automatically decreased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0185] Thereafter, during a step 668, drilling continues with the
decreased RPM during a predetermined drilling interval -.DELTA.RPM.
The -.DELTA.RPM interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the -.DELTA.RPM interval may be a
predetermined drilling progress depth. For example, step 668 may
include continuing drilling operation with the decreased RPM until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The -.DELTA.RPM interval may also include both
a time and a depth component. For example, the -.DELTA.RPM interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the -.DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0186] After continuing drilling operation through the -.DELTA.RPM
interval with the decreased RPM, a step 670 is performed to
determine the MSE.sub.-.DELTA.RPM resulting from operating with the
decreased RPM during, the -.DELTA.RPM interval. In a subsequent
decisional step 672, the decreased MSE.sub.-.DELTA.RPM is compared
to the baseline MSE.sub.BL-RPM. If the changed MSE.sub.-.DELTA.RPM
is desirable relative to the MSE.sub.BL-RPM, the method 600c
continues to a step 676. However, if the changed
MSE.sub.-.DELTA.RPM is not desirable relative to the
MSE.sub.BL-RPM, the method 600c continues to a step 674 where the
RPM is restored to its value before step 666 was performed, and the
method then continues to step 676.
[0187] The determination made during decisional step 672 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub.-.DELTA.RPM to be desirable if it is substantially equal to
and/or less than the MSE.sub.BL-RPM. However, additional or
alternative factors may also play a role in the determination made
during step 672.
[0188] During step 676 of the method 600c, a baseline MSE is
determined for optimization of drilling efficiency based on MSE by
increasing the bit rotational speed, RPM. Because the baseline MSE
determined in step 676 will be utilized for optimization by
increasing RPM, the convention MSE.sub.BL+RPM will be used
herein.
[0189] In a subsequent step 678, the RPM is increased. The increase
of RPM during step 678 may be within certain, predefined RPM
limits. For example, the RPM increase may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined RPM limits. The RPM may be manually increased
via operator input, or the RPM may be automatically increased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0190] Thereafter, during a step 680, drilling continues with the
increased RPM during a predetermined drilling interval +.DELTA.RPM.
The +.DELTA.RPM interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the +.DELTA.RPM interval may be a
predetermined drilling progress depth. For example, step 680 may
include continuing drilling operation with the increased RPM until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The +.DELTA.RPM interval may also include both
a time and a depth component. For example, the +.DELTA.RPM interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the +.DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0191] After continuing drilling operation through the +.DELTA.RPM
interval with the increased RPM, a step 682 is performed to
determine the MSE.sub.+.DELTA.RPM resulting from operating with the
increased RPM during the +.DELTA.RPM interval, in a subsequent
decisional step 684, the increased MSE.sub.+RPM is compared to the
baseline MSE.sub.BL+RPM. IF the changed MSE.sub.+.DELTA.RPM is
desirable relative to the MSE.sub.BL+RPM, the method 600c continues
to a step 688. However, if the changed MSE.sub.+.DELTA.RPM is not
desirable relative to the MSE.sub.BL+RPM, the method 600c continues
to a step 686 where the RPM is restored to its value before step
678 was performed, and the method then continues to step 688.
[0192] The determination made during decisional step 684 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
MSE.sub.+.DELTA.RPM to be desirable if it is substantially equal to
and/or less than the MSE.sub.BL+RPM. However, additional or
alternative factors may also play a role in the determination made
during step 684.
[0193] Step 688 includes awaiting a predetermined time period or
drilling depth interval before reiterating the method 600c by
returning to step 640. However, in an exemplary embodiment, the
interval may be as small as 0 seconds or 0 feet, such that the
method returns to step 640 substantially immediately after
performing steps 684 and/or 686. Alternatively, the method 600c may
not require iteration, such that the method 6.00c may substantially
end after the performance of steps 684 and/or 686.
[0194] Moreover, the drilling intervals -.DELTA.WOB, +.DELTA.WOB,
-.DELTA.RPM and +.DELTA.ROM may each be substantially identical
within a single iteration of the method 600c. Alternatively, one or
more of the intervals may vary in duration or depth relative to the
other intervals. Similarly, the amount that the WOB is decreased
and increased in steps 642 and 654 may be substantially identical
or may vary relative to each other within a single iteration of the
method 600c. The amount that the RPM is decreased and increased in
steps 666 and 678 may be substantially identical or may vary
relative to each other within a single iteration of the method
600c. The WOB and RPM variances may also change or stay the same
relative to subsequent iterations of the method 600c.
[0195] As described above, one or more aspects of the present
disclosure may be utilized for drilling operation or control based
on MSE. However, one or more aspects of the present disclosure may
additionally or alternatively be utilized for drilling operation or
control based on .DELTA.T. That is, as described above, during
drilling operation, torque is transmitted from the top drive or
other rotary drive to the drill string. The torque required to
drive the bit may be referred to as the Torque On Bit (TOB), and
may be monitored utilizing a sensor such as the torque sensor 140a
shown in FIG. 1, the torque sensor 355 shown in FIG. 3, one or more
of the sensors 430 shown in FIGS. 4A and 4B, the torque sensor 696a
shown in FIG. 6B, and/or one or more torque sensing devices of the
BHA.
[0196] The drill string undergoes various types of vibration during
drilling, including axial (longitudinal) vibrations, bending
(lateral) vibrations, and torsional (rotational) vibrations. The
torsional vibrations are caused by nonlinear interaction between
the bit, the drill string, and the wellbore. As described above,
this torsional vibration can include stick-slip vibration,
characterized by alternating stops (during which the BHA "sticks"
to the wellbore) and intervals of large angular velocity of the BHA
(during which the BHA "slips" relative to the wellbore).
[0197] The stick-slip behavior of the BHA causes real-time
variations of TOB, or .DELTA.T. This .DELTA.T may be utilized to
support a Stick Slip Alarm (SSA) according to one or more aspects
of the present disclosure. For example, a .DELTA.T or SSA parameter
may be displayed visually with a "Stop Light" indicator, where a
green light may indicate an acceptable operating condition (e.g.,
SSA parameter of 0-15), an amber light may indicate that stick-slip
behavior is imminent (e.g., SSA parameter of 16-25), and a red
light may indicate that stick-slip behavior is likely occurring
(e.g., SSA parameter above 25). However, these example thresholds
may be adjustable during operation, as they may change with the
drilling conditions. The .DELTA.T or SSA parameter may
alternatively or additionally be displayed graphically (e.g.,
showing current and historical data), audibly (e.g., via an
annunciator), and/or via a meter or gauge display. Combinations of
these display options are also within the scope of the present
disclosure. For example, the above-described "Stop Light" indicator
may continuously indicate the SSA parameter regardless of its
value, and an audible alarm may be triggered if the SSA parameter
exceeds a predetermined value (e.g., 25).
[0198] A drilling operation controller or other apparatus within
the scope of the present disclosure may have integrated therein one
or more aspects of drilling operation or control based on .DELTA.T
or the SSA parameter as described above. For example, a controller
such as the controller 190 shown in FIG. 1, the controller 325
shown in FIG. 3, controller 420 shown in FIGS. 4A or 4B, and/or the
controller 698 shown in FIG. 6B may be configured to automatically
adjust the drill string RPM with a short burst of increased or
decreased RPM (e.g., +/-5 RPM) to disrupt the harmonic of
stick-slip vibration, either prior to or when stick-slip is
detected, and then return to normal RPM. The controller may be
configured to automatically step RPM up or down by a predetermined
or user-adjustable quantity or percentage for a predetermined or
user-adjustable duration, in attempt to move drilling operation out
of the harmonic state. Alternatively, the controller may be
configured to automatically continue to adjust RPM up or down
incrementally until the .DELTA.T or SSA parameter indicates that
the stick-slip operation has been halted.
[0199] In an exemplary embodiment, the .DELTA.T or SSA-enabled
controller may be further configured to automatically reduce WOB if
stick slip is severe, such as may be due to an excessively high
target WOB. Such automatic WOB reduction may include a single
adjustment or incremental adjustments, whether temporary or
long-term, and which may be sustained until the .DELTA.T or SSA
parameter indicates that the stick-slip operation has been
halted.
[0200] The .DELTA.T or SSA-enabled controller may be further
configured to automatically increase WOB, such as to find the upper
WOB stick-slip limit. For example, if all other possible drilling
parameters are optimized or adjusted to within corresponding
limits, the controller may automatically increase WOB incrementally
until the .DELTA.T or SSA parameter nears or equals its upper limit
(e.g., 25).
[0201] In an exemplary embodiment, .DELTA.T-based drilling
operation or control according to one or more aspects of the
present disclosure may function according to one or more aspects of
the following pseudo-code: [0202] IF (counter<=Process_Time)
[0203] IF (counter==1) [0204] Minimum_Torque=Realtime_Torque [0205]
PRINT ("Minimum", Minimum_Torque) [0206]
Maximum_Torque=Realtime_Torque [0207] PRINT ("Maximum",
Maximum_Torque) [0208] END [0209] IF
(Realtime_Torque<Minimum_Torque) [0210]
Minimum_Torque=Realtime_Torque [0211] END [0212] IF
(Maximum_Torque<Realtime_Torque) [0213]
Maximum_Torque=Realtime_Torque [0214] END [0215]
Torque_counter=(Torque_counter+Realtime_Torque) [0216]
Average_Torque=( Torque_counter/counter) [0217] counter=counter+1
[0218] PRINT ("Proeess_Time", Process_Time) [0219] ELSE [0220]
SSA=((Maximum_Torque-Minimum_Torque)/Average_Torque)*100 where
Process_Time is the time elapsed since monitoring of the .DELTA.T
or SSA parameter commenced, Minimum_Torque is the minimum TOB which
occurred during Process_Time, Maximum_Torque is the maximum TOB
which occurred during Process_Time, Realtime_Torque is current TOB,
Average_Torque is the average TOB during Process_Time, and SSA is
the Stick-Slip Alarm parameter.
[0221] As described above, the .DELTA.T or SSA parameter may be
utilized within or otherwise according to the method 200a shown in
FIG. 2A, the method 200b shown in FIG. 2B, the method 600a shown in
FIG. 6A, the method 600b shown in FIG. 6C, and/or the method 600c
shown in FIG. 6D. For example, as shown, in FIG. 7A, the .DELTA.T
or SSA parameter may be substituted for the MSE parameter described
above with reference to FIG. 6A. Alternatively, the .DELTA.T or SSA
parameter may be monitored in addition to the MSE parameter
described above with reference to FIG. 6A, such that drilling
operation or control is based on both MSE and the .DELTA.T or SSA
parameter.
[0222] Referring to FIG. 7A, illustrated is a flow-chart diagram of
a method 700a according to one or more aspects of the present
disclosure. The method 700a may be performed in association with
one or more components of the apparatus 100 shown in. FIG. 1, the
apparatus 300 shown in FIG. 3, the apparatus 400a shown in FIG. 4A,
the apparatus 400b shown in FIG. 4B, and/or the apparatus 690 shown
in FIG. 6B, during operation thereof.
[0223] The method 700a includes a step 702 during winch current
.DELTA.T parameters are measured. In a subsequent step 704, the
.DELTA.T is calculated. If the .DELTA.T is sufficiently equal to
the desired .DELTA.T or otherwise ideal, as determined during
decisional step 706, the method 700a is iterated and the step 702
is repeated. "Ideal" may be as described above. The iteration of
the method 700a may be substantially immediate, or there may be a
delay period before the method 700a is iterated and the step 702 is
repeated. If the .DELTA.T is not ideal, as determined during
decisional step 706, the method 700a continues to a step 708 during
which one or more drilling parameters (e.g., WOB, RPM, etc.) are
adjusted in attempt to improve the .DELTA.T. After step 708 is
performed, the method 700a is iterated and the step 702 is
repeated. Such iteration may be substantially immediate, or there
may be a delay period before the method 700a is iterated and the
step 702 is repeated.
[0224] Referring to FIG. 7B, illustrated is a flow-chart diagram of
a method 700b for monitoring .DELTA.T and/or SSA according to one
or more aspects of the present disclosure. The method 700b may be
performed via the apparatus 100 shown in FIG. 1, the apparatus 300
shown in FIG. 3, the apparatus 400a shown in FIG. 4A, the apparatus
400b shown in FIG. 4B, and/or the apparatus 690 shown in FIG. 6B.
The method 700b may also be performed in conjunction with the
performance of the method 200a shown in FIG. 2A, the method 200b
shown in FIG. 2B, the method 600a shown in FIG. 6A, the method 600b
shown in FIG. 6C, the method 600c shown in FIG. 6D, and/or the
method 700a shown in FIG. 7A. The method 700b shown in FIG. 7B may
include or form at least a portion of the method 700a shown in FIG.
7A.
[0225] During a step 712 of the method 700b, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by varying WOB.
Because the baseline .DELTA.T determined in step 712 will be
utilized for optimization by varying WOB, the convention
.DELTA.T.sub.BLWOB will be used herein.
[0226] In a subsequent step 714, the WOB is changed. Such change
can include either increasing or decreasing the WOB. The increase
or decrease of WOB during step 714 may be within certain,
predefined WOB limits. For example, the WOB change may be no
greater than about 10%. However, other percentages are also within
the scope of the present disclosure, including where such
percentages are within or beyond the predefined WOB limits. The WOB
may be manually changed via operator input, or the WOB may be
automatically changed via signals transmitted by a controller,
control system, and/or other component of the drilling rig and
associated apparatus. As above, such signals may be via remote
control from another location.
[0227] Thereafter, during a step 716, drilling continues with the
changed WOB during a predetermined drilling interval .DELTA.WOB.
The .DELTA.WOB interval may be a predetermined time period, such as
five minutes, ten minutes, thirty minutes, or some other duration.
Alternatively, the .DELTA.WOB interval may be a predetermined
drilling progress depth. For example, step 716 may include
continuing drilling operation with the chunked WOB until the
existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The .DELTA.WOB interval may also include both a
time and a depth component. For example, the .DELTA.WOB interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the .DELTA.WOB
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes. Of course, the
above-described time and depth values for the .DELTA.WOB interval
are merely examples, and many other values are also within the
scope of the present disclosure.
[0228] After continuing drilling operation through the .DELTA.WOB
interval with the changed WOB, a step 718 is performed, to
determine the .DELTA.T.sub..DELTA.WOB resulting from operating with
the changed WOB during the .DELTA.WOB interval. In a subsequent
decisional step 720, the changed .DELTA.T.sub..DELTA.WOB is
compared to the baseline .DELTA.T.sub.BLWOB. If the changed
.DELTA.T.sub..DELTA.WOB is desirable relative to the
.DELTA.T.sub.BLWOB, the method 700b continues to a step 722.
However, if the changed .DELTA.T.sub..DELTA.WOB is not desirable
relative to the .DELTA.T.sub.BLWOB, the method 700b continues to a
step 724 where the WOB is restored to its value before step 714 was
performed, and the method then continues to step 722.
[0229] The determination made during decisional step 720 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub..DELTA.WOB to be desirable if it is substantially
equal to and/or less than the .DELTA.T.sub.BLWOB. However,
additional or alternative factors may also play a role in the
determination made during step 720.
[0230] During step 722 of the method 700b, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by varying the bit
rotational speed, RPM. Because the baseline .DELTA.T determined in
step 722 will be utilized for optimization by varying RPM, the
convention .DELTA.T.sub.BLRPM will be used herein.
[0231] In a subsequent step 726, the RPM is changed. Such change
can include either increasing or decreasing the RPM. The increase
or decrease of RPM during step 726 may be within certain,
predefined RPM limits. For example, the RPM change may be no
greater than about 10%. However, other percentages are also within
the scope of the present disclosure, including where such
percentages are within or beyond the predefined RPM limits. The RPM
may be manually changed via operator input, or the RPM may be
automatically changed via signals transmitted by a controller,
control system, and/or other component of the drilling rig and
associated apparatus.
[0232] Thereafter, during a step 728, drilling continues with the
changed RPM during a predetermined drilling interval .DELTA.RPM.
The .DELTA.RPM interval may be a predetermined time period, such as
five minutes, ten minutes, thirty minutes, or some other duration.
Alternatively, the .DELTA.RPM interval may be a predetermined
drilling progress depth. For example, step 728 may include
continuing drilling operation with the changed RPM until the
existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The .DELTA.RPM interval may also include both a
time and a depth component. For example, the .DELTA.RPM interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the .DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes. Of course, the
above-described time and depth values for the .DELTA.RPM interval
are merely examples, and many other values are also within the
scope of the present disclosure.
[0233] After continuing drilling operation through the .DELTA.RPM
interval with the changed RPM, a step 730 is performed to determine
the .DELTA.T.sub..DELTA.RPM resulting from operating with the
changed RPM during the .DELTA.RPM interval. In a subsequent
decisional step 732, the changed .DELTA.T.sub..DELTA.RPM is
compared to the baseline .DELTA.T.sub.BLRPM. If the changed
.DELTA.T.sub..DELTA.RPM is desirable relative to the
.DELTA.T.sub.BLRPM, the method 700b returns to step 712. However,
if the changed .DELTA.T.sub..DELTA.RPM is not desirable relative to
the .DELTA.T.sub.BLRPM, the method 700b continues to step 734 where
the RPM is restored to its value before step 726 was performed, and
the method then continues to step 712.
[0234] The determination made during decisional step 732 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub..DELTA.RPM to be desirable if it is substantially
equal to and/or less than the .DELTA.T.sub.BLRPM. However,
additional or alternative factors may also play a role in the
determination made during step 732.
[0235] Moreover, after steps 732 and/or 734 are performed, the
method 700b may not immediately return to step 712 for a subsequent
iteration. For example, a subsequent iteration of the method 700b
may be delayed for a predetermined time interval or drilling
progress depth. Alternatively, the method 700b may end after the
performance of steps 732 and/or 734.
[0236] Referring to FIG. 7C, illustrated is a flow-chart diagram of
a method 700c for optimizing drilling operation based on real-time
calculated .DELTA.T according to one or more aspects of the present
disclosure. The method 700c may be performed via the apparatus 100
shown in FIG. 1, the apparatus 300 shown in FIG. 3, the apparatus
400a shown in FIG. 4A, the apparatus 400b shown in FIG. 4B, and/or
the apparatus 690 shown in FIG. 6B. The method 700c may also be
performed in conjunction with the performance of the method 200a
shown in FIG. 2A, the method 200b shown in FIG. 2B, the method 600a
shown in FIG. 6A, the method 600b shown in FIG. 6C, the method 600c
shown in FIG. 6D, the method 700a shown in FIG. 7A, and/or the
method 700b shown in FIG. 7B. The method 700c shown in FIG. 7C may
include or form at least a portion of the method 700a shown in FIG.
7A and/or the method 700b shown in FIG. 7B.
[0237] During a step 740 of the method 700c, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by decreasing WOB.
Because the baseline .DELTA.T determined in step 740 will be
utilized for optimization by decreasing WOB, the convention
.DELTA.T.sub.BL-WOB will be used herein.
[0238] In a subsequent step 742, the WOB is decreased. The decrease
of WOB during step 742 may be within certain, predefined WOB
limits. For example, the WOB decrease may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined WOB limits. The WOB may be manually decreased
via operator input, or the WOB may be automatically decreased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0239] Thereafter, during a step 744, drilling continues with the
decreased WOB during a predetermined drilling interval -.DELTA.WOB.
The -.DELTA.WOB interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the -.DELTA.WOB interval may be a
predetermined drilling progress depth. For example, step 744 may
include continuing drilling operation with the decreased WOB until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The -.DELTA.WOB interval, may also include
both a time and a depth component. For example, the -.DELTA.WOB
interval may include drilling for at least thirty minutes or until
the wellbore is extended ten feet. In another example, the
-.DELTA.WOB interval may include drilling until the wellbore is
extended twenty feet, but no longer than ninety minutes. Of course,
the above-described time and depth values for the -.DELTA.WOB
interval are merely examples, and many other values are also within
the scope of the present disclosure.
[0240] After continuing drilling operation through the -.DELTA.WOB
interval with the decreased WOB, a step 746 is performed to
determine the .DELTA.T.sub.-.DELTA.WOB resulting from operating
with the decreased WOB during the -.DELTA.WOB interval. In a
subsequent decisional step 748, the decreased
.DELTA.T.sub.-.DELTA.WOB is compared to the baseline
.DELTA.T.sub.BL-WOB. If the decreased .rarw.T.sub.-.DELTA.WOB is
desirable relative to the .DELTA.T.sub.BL-WOB, the method 700c
continues to a step 752. However, if the decreased
.DELTA.T.sub.-.DELTA.WOB is not desirable relative to the
.DELTA.T.sub.BL-WOB, the method 700c continues to a step 750 where
the WOB is restored to its value before step 742 was performed, and
the method then continues to step 752.
[0241] The determination made during decisional step 748 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub.-.DELTA.WOB to be desirable if it is substantially
equal to and/or less than the .DELTA.T.sub.BL-WOB. However,
additional or alternative factors may also play a role in the
determination made during step 748.
[0242] During step 752 of the method 700c, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by increasing the
WOB. Because the baseline .DELTA.T determined in step 752 will be
utilized for optimization by increasing WOB, the convention
.DELTA.T.sub.BL+WOB will be used herein.
[0243] In a subsequent step 754, the WOB is increased. The increase
of WOB during step 754 may be within certain, predefined WOB
limits. For example, the WOB increase may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined WOB limits. The WOB may be manually increased
via operator input, or the WOB may be automatically increased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0244] Thereafter, during a step 756, drilling continues with, the
increased WOB during a predetermined drilling interval +.DELTA.WOB.
The +.DELTA.WOB interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the +.DELTA.WOB interval may be a
predetermined drilling progress depth. For example, step 756 may
include continuing drilling operation with the increased WOB until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The +.DELTA.WOB interval may also include both
a time and a depth component. For example, the +.DELTA.WOB interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the +.DELTA.WOB
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0245] After continuing drilling operation through the +.DELTA.WOB
interval with the increased WOB, a step 758 is performed to
determine the .DELTA.T.sub.+WOB resulting from operating with the
increased WOB during the +.DELTA.WOB interval. In a subsequent
decisional step 760, the changed .DELTA.T.sub.+.DELTA.WOB is
compared to the baseline .DELTA.T.sub.BL+WOB. If the changed
.DELTA.T.sub.+.DELTA.WOB is desirable relative to the
.DELTA.T.sub.BL+WOB, the method 700c continues to a step 764.
However, if the changed .DELTA.T.sub.+.DELTA.WOB is not desirable
relative to the .DELTA.T.sub.BL+WOB, the method 700c continues to a
step 762 where the WOB is restored to its value before step 754 was
performed, and the method then continues to step 764.
[0246] The determination made during decisional step 760 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub.+.DELTA.WOB to be desirable if it is substantially
equal to and/or less than the .DELTA.T.sub.BL+WOB. However,
additional or alternative factors may also play a role in the
determination made during step 760.
[0247] During step 764 of the method 700c, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by decreasing the bit
rotational speed, RPM. Because the baseline .DELTA.T determined in
step 764 will be utilized for optimization by decreasing RPM, the
convention .DELTA.T.sub.BL-RPM will be used herein.
[0248] In a subsequent step 766, the RPM is decreased. The decrease
of RPM during step 766 may be within certain, predefined RPM
limits. For example, the RPM decrease may be no greater than about
10%. However, other percentages arc also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined RPM limits. The RPM may be manually decreased
via operator input, or the RPM may be automatically decreased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0249] Thereafter, during, a step 768, drilling continues with the
decreased RPM during a predetermined drilling interval -.DELTA.RPM.
The -.DELTA.RPM interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the -.DELTA.RPM interval may be a
predetermined drilling progress depth. For example, step 768 may
include continuing drilling operation with the decreased RPM until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The -.DELTA.RPM interval may also include both
a time and a depth component. For example, the -.DELTA.RPM interval
may include drilling for at least thirty minutes or until the
wellbore is extended ten feet. In another example, the -.DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0250] After continuing drilling operation through the -.DELTA.RPM
interval with the decreased RPM, a step 770 is performed to
determine the .DELTA.T.sub.-.DELTA.RPM resulting from operating
with the decreased RPM during the -.DELTA.RPM interval. In a
subsequent decisional step 772, the decreased
.DELTA.T.sub.-.DELTA.RPM is compared to the baseline
.DELTA.T.sub.BL-RPM. If the changed .DELTA.T.sub.-.DELTA.RPM is
desirable relative to the .DELTA.T.sub.BL-RPM, the method 700c
continues to a step 776. However, if the changed
.DELTA.T.sub..DELTA.RPM is not desirable relative to the
.DELTA.T.sub.BL-RPM, the method 700c continues to a step 774 where
the RPM is restored to its value before step 766 was performed, and
the method then continues to step 776.
[0251] The determination made during decisional step 772 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub.-.DELTA.RPM to be desirable if it is substantially
equal to and/or less than the .DELTA.T.sub.BL-RPM. However,
additional or alternative factors may also play a role in the
determination made during step 772.
[0252] During step 776 of the method 700c, a baseline .DELTA.T is
determined for optimization based on .DELTA.T by increasing the bit
rotational speed, RPM. Because the baseline .DELTA.T determined in
step 776 will be utilized for optimization by increasing RPM, the
convention .DELTA.T.sub.BL+RPM will be used herein.
[0253] In a subsequent step 778, the RPM is increased. The increase
of RPM during step 778 may be within certain, predefined RPM
limits. For example, the RPM increase may be no greater than about
10%. However, other percentages are also within the scope of the
present disclosure, including where such percentages are within or
beyond the predefined RPM limits. The RPM may be manually increased
via operator input, or the RPM may be automatically increased via
signals transmitted by a controller, control system, and/or other
component of the drilling rig and associated apparatus.
[0254] Thereafter, during a step 780, drilling continues with the
increased RPM during a predetermined drilling interval +.DELTA.RPM.
The +.DELTA.RPM interval may be a predetermined time period, such
as five minutes, ten minutes, thirty minutes, or some other
duration. Alternatively, the +.DELTA.RPM interval may be a
predetermined drilling progress depth. For example, step 780 may
include continuing drilling operation with the increased RPM until
the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth. The +.DELTA.RPM interval may also include both
a time and a depth component. For example, the +.DELTA.RPM interval
may include drilling for at least thirty minutes or-until the
wellbore is extended ten feet. In another example, the +.DELTA.RPM
interval may include drilling until the wellbore is extended twenty
feet, but no longer than ninety minutes.
[0255] After continuing drilling operation through the +.DELTA.RPM
interval with the increased RPM, a step 782 is performed to
determine the .DELTA.T.sub.+.DELTA.RPM resulting from operating
with the increased RPM during the +.DELTA.RPM interval. In a
subsequent decisional step 784, the increased
.DELTA.T.sub.+.DELTA.RPM is compared to the baseline
.DELTA.T.sub.BL+RPM. If the changed .DELTA.T.sub..DELTA.RPM is
desirable relative to the .DELTA.T.sub.BL+RPM, the method 700c
continues to a step 788. However, if the changed
.DELTA.T.sub.+.DELTA.RPM is not desirable relative to the
.DELTA.T.sub.BL+RPM, the method 700c continues to a step 786 where
the RPM is restored to its value before step 778 was performed, and
the method then continues to step 788.
[0256] The determination made during decisional step 784 may be
performed manually or automatically by a controller, control
system, and/or other component of the drilling rig and associated
apparatus. The determination may include finding the
.DELTA.T.sub.+RPM to be desirable if it is substantially equal to
and/or less than the .DELTA.T.sub.BL+RPM. However, additional or
alternative factors may also play a role in the determination made
during step 784.
[0257] Step 788 includes awaiting a predetermined time period or
drilling depth interval before reiterating the method 700c by
returning to step 740. However, in an exemplary embodiment, the
interval may be as small as 0 seconds or 0 feet, such that the
method returns to step 740 substantially immediately after
performing steps 784 and/or 786. Alternatively, the method 700c may
not require iteration, such that the method 700c may substantially
end after the performance of steps 784 and/or 786.
[0258] Moreover, the drilling intervals -.DELTA.WOB, +.DELTA.WOB,
-.DELTA.RPM and +.DELTA.ROM may each be substantially identical
within a single iteration of the method 700c. Alternatively, one or
more of the interval s may vary in duration or depth relative to
the other intervals. Similarly, the amount that the WOB is
decreased and increased in steps 742 and 754 may be substantially
identical or may vary relative to each other within a single
iteration of the method 700c. The amount that the RPM is decreased
and increased in steps 766 and 778 may be substantially identical
or may vary relative to each other within a single iteration of the
method 700c. The WOB and RPM variances may also change or stay the
same relative to subsequent iterations of the method 700c.
[0259] Referring to FIG. 8A, illustrated is a schematic view of
apparatus 800 according to one or more aspects of the present
disclosure. The apparatus 800 may include or compose at least a
portion of the apparatus 100 shown in FIG. 1, the apparatus 300
shown in FIG. 3, the apparatus 400a shown in FIG. 4A, the apparatus
400b shown in FIG. 4B, the apparatus 400c in FIG. 4C, and/or the
apparatus 690 shown in FIG. 6B. The apparatus 800 represents an
exemplary embodiment in which one or more methods within the scope
of the present disclosure may be performed or otherwise
implemented, including the method 200a shown in FIG. 2A, the method
200b shown in FIG. 2B, the method 500 in FIG. 5A, the method 600a
shown in FIG. 6A, the method 600b shown in FIG. 6C, the method 600c
shown in FIG. 6D, the method 700a shown in FIG. 7A, the method 700b
shown in FIG. 7B, and/or the method 700c shown in FIG. 7C.
[0260] The apparatus 800 includes a plurality of manual or
automated data inputs, collectively referred to herein as inputs
802. The apparatus also includes a plurality of controllers,
calculators, detectors, and other processors, collectively referred
to herein as processors 804. Data from the various ones of the
inputs 802 is transmitted to various ones of the processors 804, as
indicated in FIG. 8A by the arrow 803. The apparatus 800 also
includes a plurality of sensors, encoders, actuators, drives,
motors, and other sensing, measurement, and actuation devices,
collectively referred to herein as devices 808. Various data and
signals, collectively referred to herein as data 806, are
transmitted between various ones of the processors 804 and various
ones of the devices 808, as indicated in FIG. 8A by the arrows
805.
[0261] The apparatus 800 may also include, be connected to, or
otherwise be associated with, a display 810, which may be driven by
or otherwise receive data from one or more of the processors 804,
if not also from other components of the apparatus 800. The display
810 may also be referred to herein as a human-machine interface
(HMI), although such HMI may further include one or more of the
inputs 802 and/or processors 804.
[0262] In the exemplary embodiment shown in FIG. 8A, the Inputs 802
include means for providing the following set points, limits,
ranges, and other data: [0263] bottom hole pressure input 802a;
[0264] choke position reference input 802b: [0265] .DELTA.P limit
input 802c; [0266] .DELTA.P reference input 802d; [0267] drawworks
pull limit input 802e; [0268] MSE limit input 802f; [0269] MSE
target input 802g: [0270] mud flow set point input 802h; [0271]
pump pressure tare input 802i: [0272] quill negative amplitude
input 802j; [0273] quill positive amplitude input 802k; [0274] ROP
set point input 802l; [0275] pump input 802m; [0276] toolface
position input 802n; [0277] top drive RPM input 802o; [0278] top
drive torque limit input 802p; [0279] WOB reference input 802q; and
[0280] WOB tare input 802r. However, the inputs 802 may include
means for providing additional or alternative set points, limits,
ranges, and other data within, the scope of the present
disclosure.
[0281] The bottom hole pressure input 802a may indicate a value of
the maximum desired pressure of the gaseous and/or other
environment at the bottom end of the wellbore. Alternatively, the
bottom hole pressure input 802a may indicate a range within which
it is desired that the pressure at the bottom of the wellbore be
maintained. Such pressure may be expressed as an absolute pressure
or a gauge pressure (e.g., relative to atmospheric pressure or some
other predetermined pressure).
[0282] The choke position reference input 802b may be a set point
or value indicating the desired choke position. Alternatively, the
choke position reference input 802b may indicate a range within
which it is desired that the choke position be maintained. The
choke may be a device having an orifice or other means configured
to control fluid flow rate and/or pressure. The choke may be
positioned at the end of a choke line, which is a high-pressure
pipe leading from an outlet on the BOP stack, whereby the fluid
under pressure in the wellbore can flow out of the well through the
choke line to the choke, thereby reducing the fluid pressure (e.g.,
to atmospheric pressure). The choke position reference input 802b
may be a binary indicator expressing the choke position as either
"opened" or "closed." Alternatively, the choke position reference
input 802b may be expressed as a percentage indicating the extent
to which the choke is partially opened or closed.
[0283] The .DELTA.P limit input 802c may be a value indicating the
maximum or minimum pressure drop across the mud motor.
Alternatively, the .DELTA.P limit input 802c may indicate a range
within which it is desired that the pressure drop across the mud
motor be maintained. The .DELTA.P reference input 802d may be a set
point or value indicating the desired pressure drop across the mud
motor. In an exemplary embodiment, the .DELTA.P limit input 802c is
a value indicating the maximum desired pressure drop across the mud
motor, and the .DELTA.P reference input 802d is a value indicating
the nominal desired pressure drop across the mud motor.
[0284] The drawworks pull limit input 802e may be a value
indicating the maximum force to be applied to the drawworks by the
drilling line (e.g., when supporting the drill string off-bottom or
pulling on equipment stuck in the wellbore). For example, the
drawworks pull limit input 802e may indicate the maximum hook load
that should be supported by the drawworks during operation. The
drawworks pull limit input 802e may be expressed as the maximum
weight or drilling line tension that can be supported by the
drawworks without damaging the drawworks, drilling line, and/or
other equipment.
[0285] The MSE limit input 802f may be a value indicating the
maximum or minimum MSE desired during drilling. Alternatively, the
MSE limit input 802f max be a range within which it is desired that
the MSE be maintained during drilling. As discussed above, the
actual value of the MSE is at least partially dependent upon WOB,
bit diameter, bit speed, drill string torque, and ROP, each of
which may be adjusted according to aspects of the present
disclosure to maintain the desired MSE. The MSE target input 802g
may be a value indicating the desired MSE, or a range within which
it is desired that the MSE be maintained during drilling. In an
exemplary embodiment, the MSE limit input 802f is a value or range
indicating the maximum and/or minimum MSE, and the MSE target input
802g is a value indicating the desired nominal MSE.
[0286] The mud flow set point input 802h may be a value indicating
the maximum, minimum, or nominal desired mud flow rate output by
the mud pump. Alternatively, the mud flow set point input 802h may
be a range within which it is desired that the mud flow rate be
maintained. The pump pressure tare input 802i may be a value
indicating the current, desired, initial, surveyed, or other mud
pump pressure tare. The mud pump pressure tare generally accounts
for the difference between the mud pressure and the casing or
wellbore pressure when the drill string is off bottom.
[0287] The quill negative amplitude input 802j may be a value
indicating the maximum desired quill rotation from the quill
oscillation neutral point in a first angular direction, whereas the
quill positive amplitude input 802k may be a value indicating the
maximum desired quill rotation from the quill oscillation neutral
point in an opposite angular direction. For example, during
operation of the top drive to oscillate the quill, the quill
negative amplitude input 802j may indicate the maximum desired
clockwise rotation of the quill past the oscillation neutral point,
and the quill positive amplitude input 802k may indicate the
maximum desired counterclockwise rotation of the quill past the
oscillation neutral point.
[0288] The ROP set point input 802l may be a value indicating the
maximum, minimum, or nominal desired ROP. Alternatively, the ROP
set point input 802l may be range within which if is desired that
the ROP be maintained.
[0289] The pump input 802m may be a value indicating a maximum,
minimum, or nominal desired flow rate, power, speed (e.g.,
strokes-per-minute), and/or other operating parameter related to
operation of the mud pump. For example, the mud pump may actually
include more than one pump, and the pump input 802m may indicate a
desired maximum or nominal aggregate pressure, flow rate, or other
parameter of the output of the multiple mud pumps, or whether a
pump system is operating in conjunction with the multiple mud
pumps.
[0290] The toolface position input 802n may be a value indicating
the desired orientation of the toolface. Alternatively, the
toolface position input 802n may be a range within which it is
desired that the toolface be maintained. The toolface position
input 802n may be expressed as one or more angles relative to a
fixed or predetermined reference. For example, the toolface
position input 802n may represent the desired toolface azimuth
orientation relative to true North and/or the desired toolface
inclination relative to vertical. As discussed above, in some
embodiments, this is input directly, or may be based upon a planned
drilling path. While drilling using the method in FIG. 5A, the
toolface orientation may be calculated based upon other data, such
as survey data or trend data and the amount of deviation from a
planned drilling path. This may be a value considered in order to
steer the BHA along a modified drilling path.
[0291] The top drive RPM input 802o may be a value indicating a
maximum, minimum, or nominal desired rotational speed of the top
drive. Alternatively, the top drive RPM input 802o may be a range
within which it is desired that the top drive rotational speed be
maintained. The top drive torque limit input 802p may be a value
indicating a maximum torque to be applied by the top drive.
[0292] The WOB reference input 802q may be a value indicating a
maximum, minimum, or nominal desired WOB resulting from the weight
of the drill string acting on the drill bit, although perhaps also
taking into account other forces affecting WOB, such as friction
between the drill string an the wellbore. Alternatively, the WOB
reference input 802q may be a range in which it is desired that the
WOB be maintained. The WOB tare input 802r may be a value
indicating the current, desired, initial, survey, or other WOB
tare, which lakes into account the hook load and drill string
weight when off bottom.
[0293] One or more of the inputs 802 may include a keypad,
voice-recognition apparatus, dial, joystick, mouse, data base
and/or other conventional or future-developed data input device.
One or more of the inputs 802 may support data input from local
and/or remote locations. One or more of the inputs 802 may include
means for user-selection of predetermined set points, values, or
ranges, such as via one or more drop-down menus. One or more of the
inputs 802 may also or alternatively be configured to enable
automated input by one or more of the processors 804, such as via
the execution of one or more database look-up procedures. One or
more of the inputs 802, possibly in conjunction with other
components of the apparatus 800, may support operation and/or
monitoring from stations on the rig site as well as one or more
remote locations. Each of the inputs 802 may have individual means
for input, although two or more of the inputs 802 may collectively
have a single means for input. One or more of the inputs 802 may be
configured to allow human input, although one or more of the inputs
802 may alternatively be configured for the automatic input of data
by computer, software, module, routine, database lookup, algorithm,
calculation, and/or otherwise. One or more of the inputs 802 may be
configured for such automatic input of data but with an override
function by which a human operator may approve or adjust the
automatically provided data.
[0294] In the exemplary embodiment shown in FIG. 8A, the devices
808 include: [0295] a block position sensor 808a; [0296] a casing
pressure sensor 808b; [0297] a choke position sensor 808c; [0298] a
dead-line anchor load sensor 808d; [0299] a drawworks encoder 808e;
[0300] a mud pressure sensor 808f; [0301] an MWD toolface gravity
sensor 808g; [0302] an MWD toolface magnetic sensor 808h; [0303] a
return line flow sensor 808i; [0304] a return line mud weight
sensor 808j; [0305] a top drive encoder 808k; [0306] a top drive
torque sensor 808l; [0307] a choke actuator 808m; [0308] a
drawworks drive 808n; [0309] a drawworks motor 808o; [0310] a mud
pump drive 808p; [0311] a top drive drive 808q; and [0312] a top
drive motor 808r, However, the devices 808 may include additional
or alternative devices within the scope of the present disclosure.
The devices 808 are configured for operation in conjunction with
corresponding ones of a drawworks, a choke, a mud pump, a top
drive, a block, a drill string, and/or other components of the rig.
Alternatively, the devices 808 also include one or more of these
other rig components.
[0313] The block position sensor 808a may be or include an optical
sensor, a radio-frequency sensor, an optical or other encoder, or
another type of sensor configured to sense the relative or absolute
vertical position of the block. The block position sensor 808a may
be coupled to or integral with the block, the crown, the drawworks,
and/or another component of the apparatus 800 or rig,
[0314] The casing pressure sensor 808b is configured to detect the
pressure in the annulus defined between the drill string and the
casing or wellbore, and may be or include one or more transducers,
strain gauges, and/or other devices for detecting pressure changes
or otherwise sensing pressure. The casing pressure sensor 808b may
be coupled to the casing, drill string. and/or another component of
the apparatus 800 or rig, and may be positioned at or near the
wellbore surface, slightly below the surface, or significantly
deeper in the wellbore.
[0315] The choke position sensor 808c is configured to detect
whether the choke is opened or closed, and may be further
configured to detect the degree to which the choke is partially
opened or closed. The choke position sensor 808c may be coupled to
or integral with the choke, the choke actuator, and/or another
component of the apparatus 800 or rig. The choke may alternatively
maintain a set pressure or steady mass flow, e.g., based on a
casing pressure. This can be measured with an optional mass flow
meter 808s.
[0316] The dead-line anchor load sensor 808d is configured to
detect the tension in the drilling line at or near the anchored
end. It may include one or more transducers, strain gauges, and/or
other sensors coupled to the drilling line.
[0317] The drawworks encoder 808e is configured to detect the
rotational position of the drawworks spools around which the
drilling line is wound. It may include one or more optical
encoders, interferometers, and/or other sensors configured to
detect the angular position of the spool and/or any change in the
angular position of the spool. The drawworks encoder 808e may
include one or more components coupled to or integral with the
spool and/or a stationary portion of the drawworks.
[0318] The mud pressure sensor 808f is configured to detect the
pressure of the hydraulic fluid output by the mud motor, and may be
or include one or more transducers, strain gauges, and/or other
devices for detecting fluid pressure. It may be coupled to or
integral with, the mud pump, and thus positioned at or near the
surface opening of the well bore.
[0319] The MWD toolface gravity sensor 808g is configured to detect
the toolface orientation based on gravity. The MWD toolface
magnetic sensor 808h is configured to detect the toolface
orientation based on magnetic field. These sensors 808g and 808h
may be coupled to or integral with the MWD assembly, and are thus
positioned downhole.
[0320] The return line flow sensor 808i is configured to detect the
flow rate of mud within the return line, and may be expressed in
gallons/minute. The return line mud weight sensor 808j is
configured to detect the weight of the mud flowing within the
return line. These sensors 808l and 808j may be coupled to the
return flow line, and may thus be positioned at or near the surface
opening of the wellbore.
[0321] The top drive encoder 808k is configured to detect the
rotational position of the quill. It may include one or more
optical encoders, interferometers, and/or other sensors configured
to detect the angular position of the quill, and/or any change in
the angular position of the quill, relative to the top drive, true
North, or some other fixed reference point. The top drive torque
sensor 808l is configured to detect the torque being applied by the
top drive, or the torque necessary to rotate the quill or drill
string at the current rate. These sensors 808k and 808l may be
coupled to or integral with the top drive.
[0322] The choke actuator 808m is configured to actuate the choke
to configure the choke in an opened configuration, a closed
configured, and/or one or more positions between fully opened and
fully closed. It may be hydraulic, pneumatic, mechanical,
electrical, or combinations thereof.
[0323] The drawworks drive 808n is configured to provide an
electrical signal to the drawworks motor 808o for actuation
thereof. The drawworks motor 808o is configured to rotate the spool
around which the drilling line is wound, thereby feeding the
drilling line in or out.
[0324] The mud pump drive 808p is configured to provide an
electrical signal to the mud pump, thereby controlling the flow
rate and/or pressure of the mud pump output. The top drive drive
808q is configured to provide an electrical signal to the top drive
motor 808r for actuation thereof. The top drive motor 808r is
configured to rotate the quill, thereby rotating the drill string
coupled to the quill.
[0325] The devices 808 may (things applicable to most of the
sensors)
[0326] In the exemplary embodiment shown in FIG. 8A, the data 806
which is transmitted between the devices 808 and the processors 804
includes: [0327] block position 806a; [0328] casing pressure 806b;
[0329] choke position 806c; [0330] hook load 806d; [0331] mud
pressure 806e; [0332] mud pump stroke/phase 806f; [0333] mud weight
806g; [0334] quill position 806h; [0335] return flow 806i; [0336]
toolface 806j; [0337] top drive torque 806k: [0338] choke actuation
signal 806l; [0339] drawworks actuation signal 806m; [0340] mud
pump actuation signal 806n; [0341] top drive actuation signal 806o;
and [0342] top drive torque limit signal 806p. However, the data
806 transferred between the devices 808 and the processors 804 may
include additional or alternative data within the scope of the
present disclosure.
[0343] In the exemplary embodiment shown in FIG. 8A, the processors
804 include: [0344] a choke controller 804a; [0345] a drum
controller 804b; [0346] a mud pump controller 804c: [0347] an
oscillation controller 804d; [0348] a quill position controller
804e: [0349] a toolface controller 804f: [0350] a d-exponent
calculator 804g; [0351] a d-exponent-corrected calculator 804h;
[0352] an MSE calculator 804i; [0353] an ROP calculator 804l;
[0354] a true depth calculator 804m; [0355] a WOB calculator 804n;
[0356] a stick/slip detector 804o; and [0357] a survey log 804p.
However, the processors 804 may include additional or alternative
controllers, calculators, detectors, data storage, and/or other
processors within the scope of the present disclosure.
[0358] The choke controller 804a is configured to receive the
bottom hole pressure setting from the bottom hole pressure input
802a, the casing pressure 806b from the casing pressure sensor
808b, the choke position 806c from the choke position sensor 808c,
and the mud weight 806g from the return line mud weight sensor
808j. The choke controller 804a may also receive bottom hole
pressure data, from the pressure calculator 804k. Alternatively,
the processors 804 may include a comparator, summing, or other
device which performs an algorithm utilizing the bottom hole
pressure setting received from the bottom hole pressure input 802a
and the current bottom hole pressure received from the pressure
calculator 804k, with the result of such algorithm being provided
to the choke controller 804a in lieu of or in addition to the
bottom hole pressure setting and/or the current bottom hole
pressure. The choke controller 804a is configured to process the
received data and generate the choke actuation signal 806l, which
is then transmitted to the choke actuator 808.
[0359] For example, if the current bottom hole pressure is greater
than the bottom hole pressure setting, then the choke actuation
signal 806l may direct the choke actuator 808m to further open,
thereby increasing the return flow rate and decreasing the current
bottom hole pressure. Similarly, if the current bottom hole
pressure is less than the bottom hole pressure setting, then the
choke actuation signal 806l may direct the choke actuator 808m to
further close, thereby decreasing the return flow rate and
increasing the current bottom hole pressure. Actuation of the choke
actuator 808m may be incremental, such that the choke actuation
signal 806l repeatedly directs the choke actuator 808m to further
open or close by a predetermined amount until the current bottom
hole pressure satisfactorily complies with the bottom hole pressure
setting. Alternatively, the choke actuation signal 806l may direct
the choke actuator 808m to further open or close by an amount
proportional to the current discord between the current bottom hole
pressure and the bottom hole pressure setting.
[0360] The drum controller 804b is configured to receive the ROP
set point from the ROP set point input 802l, as well as the current
ROP from the ROP calculator 804l. The drum controller 804b is also
configured to receive WOB data from a comparator, summing, or other
device which performs an algorithm utilizing the WOB reference
point from the WOB reference input 802g and the current WOB from
the WOB calculator 804n. This WOB data may be modified based
current MSE data. Alternatively, the drum controller 804b is
configured to receive the WOB reference point from the WOB
reference input 802g and the current WOB from the WOB calculator
804n directly, and then perform the WOB comparison or summing
algorithm itself. The drum controller 804b is also configured, to
receive .DELTA.P data from a comparator, summing, or other device
which performs an algorithm utilizing the .DELTA.P reference
received from the .DELTA.P reference input 802d and a current
.DELTA.P received from one of the processors 804 that is configured
to determine the current .DELTA.P. The current .DELTA.P may be
corrected to take account the casing pressure 806b.
[0361] The drum controller 804b is configured to process the
received data and generate the drawworks actuation signal 806m,
which is then transmitted to the drawworks drive 808n. For example,
if the current WOB received from the WOB calculator 804n is less
than the WOB reference point received from the WOB reference input
802q, then the drawworks actuation signal 806m may direct the
drawworks drive 808n to cause the drawworks motor 808o to feed out
more drilling line. If the current WOB is less than the WOB
reference point, then the drawworks actuation signal 806m may
direct the drawworks drive 808n to cause the drawworks motor 808o
to feed in the drilling line.
[0362] If the current ROP received from the ROP calculator 804l is
less than the ROP set point received from the ROP set point input
802l, then the drawworks actuation signal 806m may direct the
drawworks drive 808n to cause the drawworks motor 808o to feed out
more drilling line. If the current ROP is greater than the ROP set
point, then the drawworks actuation signal 806m may direct the
drawworks drive 808n to cause the drawworks motor 808o to feed in
the drilling line.
[0363] If the current .DELTA.P is less than the .DELTA.P reference
received from the .DELTA.P reference input 802d, then the drawworks
actuation signal 806m may direct the drawworks drive 808n to cause
the drawworks motor 808o to feed out more drilling line. If the
current .DELTA.P is greater than the .DELTA.P reference, then the
drawworks actuation signal 806m may direct the drawworks drive 808n
to cause the drawworks motor 808o to feed in the drilling line.
[0364] The mud pump controller 804c is configured to receive the
mud pump stroke/phase data 806f, the mud pressure 806e from the mud
pressure sensor 808f, the current .DELTA.P, the current MSE from
the MSE calculator 804i, the current ROP from the ROP calculator
804l, a stick/slip indicator from the stick/slip detector 804o, the
mud flow rate set point from the mud flow set point input 802h, and
the pump data from the pump input 802m. The mud pump controller
804c then utilizes this data to generate the mud pump actuation
signal 806n, which is then transmitted to the mud pump 808p.
[0365] The oscillation controller 804d is configured to receive the
current quill position 806h, the current top drive torque 806k, the
stick/slip indicator from the stick/slip detector 804o, the current
ROP from the ROP calculator 804l, and the quill oscillation
amplitude limits from the inputs 802j and 802k. The oscillation
controller 804d then utilizes this data to generate an input to the
quill position controller 804e for use in generating the top drive
actuation signal 806o. For example, if the stick/slip indicator
from the stick/slip detector 804o indicates that stick/slip is
occurring, then the signal generated by the oscillation controller
804d will indicate that oscillation needs to commence or increase
in amplitude.
[0366] The quill position controller 804e is configured to receive
the signal from the oscillation controller 804d, the top drive RPM
setting from the top drive RPM input 802o, a signal from the
toolface controller 804f, the current WOB from the WOB calculator
804n, and the current toolface 806j from at least one of the MWD
toolface sensors 808g and 808h. The quill position controller 804e
may also be configured to receive the top drive torque limit
setting from the top drive torque limit input 802p, although this
setting may be adjusted by a comparator, summing, or other device
to account for the current MSE, where the current MSE is received
from the MSE calculator 804i. The quill position controller 804e
may also be configured to receive a stick/slip indicator from the
stick/slip detector 804o. The quill position controller 804e then
utilizes this data to generate the top drive actuation signal
806o.
[0367] For example, the top drive actuation signal 806o causes the
top drive drive 808q to cause the top drive motor 808r to rotate
the quill at the speed indicated by top drive RPM input 802o.
However, this may only occur when other inputs aren't overriding
this objective. For example, if so directed by the signal from the
oscillation controller 804d, the top drive actuation signal 806o
will also cause the top drive drive 808q to cause the top drive
motor 808r to rotationally oscillate the quill. Additionally, the
signal from the toolface controller 804d may override or otherwise
influence the top drive actuation signal 806o to rotationally
orient the quill at a certain static position or set a neutral
point for oscillation.
[0368] The toolface controller 804f is configured to receive the
toolface position setting from the toolface position input 802n, as
well as the current toolface 806j from at least one of the MWD
toolface sensors 808g and 808h. The toolface controller 804f may
also be configured to receive .DELTA.P data. The toolface
controller 804f then utilizes this data to generate a signal which
is provided to the quill position controller 804e.
[0369] The d-exponent calculator 804g is configured to receive the
current. ROP from the ROP calculator 804l, the current .DELTA.P
and/or other pressure data, the bit diameter, the current WOB from
the WOB calculator 804n, and the current mud weight 806g from the
return line mud weight sensor 808j. The d-exponent calculator 804g
then utilizes this data to calculate the d-exponent, which is a
factor for evaluating ROP and detecting or predicting abnormal pore
pressure zones. Assuming all other parameters are constant, the
d-exponent should increase with depth when drilling in a normal
pressure section, whereas a reversal of this trend is an indication
of drilling into potential overpressures. The signal from the
d-exponent calculator 804g is optionally provided to the display
810, as well as to the toolface calculation engine 404.
Consequently, the steering module 420 can cease drilling or adjust
the planned path by treating an area causing increased values from
the d-exponent calculator 804g as a deviation from the planned path
outside the tolerance zone. This can advantageously automatically
direct the main controller to drill in a different direction to
avoid drilling into the potential overpressure area. The d-exponent
calculator is simply another suitable method, or algorithm, for
analyzing ROP and is another calculation that can be accomplished
similar to that for MSE.
[0370] The d-exponent-corrected calculator 804h may be configured
to receive substantially the same data as received by the
d-exponent calculator 804g. Alternatively, the d-exponent-corrected
calculator 804h is configured to receive the current d-exponent as
calculated by the d-exponent calculator 804g. The
d-exponent-corrected calculator 804h then utilizes this data to
calculate the collected d-exponent, which corrects the d-exponent
value for mud weight and which can be related directly to formation
pressure rather than to differential pressure. The signal from the
d-exponent calculator 804g is provided, e.g., to the display
810.
[0371] The MSE calculator 804i is configured to receive current RPM
data from the top drive RPM input 802o, the top drive torque 806k
from the top drive torque sensor 808l, and the current WOB from the
WOB calculator 804n. The MSE calculator 804i then utilizes this
data to calculate the current MSE, which is then transmitted to the
drum controller 804b, the quill position controller 804e, and the
mud pump controller 804c. The MSE calculator 804i may also be
configured to receive the MSE limit setting from the MSE limit
input 802f, in which case the MSE calculator 804i may also be
configured to compare the current MSE to the MSE limit setting and
trigger an alert if the current MSE exceeds the MSE limit setting.
The MSE calculator 804i may also be configured to receive the MSE
target setting from the MSE target input 802g, in which case the
MSE calculator 804i may also be configured to generate a signal
indicating the difference between the current MSE and the MSE
target. This signal may be utilized by one or more of the
processors 804 to correct adjust various data values utilized
thereby, such as the adjustment to the current or reference WOB
utilized by the drum controller 804b, and/or the top drive torque
limit setting utilized by the quill position controller 804e, as
described above.
[0372] The pressure calculator 804k is configured to receive the
casing pressure 806b from the casing pressure sensor 808b, the mud
pressure 806e from the mud pressure sensor 808f, the mud weight
806g from the return line mud weight sensor 808j, and the true
vertical depth from the true depth calculator 804m. The pressure
calculator 804k then utilizes this data to calculate the current
bottom hole pressure, which is then transmitted to choke controller
804a. However, before being sent to the choke controller 804a, the
current bottom hole pressure may be compared to the bottom hole
pressure setting received from the bottom hole pressure input 802a,
in which case the choke controller 804a may utilize only the
difference between the current bottom home pressure and the bottom
hole pressure setting when generating the choke actuation signal
806l. This comparison between the current bottom hole pressure and
the bottom hole pressure setting may be performed by the pressure
calculator 804k, the choke controller 804a, or another one of the
processors 804.
[0373] The ROP calculator 804l is configured to receive the block
position 806a from the block position 808a and then utilize this
data to calculate the current ROP. The current ROP is then
transmitted to the true depth calculator 804m, the drum controller
804b, the mud pump controller 804c, and the oscillation controller
804d.
[0374] The true depth calculator 804m is configured to receive the
current toolface 806j from at least one of the MWD toolface sensors
808g and 808h, the survey log 804p, and the current measured depth
that is calculated from the current ROP received from the ROP
calculator 804l. The true depth calculator 804m then utilizes this
data to calculate the true vertical depth, which is then
transmitted to the pressure calculator 804k.
[0375] The WOB calculator 804n is configured to receive the
stick/slip indicator from the stick/slip detector 804o, as well as
the current hook load 806d from the dead-line anchor load sensor
808d. The WOB calculator 804n may also be configured to receive an
off-bottom string weight tare, which may be the difference between
the WOB tare received from the WOB tare input 802r and the current
hook load 806d received from the dead-line anchor load sensor 808d.
In any case, the WOB calculator 804n is configured to calculate the
current WOB based on the current hook load, the current string
weight, and the stick-slip indicator. The current WOB is then
transmitted to the quill position controller 804e, the d-exponent
calculator 804g, the d-exponent-corrected calculator 804h, the MSE
calculator 804i, and the drum controller 804b.
[0376] The stick/slip detector 804o is configured to receive the
current top drive torque 806k and utilize this data to generate the
stick/slip indicator, which is then provided to the mud pump
controller 804c, the oscillation controller 804d, and the quill
position controller 804e. The stick/slip detector 804o measures
changes in the top drive torque 806k relative to time, which is
indicative of whether the bit may be exhibiting stick/slip
behavior, indicating that the top drive torque and/or WOB should be
reduced or the quill oscillation amplitude should be modified.
[0377] The processors 804 may be collectively implemented as a
single processing device, or as a plurality of processing devices.
Each processor 804 may include one or more software or other
program, product modules, sub-modules, routines, sub-routines,
state machines, algorithms. Each processor 804 may additional
include one or more computer memories or other means for digital
data storage. Aspects of one or more of the processors 804 may be
substantially similar to those described herein with reference to
any controller or other data processing apparatus. Accordingly, the
processors 804 may include or be composed of at least a portion of
controller 190 in FIG. 1, the controller 325 in FIG. 3, the
controller 420 in FIGS. 4A-C, and the controller 698 in FIG. 6B,
for example.
[0378] FIG. 8B illustrates a system control module 812 according to
one or more aspects of the present disclosure. The system control
module 812 is one possible implementation of the apparatus 800
shown in FIG. 8A, and may be utilized in conjunction with or
implemented within the apparatus 100 shown in FIG. 1, and any of
the apparatuses 300, 400a, 400b. 400c, and 790 shown respectively
in FIGS. 3, 4A-C, and 7B. The system control module 812 may also be
utilized to perform one or more aspects of the methods shown in any
of FIGS. 2A, 2B, 5A, 6A, 6C, 7A, 7B, and 7C.
[0379] The system control module 812 includes an HMI module 814, a
data transmission module 816, and a master drilling control module
818. The HMI module 814 includes a manual data input module 814a
and a display module 814b. The master drilling control module 818
includes a sensed data, module 818a, a control signal transmission
module 818b, a BHA control module 818c, a drawworks control module
420b, a top drive control module 420a, a mud pump control module
420f, an ROP optimization module 818g, a bit life optimization
module 818h, an MSE-based optimization module 818i, a
d-exponent-based optimization module 818j, a
d-exponent-corrected-based optimization module 818k, and a BHA
optimization module 818m.
[0380] The manual data input module 814a is configured to
facilitate user-input of various set points, operating ranges,
formation conditions, equipment parameters, and/or other data,
including a drilling plan or data for determining a drilling plan.
For example, the manual data input module 814a may enable the
inputs 802 shown in FIG. 8A, among others. Such data may be
received by the manual data input module 814a via the data
transmission module 816, which may include or support one or more
connectors, ports, and/or other means for receiving data from
various data input devices. The display module 814b is configured
to provide an indication that the user has successfully entered
some or all of the input facilitated by the manual data input
module 814a. Such indication may be include a visual indication of
some type, such as via the display of text or graphic icons or
other information, the illumination of one or more lights or LEDs,
or the change in color of a light, LED, graphic icon or symbol,
among others.
[0381] The master drilling control module 818 is configured to
receive data input by the user from the HMI module 814, which in
some embodiments is communicated via the data transmission module
816 as in the exemplary embodiment depicted in FIG. 8B.
[0382] The sensed data module 818a of the master drilling control
module 818 also receives sensed or detected data from various
sensors, detectors, encoders, and other such devices associated
with the various equipment and components of the rig. Examples of
such sensing and information obtaining devices include the devices
430 in FIG. 4A and 806 in FIG. 8A among other figures included
herein. This sensed data may also be received by the sensed data
module 818a via the data transmission module 816.
[0383] The control signal transmission module 718b interfaces
between the control modules of the master drilling control module
818 and the actual working systems. For example, it sends and
receives control signals to the drawworks 130, the top drive 140,
the mud pump 180, and in some embodiments, the BHA 170 in FIG. 1.
The BHA control module 718c may be employed when the BHA is
configured to be controlled downhole.
[0384] The drawworks control module 420b, the top drive control
module 420a, and the mud pump control module 420f are used to
generate control signals sent via the control signal transmission
module 718b to the drawworks, the top drive, and the mud pump.
These may correspond to the controllers shown in FIG. 4C.
[0385] In some embodiments, the master drilling control module 818
may include less than all the optimization modules 818g-m shown,
with each of the optimization modules being separately purchasable
by a user. Accordingly, some embodiments may include only one of
the optimization modules while other embodiments include more than
one of the optimization modules. Thus, the master drilling control
module 818 may be configured so that the available modules
cooperate to arrive at optimization values considering all the
optimization modules available in the master drilling control
module. This is further discussed below with reference to FIG.
8C.
[0386] Still referring to FIG. 8B, the ROP optimization module 818g
determines methods or adjustments to processes that improve the ROP
of the BHA. The ROP optimization module 818g receives data from the
sensed data module 430 as well as other data, including data
relating to toolface orientation, among others, to determine the
most effective way to maximize ROP. After considering these and/or
other factors, the ROP optimization module 818g communicates with
the control modules 818c, 420a, 420b, and 420f so that the control
modules can determine whether steering changes would optimize ROP
in a way that maximizes productivity and effectiveness.
[0387] The bit life optimization module 818h may consider data
received from the sensed data module 430 as well as toolface
orientation data, including azimuth, inclination toolface
orientation data, time in drilling, to determine the most effective
way to preserve bit life without compromising effectiveness or
productivity. After considering these or other factors, the bit
life optimization module communicates with the control modules
818c, 420a, 420b, and 420f so that the control modules can
determine whether steering changes would preserve bit life in a way
that maximizes productivity and effectiveness.
[0388] The MSE-based optimization module 818i performs the MSE
based optimization processes discussed above with reference to
FIGS. 6A, 6C, and 6D. The outputs of the optimization module 818i
may be communicated to the control modules 818c, 420a, 420b, and
420f to actually implement the changes that result in the
efficiencies.
[0389] The d-exponent-based optimization module 818j may include
the d-exponent calculator 804g to determine the d-exponent and
evaluate ROP while detecting or predicting abnormal pore pressure
zones. Accordingly, as the d-exponent module detects variance in
normal pressure, the d-exponent module can communicate with the
control modules 818c, 420a, 420b, and 420f to consider making any
steering changes necessary for efficient and effective
drilling.
[0390] The d-exponent-corrected-based optimization module 818k may
include the d-exponent-corrected calculator 804h. Using the data
received, the optimization module 818k corrects the d-exponent
value for mud weight which can be related directly to formation
pressure rather than to differential pressure. This corrected value
also can be communicated to the control modules 818c, 420a, 420b,
and 420f to consider making any steering changes necessary for
efficient and effective drilling.
[0391] The BHA optimization module 818m may consider data received
from the sensed data module 430, data input at the manual data
input module 714a, and other obtainable data to determine
optimization profiles for the BHA. In some embodiments, the BHA
optimization module 818m processes information received from other
modules in the master drilling control module 718. Using this
information, the BHA optimization module 818m outputs data to the
control modules 818c, 420a, 420b, and 420f to consider making any
steering changes to the BHA necessary to optimize the BHA.
[0392] As the drawworks control module 420b, the top drive control
module 420a, and the mud pump control module 420f receive
information from the optimization modules, they process the data to
determine whether the interaction of the recommended changes would
positively or negatively affect the overall productivity of the
well system, and generate control signals instructing the drawworks
130, the top drive 140, and the mudpump 180 of FIG. 1 in a manner
to most effectively implement changes.
[0393] FIG. 8C shows an exemplary method 830 performed by the
master drilling control module 818 to optimize the overall drilling
operation of the drilling rig. As discussed above, some embodiments
of the master drilling control module 818 do not include all the
optimization modules shown in FIG. 8B. Accordingly, the method 830
considers the circumstances where the master drilling control
module includes one, more than one, or less than all the
optimization modules shown. It is contemplated that these modules
are exemplary and that other optimization modules may be included
therein.
[0394] The method 830 includes steps that appear in parallel, and
are not necessarily done in series. In some embodiments, these
parallel method paths are alternative paths and may be implemented
based upon the configuration of the master drilling control module
and/or the availability of the optimization modules. For example,
from step 832, the method 830 continues to steps 834, 840, 846,
852, and 858. These are each discussed below.
[0395] Referring to FIG. 8C, at a step 832, the master drilling
control module 718 receives manual inputs and/or sensed data from
the manual data input module 814a and/or the sensed data module 430
(input or sensed data not shown). In some instances, the master
drilling control module 718 may access trend data stored from prior
surveys.
[0396] Using this information and data, the optimization modules in
the master drilling control module 818 calculate or otherwise
process data using algorithms to determine optimization values for
any number of factors affecting drilling efficiency or
productivity, including ROP. In some embodiments, the alternative
paths in FIG. 8C are dependent on the availability of the
optimization modules. For example, from step 832, the method 830
continues to step 834 if the master drilling control module 818
includes only the ROP optimization module 818g of the optimization
modules. Alternatively, from step 832, the method 830 continues to
step 840 if the master drilling control module 818 includes only
one of the MSE-based optimization module 818i, the d-exponent-based
optimization module 818j, the d-exponent-corrected-based
optimization module 818k, and the BHA optimization module 818m.
Again, alternatively, from step 832, the method 830 continues to
step 846 if the master drilling control module 818 includes more
than one optimization module. The method 832 continues to step 852
if the master drilling control module 818 includes the ROP
optimization module 818g and one of the MSE-based optimization
module 818i, the d-exponent-based optimization module 818j, the
d-exponent-corrected-based optimization module 818k, and the BHA
optimization module 818m. The method 832 continues to step 858 if
the master drilling control module 818 includes the ROP
optimization module 8l 8g and more than one optimization module
818i, 818j, 818k, 818l, and 818m.
[0397] In alternative, embodiments, the master drilling control
module 818 performs all the steps of the method rather than
treating them as alternative steps as described above. Accordingly,
although the master drilling control module includes a plurality of
optimization modules, it still considers the ROP optimization
module 818g independently at step 834, considers one of the other
optimization modules independently at step 840, and so on with
steps 846, 852, and 858.
[0398] In the circumstances where only the ROP optimization module
818g is included in the master drilling control module 818, or the
master control module 818 is configured to consider only the ROP
optimization module 818g, at step 834, the ROP optimization module
818g determines drilling parameter changes that optimize drilling
operation based on ROP using the manual inputs and/or sensed data.
These drilling parameter changes are communicated to the BHA
control module 818c, the drawworks control module 420b, the top
drive control module 420a, and/or the mud pump, control module
420f. At step 836, these control modules modify the one or more
control signals being sent to the BHA, the drawworks, the top
drive, and or the mudpump to change the drilling parameter(s)
necessary to optimize the drilling operation based on ROP.
[0399] In the circumstances where only one optimization module is
included in the master drilling control module 818, or the master
control module 818 is configured to consider only one optimization
module, at step 840, using the MSE-based optimization module 818i,
the d-exponent-based optimization module 818j, the
d-exponent-corrected-based optimization module 818k, and the BHA
optimization module 818m, the master drilling control module 818
can calculate one of MSE, d-exp, d-exp-corrected, and BHA
optimization values based on data received from the sensed data
module and/or the manual data input module 814a. Based on this
data, at step 842, the master drilling control module 818 can
determine the drilling parameter changes necessary to optimize the
drilling operation based on the calculated one of MSE, d-exp,
d-exp-corrected, and BHA optimization values. These drilling
parameter changes are communicated to the BHA control module 818c,
the drawworks control module 420b, the top drive control module
420a, and/or the mud pump control module 420f. At step 844, these
control modules modify the control signals being sent to the BHA,
the drawworks, the top drive, and or the mudpump to change the
drilling parameters necessary to optimize the drilling operation
based on the calculated value.
[0400] In the circumstances where more than one optimization module
is included in the master drilling control module, at step 846
using the optimization modules 818i, 818j, 818k, 818l, and 818m,
the master drilling control module 818 preferably calculates more
than one (typically at least two) of MSE, d-exp, d-exp-corrected,
and BHA optimization values based on data received form the sensed
data module and/or the manual data input module 814a. Based on this
data, at step 848, the master drilling control module 818 can
determine the drilling parameter changes necessary to optimize the
drilling operation based on the plurality of calculated values.
These drilling parameter changes are communicated to the BHA
control module 818c, the drawworks control module 420b, the top
drive control module 420a, and/or the mud pump control module
420fand at step 850, these control modules modify the control
signals being sent to the BHA, the drawworks, the top drive, and or
the mudpump to change the drilling parameters necessary to optimize
the drilling operation based on the plurality of calculated
values.
[0401] In the circumstances where the ROP optimization module 818g
and only one other optimization module are included in the master
drilling control module 818, of the master control module 818 is
configured to consider only the ROP optimization module 818g and
only one other optimization module, at step 854, the master
drilling control module 818 preferably determines the drilling
parameter changes necessary to optimize the drilling operation
based on the one calculated value and the ROP optimization value.
These values are communicated to the control modules and at step
856, these control modules can modify the control signals being
sent to the BHA, the drawworks, the top drive, and or the mudpump
to change the drilling parameters necessary to optimize the
drilling operation based on the calculated value.
[0402] In the circumstances where the ROP optimization module and
more than one additional optimization module are included in the
master drilling control module, at step 858, using the optimization
modules 818i, 818j, 818k, 818l, and 818m the master drilling
control module 818 calculates more than one of MSE, d-exp,
d-exp-corrected, and BHA optimization values based on data received
from the sensed data module and/or the manual data input module
814a. Here, the master drilling control module 818 considers ROP
when determining the drilling parameter changes necessary to
optimize the drilling operation. Accordingly the master drilling
control module 818 can consider the plurality of calculated values
from the optimization modules, including the ROP, to determine the
optimized drilling parameter changes. These drilling parameter
changes are communicated to the control modules 818c, 420b, 420a,
and/or 420f and at step 862, these control modules modify the
control signals being sent to the BHA, the drawworks, the top
drive, and/or the mudpump to change the drilling parameters
necessary to optimize the drilling operation based on the plurality
of calculated values.
[0403] Regardless of which path is used, after modified control
signals are sent from the master drilling control module, the
display module 814b preferably updates the optional but preferred
HMI display at step 838 to reflect these new changed control
signals. The HMI display is discussed further herein and as
incorporated.
[0404] In some instances, the master drilling control module 818
performs all or some of the steps 834, 840, 846, 852, and 858 at
the same time, or in sufficiently rapid succession so as to appear
simultaneous, and the control signals are modified based on
multiple inputs from the system.
[0405] FIGS. 9A and 9B show flow charts detailing methods of
optimizing directional drilling accuracy during drilling operations
performed via the apparatus 100 in FIG. 1. Any of the control
systems disclosed herein, including FIGS. 1, 3, 4A-C, 6B, 8A, and
8B may be used to execute the methods of FIGS. 9A and 9B. The
real-time data obtained in these methods may be configured as
inputs in FIG. 4A to optimize drilling operations and to calculate
bit position in order to identify and correct any deviations of the
bit from the planned drilling path during drilling operations.
[0406] Referring first to FIG. 9A, illustrated is a flow-chart
diagram of a method 900 according, to one or more aspects of the
present disclosure. The method 900 may be performed in association
with one or more components of the apparatus 100 shown in FIG. 1
during operation of the apparatus 100. For example, the method 900
may be performed to optimize directional drilling accuracy during
drilling operations performed via the apparatus 100.
[0407] The method 900 includes a step 910 during which real-time
toolface, hole depth, pipe rotation, hook load, delta pressure,
and/or other data are received by a controller or other processing
device (e.g., any of the controller 190, 325, 420, 402, 698, 804,
812 or others discussed herein). The data may be obtained from
various rig instruments and/or sensors configured for such
measurement (such as the sensors shown in FIGS. 1, 4A, 8 A, and
others). The step 910 may also include receiving modeled dogleg
and/or other well plan data taken from surveys or otherwise
obtained. In a subsequent step 920, the real-time and/or modeled
data received during step 910 is utilized to calculate a real-time
survey projection ahead of the most recent standard survey result.
The real-time survey projection calculated during step 920 can then
optionally be temporarily utilized as the next standard survey
point during a subsequent step 930. The method 900 may also include
a step 940 following step 920 and/or step 930, during which the
real-time survey projection calculated during step 920 is compared
to the well plan at the corresponding hole depth. A step 950 may
follow step 930 and/or step 940, during which the directional
driller is given the real-time survey projection calculated during
step 920 and/or the results of the comparison performed during step
940. Consequently, the directional driller can more accurately
assess the progress of the current drilling operation even in the
absence of any direct inclination and azimuth measurements at hole
depth.
[0408] In an exemplary embodiment within the scope of the present
disclosure, the method 900 then repeats, such that the method flow
goes back to step 910 and begins again. Iteration of the method 900
may be utilized to characterize the performance of the bottom hole
assembly. Moreover, iteration may allow the real-time survey
projection calculation model to refine itself each time a survey is
received. Use of the method 900 may, at least in some embodiments,
assist the directional driller in the drilling operation by
applying build and turn rates to the slide sections and projections
across sections drilled by rotating.
[0409] As described, above, the conventional approach entails
conducting a standard survey at each drill pipe connection to
obtain a measurement of inclination and azimuth for the new survey
position. Thus, the prior art makes measurements after the hole is
drilled. In contrast, with the method 900 and others within the
scope the present disclosure, real-time measurements are made ahead
of the last standard survey, and can give the directional driller
feedback on the progress and effectiveness of a slide or rotation
procedure.
[0410] Referring to FIG. 9B, illustrated is a flow-chart diagram of
a simplified version of the method 900 shown in FIG. 9A, herein
designated by the reference numeral 900a. The method 900a includes
step 910 during which, toolface and hole depth measurements are
received from rig instruments. Step 910 may also include receiving
model or well plan data corresponding to the real-time data
received from the rig instruments. Such receipt of the real-time
and/or model data may be at one or more controllers, processing
devices, and/or other devices, such as the controller 190 shown in
FIG. 1.
[0411] In a subsequent step 960, these measurements are utilized
with modeled or calculated data from previous surveys (e.g.,
including build rates, doglegs, etc.) to track the progress of the
hole by calculating a real-time survey projection and comparing the
projection to the well plan. Steps 910 and 960 are then repeated,
perhaps at rates or intervals which yield high granularity. Step
960 may also include averaging the received data across depth
intervals (e.g., averaging most recently received data with
previously received data). Consequently, the data received during
step 910 and processed during step 960 may provide precise
resolution, perhaps on a foot-by-foot basis during a slide
operation, and may demonstrate how a particular drilling operation
will be or is being affected by how precise a particular toolface
is being maintained.
[0412] A high resolution view of the current hole versus the well
plan is often key to tracking the effectiveness of a slide
operation. For example, within the span of a single joint, a
directional driller may be required (e.g., by the well plan) to
perform a 20 foot slide, 50 feet of rotary drilling, and then
another 20 foot slide. Conventionally, the driller would not know
the effectiveness of this section until he receives his next
survey, which is performed after the slide-rotate-slide procedure
is attempted. However, according to one or more aspects of the
present disclosure, the driller can calculate utilize realtime
surveys projections throughout the slide-rotate-slide procedure to
show the projected well path of the bit. Thus, the accuracy with
which the slide-rotate-slide procedure is performed may be
dramatically increased, and when used to perform the method in FIG.
5A, provides more accurate directional correction than conventional
systems. Moreover, the methods 900 and 900a may include updating
build rates and model on each real-time survey, thus increasing the
accuracy of each subsequent survey, survey projection, and/or
drilling stage.
[0413] FIGS. 10A and 10B are exemplary illustrations of user
displays relaying information about the bit location to a user. The
display in the figures may be any display discussed herein,
including the displays 335, 472, 692c, and 810. Turning to FIG.
10A, illustrated is a schematic view of a human-machine interface
(HMI) 1000 according to one or more aspects of the present
disclosure. The HMI 100 may be utilized by a human operator during
directional and/or other drilling operations to monitor the
relationship between toolface orientation and quill position. In an
exemplary embodiment, the HMI 1000 is one of several display
screens selectable by the user during drilling operations, and may
be included as or within the human-machine interfaces, drilling
operations and/or drilling apparatus described in the systems
herein and the systems incorporated by reference. The HMI 100 may
also be implemented as a series of instructions recorded on a
computer-readable medium, such as described in one or more of these
references.
[0414] The HMI 100 is used by the directional driller while
drilling to monitor the BHA in three-dimensional space. The control
system or computer which drives one or more other human-machine
interfaces during drilling operation may be configured to also
display the HMI 1000. Alternatively, the HMI 1000 may be driven or
displayed by a separate control system or computer, and may be
displayed on a computer display (monitor) other than that on which
the remaining drilling operation screens are displayed.
[0415] The control system or computer driving the HMI 1000 includes
a "survey" or other data channel, or otherwise includes means for
receiving and/or reading sensor data relayed from the BHA, a
measurement-while-drilling (MWD) assembly, and/or other drilling
parameter measurement means, where such relay may be via the
Wellsite Information Transfer Standard (WITS). WITS Markup Language
(WITSML), and/or another data transfer protocol. Such electronic
data may include gravity-based toolface orientation data,
magnetic-based toolface orientation data, azimuth toolface
orientation data, and/or inclination toolface orientation data,
among others. In an exemplary embodiment, the electronic data
includes magnetic-based toolface orientation data when the toolface
orientation is less than about 7.degree. relative to vertical, and
alternatively includes gravity-based toolface orientation data when
the toolface orientation is greater than about 7.degree. relative
to vertical. In other embodiments, however, the electronic data may
include both gravity- and magnetic-based toolface orientation data.
The azimuth toolface orientation data may relate the azimuth
direction of the remote end of the drill string relative to true
North, wellbore high side, anchor another predetermined
orientation. The inclination toolface orientation data may relate
the inclination of the remote end of the drill string relative to
vertical.
[0416] As shown in FIG. 10A, the HMI 1000 may be depicted as
substantially resembling a dial or target shape having a plurality
of concentric nested rings 1005. The magnetic-based toolface
orientation data is represented in the HMI 1000 by symbols 1010,
and the gravity-based toolface orientation data is represented by
symbols 1015. The HMI 1000 also includes symbols 1020 representing
the quill position. In the exemplary embodiment shown in FIG. 10A,
the magnetic toolface data symbols 1010 are circular, the gravity
toolface data symbols 1015 are rectangular, and the quill position
data symbols 1020 are triangular, thus distinguishing the different
types of data from each other. Of course, other shapes may be
utilized within the scope of the present disclosure. The symbols
1010, 1015, 1020 may also or alternatively be distinguished from
one another via color, size, flashing, flashing rate, and/or other
graphic means.
[0417] The symbols 1010, 1015, 1020 may indicate only the most
recent toolface (1010, 1015) and quill position (120) measurements.
However, as in the exemplary embodiment shown in FIGS. 10A and 10B;
the HMI 1000 may include a historical representation of the
toolface and quill position measurements, such that the most recent
measurement and a plurality of immediately prior measurements are
displayed. Thus, for example, each ring 1005 in the HMI 1000 may
represent a measurement iteration or count, or a predetermined time
interval, or otherwise indicate the historical relation between the
most recent measurement(s) and prior measurement(s). In the
exemplary embodiment shown in FIG. 10 there are five such rings
1005 in the dial (the outermost ring being reserved for other data
indicia), with each ring 1005 representing a data measurement or
relay iteration or count. The toolface symbols 1010, 1015 may each
include a number indicating the relative age of each measurement.
In other embodiments, color, shape, and/or other indicia may
graphically depict the relative age of measurement. Although not
depicted as such in FIG. 10A, this concept may also be employed to
historically depict the quill position data.
[0418] The HMI 1000 may also include a data legend 1025 linking the
shapes, colors, and/or other parameters of the data symbols 1010,
1015, 1020 to the corresponding data represented by the symbols.
The HMI 1000 may also include a textual and/or other type of
indicator 1030 of the current toolface mode setting. For example,
the toolface mode may be set to display only gravitational toolface
data, only magnetic toolface data, or a combination thereof
(perhaps based on the current toolface and/or drill string end
inclination). The indicator 1030 may also indicate the current
system time. The indicator 1030 may also identify a secondary
channel or parameter being monitored or otherwise displayed by the
HMI 1000. For example, in the exemplary embodiment shown in FIG.
10A, the indicator 1030 indicates that a combination ("Combo")
toolface mode is currently selected by the user, that the bit depth
is being monitored on the secondary channel, and that the current
system time is 13:09:04.
[0419] The HMI 1000 may also include a textual and/or other type of
indicator 1035 displaying the current or most, recent toolface
orientation. The indicator 1035 may also display the current
toolface measurement mode (e.g., gravitational vs. magnetic). The
indicator 1035 may also display the time at which the most recent
toolface measurement was performed or received, as well as the
value of any parameter being monitored by a second channel at that
time. For example, in the exemplary embodiment shown in FIG. 10A,
the most recent toolface measurement was measured by a
gravitational toolface sensor, which indicated that the toolface
orientation was -75 V and this measurement was taken at time
13:00:13 relative to the system clock, at which time the bit-depth
was most recently measured to be 1830 feet.
[0420] The HMI 1000 may also include a textual and/or other type of
indicator 1040 displaying the current or most recent, inclination
of the remote end of the drill string. The indicator 1040 may also
display the time at which the most recent inclination measurement
was performed or received, as well as the value of any parameter
being monitored by a second channel at that time. For example, in
the exemplary embodiment shown in FIG. 10A, the most recent drill
string end inclination was 8.degree., and this measurement was
taken at time 13:00:04 relative to the system clock, at which time
the bit-depth was most recently measured to be 1830 feet. The HMI
1000 may also include an additional graphical or other type of
indicator 1040a displaying the current or most recent inclination.
Thus, for example, the HMI 1000 may depict the current or most
recent inclination with both a textual indicator (e.g., indicator
1040) and a graphical indicator (e.g., indicator 1040a). In the
embodiment shown in FIG. 10A, the graphical inclination indicator
1040a represents the current or most recent inclination as an
arcuate bar, where the length of the bar indicates the degree to
which the inclination varies from vertical, and where the direction
in which the bar extends (e.g., clockwise vs. counterclockwise) may
indicate a direction of inclination (e.g., North vs. South).
[0421] The HMI 1000 may also include a textual and/or other type of
indicator 1045 displaying the current or most recent azimuth
orientation of the remote end of the drill string. The indicator
1045 may also display the time at which the most recent azimuth
measurement was performed or received, as well as the value of any
parameter being monitored by a second channel at that time. For
example, in the exemplary embodiment shown in FIG. 10A, the most
recent drill string end azimuth was 67.degree., and this
measurement was taken at time 12:59:55 relative to the system
clock, at which time the bit-depth was most recently measured to be
1830 feet. The HMI 1000 may also include an additional graphical or
other type of indicator 1045a displaying the current or most recent
inclination. Thus, for example, the HMI 1000 may depict the current
or most recent inclination with both a textual indicator (e.g.,
indicator 1045) and a graphical indicator (e.g., indicator 1045a).
In the embodiment shown in FIG. 10A, the graphical azimuth
indicator 1045a represents the current or most recent azimuth
measurement as an arcuate bar, where the length of the bar
indicates the degree to which the azimuth orientation varies from
true North or some other predetermined position, and where the
direction in which the bar extends (e.g., clockwise vs.
counterclockwise) may indicate an azimuth direction (e.g.,
East-of-North vs. West-of-North).
[0422] In some embodiments, the HMI 1000 includes data
corresponding to the planned drilling path and the actual drilling
path discussed with reference to FIGS. 4C and 5A. This data may
provide a visual indicator to a driller of the location of the BHA
bit relative to the planned drilling path and/or the target
location. In addition, the taken-over-time data displayed in the
HMI 1000 in FIG. 10A may be considered when calculating the
position of the BHA, whether it is deviating from the planned
drilling path, and which zone in FIG. 5B it is located in.
[0423] Referring to FIG. 10B, illustrated is a magnified view of a
portion of the HMI 1000 shown in FIG. 10A. In embodiments in which
the HMI 1000 is depicted as a dial or target shape, the most recent
toolface and quill position measurements may be closest to the edge
of the dial, such that older readings may step toward the middle of
the dial. For example, in the exemplary embodiment shown in FIG. 2,
the last reading was 8 minutes before the currently-depicted system
time, the next reading was 7 minutes before that one, and the
oldest reading was 6 minutes older than the others, for a total of
21 minutes of recorded activity. Readings that are hours or seconds
old may indicate the length/unit of time with an "h" or an "s."
[0424] As also shown in FIG. 10B, positioning the user's mouse
pointer or other graphical user-input means over one of the
toolface or quill position symbols 1010, 1015, 1020 may show the
symbol's timestamp, as well as the secondary indicator (if any), in
a pop-up window 1050. Timestamps may be dependent upon the device
settings at the actual time of recording the measurement. The
toolface symbols 1010, 1015 may show the time elapsed from when the
measurement is recorded by the sensing device (e.g., relative to
the current system time). Secondary channels set to display a
timestamp may show a timestamp according to the device recording
the measurement.
[0425] In the embodiment shown in FIGS. 10A and 10B, the HMI 1000
shows the absolute position of the top-drive quill referenced to
true North, hole high-side, or to some other predetermined
orientation. The HMI 1000 also shows current and historical
toolface data received from the downhole tools (e.g., MWD). The HMI
1000, other human-machine interfaces within the scope of the
present disclosure, and/or other tools within the scope of the
present disclosure may have, enable, and/or exhibit a simplified
understanding of the effect of reactive torque on toolface
measurements, by accurately monitoring and simultaneously
displaying both toolface and quill position measurements to the
user.
[0426] In view of the above, the Figures, and the references
incorporated herein, those of ordinary skill in the art should
readily understand that the present disclosure introduces a method
of visibly demonstrating a relationship between toolface
orientation and quill orientation, such method including: (1)
receiving electronic data on an on-going basis, wherein the
electronic data includes quill orientation data and at least one of
gravity-based toolface orientation data and magnetic-based toolface
orientation data; and (2) displaying the electronic data on a
user-viewable display in a historical format depicting data
resulting from a most recent measurement and a plurality of
immediately prior measurements. The electronic data may further
include toolface azimuth data, relating the azimuth orientation of
the drill string near the bit. The electronic data may further
include toolface inclination data, relating the inclination of the
drill string near the bit. The quill position data may relate the
orientation of the quill, top drive, Kelly, and/or other rotary
drive means to the bit and/or toolface. The electronic data may be
received from MWD and/or other downhole sensor/measurement
means.
[0427] The method may further include associating the electronic
data with time indicia based on specific times at which
measurements yielding the electronic data were performed. In an
exemplary embodiment, the most current data may be displayed
textually and older data may be displayed graphically, such as a
dial- or target-shaped representation. The graphical display may
include time-dependent or time-specific symbols or other icons,
which may each be user-accessible to temporarily display data
associated with that time (e.g., pop-up data). The icons may have a
number, text, color, or other indication of age relative to other
icons. The icons may be oriented by time, newest at the dial edge,
oldest at the dial center. The icons may depict the change in time
from (1) the measurement being recorded by a corresponding sensor
device to (2) the current computer system time. The display may
also depict the current system time.
[0428] The present disclosure also introduces an apparatus
including: (1) means for receiving electronic data on an on-going
basis, wherein the electronic data includes quill orientation data
and at least one of gravity-based toolface orientation data and
magnetic-based toolface orientation data; and (2) means for
displaying the electronic data on a user-viewable display in a
historical format depicting data resulting from a most recent
measurement and a plurality of immediately prior measurements.
[0429] Embodiments within the scope of the present disclosure may
offer certain advantages over the prior art. For example, when
toolface and quill position data are combined on a single visual
display, it may help an operator or other human personnel to
understand the relationship between toolface and quill position.
Combining toolface and quill position data on a single display may
also or alternatively aid understanding of the relationship that
reactive torque has with toolface and/or quill position.
[0430] Referring to FIG. 11, illustrated is an exemplary system
1100 for implementing one or more embodiments of at least portions
of the apparatus and/or methods described herein. The system 1100
includes a processor 1102, an input device 1104, a storage device
1106, a video controller 1108, a system memory 1110, a display
1114, and a communication device 1116, all interconnected by one or
more buses 1112. The storage device 1106 may be a floppy drive,
hard drive, CD, DVD, optical drive, or any other form of storage
device. In addition, the storage device 1106 may be capable of
receiving a floppy disk, CD, DVD, or any other form of
computer-readable medium that may contain computer-executable
instructions. Communication device 1116 may be a modem, network
card, or any other device to enable the system 1100 to communicate
with other systems.
[0431] A computer system typically includes at least hardware
capable of executing machine readable instructions, as well as
software for executing acts (typically machine-readable
instructions) that produce a desired result. In addition, a
computer system may include hybrids of hardware, and software, as
well as computer sub-systems.
[0432] Hardware generally includes at least processor-capable
platforms, such as client-machines (also known as personal
computers or servers), and hand-held processing devices (such as
smart phones, PDAs, and personal computing devices (PCDs), for
example). Furthermore, hardware typically includes any physical
device that is capable of storing machine-readable instructions,
such as memory or other data storage devices. Other forms of
hardware include hardware sub-systems, including transfer devices
such as modems, modem cards, ports, and port cards, for example.
Hardware may also include, at least within the scope of the present
disclosure, multi-modal technology, such as those devices and/or
systems configured to allow users to utilize multiple forms of
input and output including voice, keypads, and
stylus--interchangeably in the same interaction, application, or
interface.
[0433] Software may include any machine code stored in any memory
medium, such as RAM or ROM, machine code stored on other devices
(such as floppy disks, CDs or DVDs, for example), and may include
executable code, an operating system, as well as source or object
code, for example. In addition, software may encompass any set of
instructions capable of being executed in a client machine or
server--and, in this form, is often called a program or executable
code.
[0434] Hybrids (combinations of software and hardware) are becoming
more common as devices for providing enhanced functionality and
performance to computer systems. A hybrid may be created when what
are traditionally software functions are directly manufactured into
a silicon chip--this is possible since software may be assembled
and compiled into ones and zeros, and, similarly, ones and zeros
can be represented directly in silicon. Typically, the hybrid
(manufactured hardware) functions are designed to operate
seamlessly with software. Accordingly, it should be understood that
hybrids and other combinations of hardware and software are also
included within the definition of a computer system herein, and are
thus envisioned by the present disclosure as possible equivalent
structures and equivalent methods.
[0435] Computer-readable mediums may include passive data storage
such as a random access memory (RAM), as well as semi-permanent
data storage such as a compact disk or DVD. In addition, an
embodiment of the present disclosure may be embodied in the RAM of
a computer and effectively transform a standard computer into a new
specific computing machine.
[0436] Data structures are defined organizations of data that may
enable an embodiment of the present disclosure. For example, a data
structure may provide an organization of data or an organization of
executable code (executable software). Furthermore, data signals
are carried across transmission mediums and store and transport
various data structures, and, thus, may be used to transport an
embodiment of the invention. It should be noted in the discussion
herein that acts with like names may be performed in like manners,
unless otherwise stated.
[0437] The controllers and/or systems of the present disclosure may
be designed to work on any specific architecture. For example, the
controllers and/or systems may be executed on one or more
computers. Ethernet networks, local area networks, wide area
networks, internets, intranets, hand-held and other portable and
wireless devices and networks.
[0438] In view of all of the above and FIGS. 1-11, those of
ordinary skill in the art should readily recognize that the present
disclosure introduces a method of directionally steering a bottom
hole assembly during a drilling operation from a drilling rig to an
underground target location. The method includes generating a
drilling plan having a drilling path and an acceptable margin of
error as a tolerance zone; receiving data indicative of directional
trends and projection to bit depth; determining the actual location
of the bottom hole assembly based on the direction trends and the
projection to bit depth; determining whether the bit is within the
tolerance zone; comparing the actual location of the bottom hole
assembly to the planned drilling path to identify an amount of
deviation of the bottom hole assembly from the actual drilling
path; creating a modified drilling path based on the amount of
identified deviation from the planned path including: creating a
modified drilling path that intersects the planned drilling path if
the amount of deviation from the planned path is less than a
threshold amount of deviation, and creating a modified drilling
path to the target location that does not intersect the planned
drilling path if the amount of deviation from the planned path is
greater than a threshold amount of deviation; determining a desired
tool face orientation to steer the bottom hole assembly along the
modified drilling path; automatically and electronically generating
drilling rig control signals at a directional steering controller;
and outputting the drilling rig control signals to a drawworks and
a top drive to steer the bottom hole assembly along the modified
drilling path.
[0439] The present disclosure also introduces a method of using a
quill to steer a hydraulic motor when elongating a wellbore in a
direction having a horizontal component, wherein the quill and the
hydraulic motor are coupled to opposing ends of a drill string, the
method including: monitoring an actual toolface orientation of a
tool driven by the hydraulic motor by monitoring a drilling
operation parameter indicative of a difference between the actual
toolface orientation and a desired toolface orientation; and
adjusting a position of the quill by an amount that is dependent
upon the monitored drilling operation parameter. The amount of
quill position adjustment may be sufficient to compensate for the
difference between the actual and desired toolface orientations.
Adjusting the quill position may include adjusting a rotational
position of the quill relative to the wellbore, a vertical position
of the quill relative to the wellbore, or both. Monitoring the
drilling operation parameter indicative of the difference between
the actual and desired toolface orientations may include monitoring
a plurality of drilling operation parameters each indicative of the
difference between the actual and desired toolface orientations,
and the amount of quill position adjustment may be further
dependent upon each of the plurality of drilling operation
parameters.
[0440] Monitoring the drilling operation parameter may include
monitoring data received from a toolface orientation sensor, and
the amount of quill position adjustment may be dependent upon the
toolface orientation sensor data. The toolface sensor may include a
gravity toolface sensor and/or a magnetic toolface sensor.
[0441] The drilling operation parameter may include a weight
applied to the tool (WOB), a depth of the tool within the wellbore,
and/or a rate of penetration of the tool into the wellbore (ROP).
The drilling operation parameter may include a hydraulic pressure
differential across the hydraulic motor (.DELTA.P), and the
.DELTA.P may be a corrected .DELTA.P based on monitored pressure of
fluid existing in an annulus defined between the wellbore and the
drill string,
[0442] In an exemplary embodiment, monitoring the drilling
operation parameter indicative of the difference between the actual
and desired toolface orientations includes monitoring data received
from a toolface orientation sensor, monitoring a weight applied to
the tool (WOB), monitoring a depth of the tool within the wellbore,
monitoring a rate of penetration of the tool into the wellbore
(ROP), and monitoring a hydraulic pressure differential across the
hydraulic motor (.DELTA.P). Adjusting the quill position may
include adjusting the quill position by an amount that is dependent
upon the monitored toolface orientation, sensor data, the monitored
WOB, the monitored depth of the tool within the wellbore, the
monitored ROP, and the monitored .DELTA.P.
[0443] Monitoring the drilling operation parameter and adjusting
the quill position may be performed simultaneously with operating
the hydraulic motor. Adjusting the quill position may include
causing a drawworks to adjust a weight applied to the tool ( WOB)
by an amount dependent upon the monitored drilling operation
parameter. Adjusting the quill position may include adjusting a
neutral rotational position of the quill, and the method may
further include oscillating the quill by rotating the quill through
a predetermined angle past the neutral position in clockwise and
counterclockwise directions.
[0444] The present disclosure also introduces a system for using a
quill to steer a hydraulic motor when elongating a wellbore in a
direction having a horizontal component, wherein the quill and the
hydraulic motor are coupled to opposing ends of a drill string. In
an exemplary embodiment, the system includes means for monitoring
an actual toolface orientation of a tool driven by the hydraulic
motor, including means for monitoring a drilling operation
parameter indicative of a difference between the actual toolface
orientation and a desired toolface orientation; and means for
adjusting a position of the quill by an amount that is dependent
upon the monitored drilling operation parameter.
[0445] The present disclosure also provides an apparatus for using
a quill to steer a hydraulic motor when elongating a wellbore in a
direction having a horizontal component, wherein the quill and the
hydraulic motor are coupled to opposing ends of a drill string. In
an exemplary embodiment, the apparatus includes a sensor configured
to detect a drilling operation parameter indicative of a difference
between an actual toolface orientation of a tool driven by the
hydraulic motor and a desired toolface orientation of the tool; and
a toolface controller configured to adjust the actual toolface
orientation by generating a quill drive control signal directing a
quill drive to adjust a rotational position of the quill based on
the monitored drilling operation parameter.
[0446] The present disclosure also introduces a method of using a
quill to steer a hydraulic motor when elongating a wellbore in a
direction having a horizontal component, wherein the quill and the
hydraulic motor are coupled to opposing ends of a drill string. In
an exemplary embodiment, the method includes monitoring a hydraulic
pressure differential across the hydraulic motor (.DELTA.P) while
simultaneously operating the hydraulic motor, and adjusting a tool
face orientation of the hydraulic motor by adjusting a rotational
position of the quill based on the monitored .DELTA.P. The
monitored .DELTA.P may be a corrected .DELTA.P that is calculated
utilizing monitored pressure of fluid existing in an annulus
defined between the wellbore and the drill string. The method may
further include monitoring an existing toolface orientation of the
motor while simultaneously operating the hydraulic motor, and
adjusting the rotational position of the quill based on the
monitored toolface orientation. The method may further include
monitoring a weight applied to a bit of the hydraulic motor (WOB)
while simultaneously operating the hydraulic motor, and adjusting
the rotational position of the quill based on the monitored WOB.
The method may further include monitoring a depth of a bit of the
hydraulic motor within the wellbore while simultaneously operating
the hydraulic motor, and adjusting the rotational position of the
quill based on the monitored depth of the bit. The method may
further include monitoring a rate of penetration of the hydraulic
motor into the wellbore (ROP) while simultaneously operating the
hydraulic motor, and adjusting the rotational position of the quill
based on the monitored ROP. Adjusting the toolface orientation may
include adjusting the rotational position of the quill based on the
monitored WOB and the monitored ROP. Alternatively, adjusting the
toolface orientation may include adjusting the rotational position
of the quill based on the monitored WOB, the monitored ROP and the
existing toolface orientation. Adjusting the toolface orientation
of the hydraulic motor may further include causing a drawworks to
adjust a weight applied to a bit of the hydraulic motor (WOB) based
on the monitored .DELTA.P. The rotational position of the quill may
be a neutral position, and the method may further include
oscillating the quill by rotating the quill through a predetermined
angle past the neutral position in clockwise and counterclockwise
directions.
[0447] The present disclosure also introduces a system for using a
quill to steer a hydraulic motor when elongating a wellbore in a
direction having a horizontal component, wherein the quill and the
hydraulic motor are coupled to opposing ends of a drill string. In
an exemplary embodiment, the system includes means for detecting a
hydraulic pressure differential across the hydraulic motor
(.DELTA.P) while simultaneously operating the hydraulic motor, and
means for adjusting a toolface orientation of the hydraulic motor,
wherein the toolface orientation adjusting means includes means for
adjusting a rotational position of the quill based on the detected
.DELTA.P. The system may further include means for detecting an
existing toolface orientation of the motor while simultaneously
operating the hydraulic motor, wherein the quill rotational
position adjusting means may be further configured to adjust the
rotational position of the quill based on the monitored toolface
orientation. The system may further include means for detecting a
weight applied to a bit of the hydraulic motor (WOB) while
simultaneously operating the hydraulic motor, wherein the quill
rotational position adjusting means may be further configured to
adjust the rotational position of the quill based on the monitored
WOB. The system may further include means for detecting a depth of
a bit of the hydraulic motor within the wellbore while
simultaneously operating the hydraulic motor, wherein the quill
rotational position adjusting means may be further configured to
adjust the rotational position of the quill based on the monitored
depth of the bit. The system may further include means for
detecting a rate of penetration of the hydraulic motor info the
wellbore (ROP) while simultaneously operating the hydraulic motor,
wherein the quill rotational position adjusting means may be
further configured to adjust the rotational position of the quill
based on the monitored ROP. The toolface orientation adjusting
means may further include means for causing a drawworks to adjust a
weight applied to a bit of the hydraulic motor (WOB) based on the
detected .DELTA.P.
[0448] The present disclosure also introduces an apparatus for
using a quill to steer a hydraulic motor when elongating a wellbore
in a direction having a horizontal component, wherein the quill and
the hydraulic motor are coupled to opposing ends of a drill string.
In an exemplary embodiment, the apparatus includes a pressure
sensor configured to detect a hydraulic pressure differential
across the hydraulic motor (.DELTA.P) during operation of the
hydraulic motor, and a toolface controller configured to adjust a
toolface orientation of the hydraulic motor by generating a quill
drive control signal directing a quill drive to adjust a rotational
position of the quill based on the detected .DELTA.P. The apparatus
may further include a toolface orientation sensor configured to
detect a current toolface orientation, wherein the toolface
controller may be configured to generate the quill drive control
signal further based on the detected current toolface orientation.
The apparatus may further include a weight-on-bit (WOB) sensor
configured to detect data indicative of an amount of weight applied
to a bit of the hydraulic motor, and a drawworks controller
configured to cooperate with the toolface controller in adjusting
the toolface orientation by generating a drawworks control signal
directing a drawworks to operate the drawworks, wherein the
drawworks control signal may be based on the detected WOB. The
apparatus may further include a rate-of-penetration (ROP) sensor
configured to detect a rate at which the wellbore is being
elongated, wherein the drawworks control signal may be further
based on the detected ROP.
[0449] Methods and apparatus within the scope of the present
disclosure include those directed towards automatically obtaining
and/or maintaining a desired toolface orientation by monitoring
drilling operation parameters which previously have not been
utilized for automatic toolface orientation, including one or more
of actual mud motor .DELTA.P, actual toolface orientation, actual
WOB, actual bit depth, actual ROP, actual quill oscillation.
Exemplary combinations of these drilling operation parameters which
may be utilized according to one or more aspects of the present
disclosure to obtain and/or maintain a desired toolface orientation
include: [0450] .DELTA.P and TF; [0451] .DELTA.P, TF, and WOB:
[0452] .DELTA.P, TF, WOB, and DEPTH: [0453] .DELTA.P and WOB;
[0454] .DELTA.P, TF, and DEPTH: [0455] .DELTA.P, TF, WOB, and ROP;
[0456] .DELTA.P and ROP; [0457] .DELTA.P, TF, and ROP; [0458]
.DELTA.P, TF, WOB, and OSC; [0459] .DELTA.P and DEPTH; [0460]
.DELTA.P, TF, and OSC; [0461] .DELTA.P, TF, DEPTH, and ROP; [0462]
.DELTA.P and OSC; [0463] .DELTA.P, WOB, and DEPTH; [0464] .DELTA.P,
TF, DEPTH, and OSC; [0465] TF and ROP: [0466] .DELTA.P, WOB, and
ROP; [0467] .DELTA.P, WOB, DEPTH, and ROP; [0468] TF and DEPTH;
[0469] .DELTA.P, WOB, and OSC: [0470] .DELTA.P, WOB, DEPTH, and
OSC; [0471] TF and OSC; [0472] .DELTA.P, DEPTH, and ROP; [0473]
.DELTA.P, DEPTH, ROP, and OSC; [0474] WOB and DEPTH; [0475]
.DELTA.P, DEPTH, and OSC; [0476] .DELTA.P, TF, WOB, DEPTH, and ROP;
[0477] WOB and OSC; [0478] .DELTA.P, ROP, and OSC; [0479] .DELTA.P,
TF, WOB, DEPTH, and OSC; [0480] ROP and OSC; [0481] .DELTA.P, TF,
WOB, ROP, and OSC; [0482] ROP and DEPTH; and [0483] .DELTA.P, TF,
WOB, DEPTH, ROP, and OSC; where .DELTA.P is the actual mud motor
.DELTA.P, TF is the actual toolface orientation, WOB is the actual
WOB, DEPTH is the actual bit depth, ROP is the actual ROP, and OSC
is the actual quill oscillation frequency, speed, amplitude,
neutral point, and/or torque.
[0484] In an exemplary embodiment, a desired toolface orientation
is provided (e.g., by a user, computer, or computer program), and
apparatus according to one or more aspects of the present
disclosure will subsequently track and control the actual toolface
orientation, as described above. However, while tracking and
controlling the actual toolface orientation, drilling operation
parameter data may be monitored to establish and then update in
real-time the relationship between; (1) mud motor .DELTA.P and bit
torque; (2) changes in WOB and bit torque; and (3) changes in quill
position and actual toolface orientation; among other possible
relationships within the scope of the present disclosure. The
learned information may then be utilized to control actual toolface
orientation by affecting a change in one or more of the monitored
drilling operation parameters.
[0485] Thus, for example, a desired toolface orientation may be
input by a user, and a rotary drive system according to aspects of
the present disclosure may rotate the drill string until the
monitored toolface orientation and/or other drilling operation
parameter data indicates motion of the downhole tool. The automated
apparatus of the present disclosure then continues to control the
rotary drive until the desired toolface orientation is obtained.
Directional drilling then proceeds. If the actual toolface
orientation wanders off from the desired toolface orientation, as
possibly indicated by the monitored drill operation parameter data,
the rotary drive may react by rotating the quill and/or drill
string in either the clockwise or counterclockwise direction,
according to the relationship between the monitored drilling
parameter data and the toolface orientation. If an oscillation mode
is being utilized, the apparatus may alter the amplitude of the
oscillation (e.g., increasing or decreasing the clockwise part of
the oscillation) to bring the actual toolface orientation back on
track. Alternatively, or additionally, a drawworks system may react
to the deviating toolface orientation by feeding the drilling line
in or out, and/or a mud pump system may react by increasing or
decreasing the mud motor .DELTA.P. If the actual toolface
orientation drifts off the desired orientation further than a
preset (user adjustable) limit for a period longer than a preset
(user adjustable) duration, then the apparatus may signal an audio
and/or visual alarm. The operator may then be given the opportunity
to allow continued automatic control, or take over manual
operation.
[0486] This approach may also be utilized to control toolface
orientation, with knowledge of quill orientation before and after a
connection, to reduce the amount of time required to make a
connection. For example, the quill orientation may be monitored
on-bottom at a known toolface orientation, WOB, and/or mud motor
.DELTA.P. Slips may then be set, and the quill orientation may be
recorded and then referenced to the above-described
relationship(s). The connection may then take place, and the quill
orientation may be recorded just prior to pulling from the slips.
At this point, the quill orientation may be reset to what it was
before the connection. The drilling operator or an automated
controller may then initiate an "auto-orient" procedure, and the
apparatus may rotate the quill to a position and then return to
bottom. Consequently, the drilling operator may not need to wait
for a toolface orientation measurement, and may not be required to
go back to the bottom blind. Consequently, aspects of the present
disclosure may offer significant time savings during
connections.
[0487] Moreover, methods within the scope of the present disclosure
may be local or remote in nature. These methods, and any
controllers discussed herein, may be achieved by one or more
intelligent adaptive controllers, programmable logic controllers,
artificial neural networks, and/or other adaptive and/or "learning"
controllers or processing apparatus. For example, such methods may
be deployed or performed via PLC, PAC, PC, one or more servers,
desktops, handhelds, and/or any other form or type of computing
device with appropriate capability.
[0488] As used herein, the term "substantially" means that a
numerical amount is within about 20 percent, preferably within
about 10 percent, and more preferably within about 5 percent of a
stated value. In a preferred embodiment, these terms refer to
amounts within about 1percent, within about 0.5 percent, or even,
within about 0.1 percent, of a stated value.
[0489] The term "about," as used herein, should generally be
understood to refer to both numbers in a range of numerals. For
example, "about 1 to 2" should be understood as "about 1 to about
2." Moreover, all numerical ranges herein should be understood to
include each whole Integer, or 1/10 of an integer, within the
range.
[0490] The present disclosure also incorporates herein in its
entirety by express reference thereto each of the following
references: [0491] U.S. Pat. No. 6,050,348 to Richarson, et al.
[0492] U.S. Pat. No. 5,474,142 to Bowden; [0493] U.S. Pat. No.
5,713,422 to Dhindsa; [0494] U.S. Pat. No. 6,192,998 to Pinckard;
[0495] U.S. Pat. No. 6,026,912 to King, et al.; [0496] U.S. Pat.
No. 7,059,427 to Power, et al.; [0497] U.S. Pat. No. 6,029,951 to
Guggari; [0498] "A Real-time Implementation of MSE,"
AADE-05-NTCE-66; [0499] "Maximizing Drill Rates with Real-Time
Surveillance of Mechanical Specific Energy," SPE 92194; [0500]
"Comprehensive Drill-Rate Management Process To Maximize Rate of
Penetration," SPE 102210: and [0501] "Maximizing ROP With Real-Time
Analysis of Digital Data and MSE," IPTC 10607.
[0502] The foregoing outlines features of several embodiments so
that those of ordinary-skill in the art may better understand the
aspects of the present disclosure. Those of ordinary-skill in the
art should appreciate that they may readily use the present
disclosure as a basis for designing or modifying other processes
and structures for carrying out the same purposes and/or achieving
the same advantages of the embodiments introduced herein. Those of
ordinary-skill in the art should also realize that such equivalent
constructions do not depart from the spirit and scope of the
present disclosure, and that they may make various changes,
substitutions and alterations herein without departing from the
spirit and scope of the present disclosure.
* * * * *