U.S. patent application number 15/098620 was filed with the patent office on 2017-10-19 for efficiency tracking system for a drilling rig.
The applicant listed for this patent is NABORS DRILLING TECHNOLOGIES USA, INC.. Invention is credited to MICHAEL DAVID LOCKRIDGE, CHAKRAPANI MANDAVA.
Application Number | 20170300845 15/098620 |
Document ID | / |
Family ID | 60021765 |
Filed Date | 2017-10-19 |
United States Patent
Application |
20170300845 |
Kind Code |
A1 |
MANDAVA; CHAKRAPANI ; et
al. |
October 19, 2017 |
EFFICIENCY TRACKING SYSTEM FOR A DRILLING RIG
Abstract
Systems, devices, and methods for tracking the efficiency of a
drilling rig are provided. A sensor system on a drilling rig is
provided. A controller in communication with the sensor system may
be operable to generate measureable parameters relating to at least
one Key Performance Indicators (KPIs). The measurable parameters
may be compared with measureable parameters from a target to
generate an Invisible Lost Time (ILT) period and an Invisible Saved
Time (IST) period for the drilling rig. The KPIs, ILT period, and
IST period may be displayed to a user.
Inventors: |
MANDAVA; CHAKRAPANI;
(HOUSTON, TX) ; LOCKRIDGE; MICHAEL DAVID;
(HOUSTON, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
NABORS DRILLING TECHNOLOGIES USA, INC. |
HOUSTON |
TX |
US |
|
|
Family ID: |
60021765 |
Appl. No.: |
15/098620 |
Filed: |
April 14, 2016 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
G06Q 10/06393 20130101;
E21B 41/0092 20130101 |
International
Class: |
G06Q 10/06 20120101
G06Q010/06; E21B 41/00 20060101 E21B041/00 |
Claims
1. A drilling apparatus comprising: a first sensor system connected
to the drilling apparatus and configured to detect at least one
measureable parameter of the drilling apparatus; a data input
system operable to receive an efficiency target; a controller in
communication with the first sensor system and the data input
system, the controller being operable to generate an efficiency
report for a drilling operation, the efficiency report including at
least one Key Performance Indicator (KPI) based on a measured time
period taken to complete at least one measurable parameter of the
drilling apparatus during the drilling operation, the controller
further operable to calculate an Invisible Lost Time (ILT) period
based on a difference between the at least one KPI and the
efficiency target; a drilling apparatus control device in
communication with the controller and configured to control a
drilling apparatus function comprising moving at least a portion of
the drilling apparatus, the drilling apparatus function forming at
least a part of the drilling operation based on the efficiency
report; and an output device in communication with the controller,
the output device configured to output to a user the efficiency
report and the ILT period.
2. The drilling apparatus of claim 1, wherein the controller is
further operable to calculate an Invisible Saved Time (IST) period
based on the difference between the at least one KPI and the
efficiency target.
3. The drilling apparatus of claim 1, wherein the at least one KPI
includes at least one of a tripping speed, a tripping connection
time, a drill connection time, a rate of penetration (ROP), a
casing running speed, a casing connection time, a blow out
preventer (BOP) work time period, a rig maintenance time, a Bottom
Hole Assembly (BHA) handling time, a cementing time, and a
circulating time.
4. The drilling apparatus of claim 1, wherein the at least one KPI
is based on measured data from an operations report.
5. The drilling apparatus of claim 1, wherein the controller is
further operable to generate a plurality of time periods required
to complete tasks on the drilling apparatus based on each of the at
least one KPI.
6. The drilling apparatus of claim 5, wherein the efficiency target
is based on a best composite well time for the drilling apparatus,
wherein the best composite well time is calculated by adding
together a lowest time period of the plurality of time periods
based on each of the at least one KPI.
7. The drilling apparatus of claim 1, wherein the output device
includes at least one of a display, an email report, or a printed
report.
8. The drilling apparatus of claim 7, wherein the efficiency target
includes at least one KPI from a second drilling apparatus based on
the measurable parameters from the second drilling apparatus.
9. The drilling apparatus of claim 8, wherein the second drilling
apparatus has at least one feature in common with the drilling
apparatus including at least one of a common drilling area, a
common drilling client, a common rig type, a common well type, a
common geology, a common location, and a common operator.
10. A drilling rig efficiency tracking system comprising: a data
input system operable to receive sensor data for a first drilling
rig, an operations report for a drilling operation, and an
efficiency target; a controller in communication with the data
input system, the controller operable to compare the sensor data
and the operations report to the efficiency target to generate an
efficiency report for the first drilling rig, the sensor data
including a measured time period taken to complete a task during
the drilling operation, the efficiency report including an
Invisible Lost Time (ILT) period based on a difference between the
measured time period of the sensor data and the efficiency target;
a drilling rig control device in communication with the controller
and configured to control a drilling rig function comprising moving
at least a portion of the drilling rig, the drilling rig function
forming at least a part of the drilling operation based on the
efficiency report; and an output device in communication with the
controller, the output device configured to output the efficiency
report to a user.
11. The system of claim 10, wherein the efficiency report further
includes an Invisible Saved Time (IST) period based on the
comparison a difference between the measured time period of the
sensor data and the efficiency report.
12. The system of claim 10, wherein the efficiency target includes
an operations report from a second drilling rig.
13. The system of claim 12, wherein the second drilling rig has at
least one feature in common with the first drilling rig including
at least one of a common drilling area, a common drilling client, a
common rig type, a common well type, a common geology, a common
location, and a common operator.
14. A method for tracking efficiency of a drilling rig, comprising:
receiving, with a controller, at least one measurable parameter for
a drilling rig function comprising moving at least a portion of the
drilling rig, the drilling rig function forming at least a part of
a drilling operation from a sensor system associated with the
drilling rig; generating at least one Key Performance Indicator
(KPI) based on the drilling operation; calculating, with the
controller, at least one performance time period for each of the at
least one KPI based on the at least one measureable parameter, the
performance time period based on a measured time taken to complete
a task on the drilling rig during the drilling operation;
receiving, with the controller, at least one target time period;
calculating, with the controller, an Invisible Lost Time (ILT)
period based on a difference between the at least one performance
time period and the at least one target time period; receiving,
with a drilling rig control device configured to control the
drilling rig function, the ILT period; controlling, with the
drilling rig control device, the drilling rig function based on the
ILT period; and outputting the ILT period to a user on an output
device.
15. The method of claim 14, wherein the at least one target time
period is based on a best composite well time for the drilling rig,
wherein the best composite well time is calculated by adding
together a lowest time period associated with the at least one
KPI.
16. The method of claim 14, wherein the at least one KPI includes
at least one of a tripping speed, a tripping connection time, a
drill connection time, a rate of penetration (ROP), a casing
running speed, a casing connection time, a blow out preventer (BOP)
work time period, a rig maintenance time, a Bottom Hole Assembly
(BHA) handling time, a cementing time, and a circulating time.
17. The method of claim 14, further comprising defining a first
operating time period for the drilling rig.
18. The method of claim 17, further comprising calculating an ILT
percentage by dividing the ILT period by the first operating time
period.
19. The method of claim 14, further comprising calculating, with
the controller, an Invisible Saved Time (IST) period based on the
difference between the at least one performance time period and the
at least one target time period; and outputting the IST period to a
user on an output device or a report generated for the user.
20. The method of claim 19, further comprising calculating an IST
percentage by dividing the IST period by a first operating time
period.
21. A drilling rig comprising: a sensor system located on the
drilling rig and arranged to measure one or more parameters of the
drilling rig, the one or more parameters including a weight on bit,
a bit depth, a hole depth, a hookload, a block height, a flow rate,
a pump pressure, a top drive torque, and a top drive RPM; a
controller in communication with the sensor system, the controller
operable to receive measurements of the one or more parameters from
the sensor system, the controller operable to generate an
efficiency report for the drilling rig which includes a comparison
of a measured time period to complete a task during a drilling
operation on the drilling rig based on the one or more parameters
with an efficiency target for the one or more parameters, the
controller further operable to calculate an Invisible Lost Time
(ILT) period based on a difference between the measured time period
and the efficiency target; and an output device in communication
with the controller, the output device configured to output to a
user the efficiency report and the ILT period, the output device
further configured to control a drilling rig function comprising
moving at least a portion of the drilling rig based on the
efficiency report.
22. The drilling rig of claim 21, wherein the controller is further
operable to calculate an Invisible Saved Time (IST) period based on
the difference between the one or more parameters and the
efficiency target.
23. The drilling rig of claim 21, wherein the efficiency target
includes data from at least one measured parameter from a second
drilling rig.
Description
TECHNICAL FIELD
[0001] The present disclosure is directed to systems, devices, and
methods for tracking the efficiency of a drilling rig.
BACKGROUND OF THE DISCLOSURE
[0002] Drilling operations are generally highly time-sensitive.
Generally, the objective of a drilling operation is to drill as
quickly as possible under the safety, technological, operational,
and quality restraints associated with the drilling operation. To
maximize the speed at which the drilling operation occurs, drillers
typically establish a drilling plan that includes time estimates to
accomplish various tasks at the outset of the drilling operation.
These estimates may include Bit on Bottom Time (BOBT) and Flat Time
(FT) estimates. BOBT may be defined as the total time the drill bit
will take to drill a wellhole according to a drill plan. FT may be
defined as the time necessary to construct a well not including the
BOBT. More specifically, FT may include time required to handle
tubulars and other components, running casing, blow out preventer
(BOP) installation and maintenance, bottom hole assembly (BHA)
handling, tripping, and other procedures.
[0003] Besides calculated time constraints, drilling operations are
often delayed by unexpected time losses. These may include Downtime
(DT) and Invisible Lost Time (ILT). DT includes unexpected problems
that arise during a drilling operation, including accidents, tool
failures, supply problems, unexpected environmental conditions,
hole problems, and others. BOBT, FT, and DT are generally tracked
with the time estimates, and may appear on drilling reports (such
as rig morning reports, operations reports, tour reports, mud
reports, or cuttings analyses) or on downhole and surface
measurements. In contrast, ILT is generally not tracked during a
drilling operation. Drilling operators generally seek to minimize
time losses associated with expected or unexpected events.
Accordingly, better and more efficient time management technologies
are needed.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] 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.
[0005] FIG. 1 is a schematic of an exemplary drilling apparatus
according to one or more aspects of the present disclosure.
[0006] FIG. 2 is a schematic of an exemplary drilling apparatus
system according to one or more aspects of the present
disclosure.
[0007] FIG. 3 is a flowchart diagram of a method of calculating an
efficiency of a drilling operation according to one or more aspects
of the present disclosure.
[0008] FIG. 4 is a flowchart diagram of a method of generating a
report for a user according to or more aspects of the present
disclosure.
[0009] FIG. 5 is a representation of an exemplary display showing
ILT and IST measurements according to one or more aspects of the
present disclosure.
[0010] FIG. 6 is a representation of an exemplary display showing a
report according to one or more aspects of the present
disclosure.
[0011] FIG. 7A is a representation of an exemplary efficiency
tracking chart according to one or more aspects of the present
disclosure.
[0012] FIG. 7B is a representation of another exemplary efficiency
tracking chart according to one or more aspects of the present
disclosure.
[0013] FIG. 7C is a representation of another exemplary efficiency
tracking chart according to one or more aspects of the present
disclosure.
[0014] FIG. 7D is a representation of another exemplary efficiency
tracking chart according to one or more aspects of the present
disclosure.
[0015] FIG. 8 is a representation of an exemplary savings estimate
chart according to one or more aspects of the present
disclosure.
DETAILED DESCRIPTION
[0016] It is to be understood that the following disclosure
provides many different implementations, or examples, for
implementing different features of various implementations.
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 implementations and/or
configurations discussed.
[0017] The systems and methods disclosed herein enable users to
identify and track efficiency and inefficiencies of a drilling
process. In particular, the present disclosure provides for the
tracking of time losses from various sources and the creation of a
time loss report showing system efficiency. The time losses may be
calculated using sensor readings and other input data.
[0018] In particular, drilling operations usually begin with the
identification of a target location, and an optimal wellbore
profile or drill plan is typically established before drilling
commences. Such proposed drill plans are generally based on
optimizing drilling time to reach hydrocarbons and achieve a
producing well. The proposed drill plan generally takes into
account time constraints associated with various tasks that are
required to meet the goals of the drill plan. As drilling proceeds,
expected and unexpected time losses may occur for a variety of
reasons. The devices, systems, and methods disclosed herein may
allow for the tracking of previously unrecorded ILT and IST periods
and systems for reporting these time losses and time savings.
[0019] ILT may represent the difference between the actual time
taken to complete a drilling operation and a target time to
complete the drilling operation. The target time may be based upon
configurable performance targets, previous drilling operations,
and/or drilling operations of other wells that are similar to the
present well. The target time may represent an efficiency target.
Although ILT makes up a substantial portion of the delays on
drilling rigs, delays associated with ILT are not tracked on any
reports in conventional drilling rigs.
[0020] Operators may be interested in tracking which parts of an
operation exceed expectations. In that regard, Invisible Saved Time
(IST) may include time saved during an operation as compared to a
target. The systems, devices, and methods described herein may
allow for the identification, tracking, and application of ILT and
IST periods to improve the efficiency of drilling operations.
[0021] 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.
[0022] 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 in and out 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.
[0023] A hook 135 may be attached to the bottom of the traveling
block 120. A top drive 140 may be suspended from the hook 135. A
quill 145 extending from the top drive 140 may be attached to a
saver sub 150, which may be attached to a drill string 155
suspended within a wellbore 160. Alternatively, the quill 145 may
be attached to the drill string 155 directly. 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 shaft, 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."
[0024] The drill string 155 may include interconnected sections of
drill pipe 165, a bottom hole assembly (BHA) 170, and a drill bit
175. The BHA 170 may include stabilizers, drill collars, and/or
measurement-while-drilling (MWD) instruments, among other
components. For the purpose of slide drilling the drill string may
include a downhole motor with a bent housing or other bend
component, operable to create an off-center departure of the bit
from the center line of the wellbore. The direction of this
departure in a plane normal to the wellbore is referred to as the
toolface angle or toolface. The drill bit 175, which may also be
referred to herein as a "tool," or a "toolface," may be connected
to the bottom of the BHA 170 or 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, which may be
connected to the top drive 140.
[0025] The downhole MWD 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 memory, such as solid-state memory, for some period of
time, and downloaded from the instrument(s) when at the surface
and/or transmitted in 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, transmission as electromagnetic pulses,
among other methods. The MWD sensors or detectors 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. In some implementations, the MWD sensors
may be used to evaluate efficiency and identify time losses
associated with the drilling operation.
[0026] In an exemplary implementation, the apparatus 100 may also
include a blow out preventer (BOP) 158 (which may include a
rotating head or diverter) that may assist when the well 160 is
being drilled utilizing under-balanced or managed-pressure drilling
methods. The apparatus 100 may also include a surface casing
annular pressure sensor 159 configured to detect the pressure in an
annulus defined between, for example, the wellbore 160 (or casing
therein) and the drill string 155.
[0027] In the exemplary implementation 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.
[0028] 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 implementation, the controller 190 includes one or more
systems located in a control room in communication with 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.
[0029] 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. Depending on the implementation, 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 an 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. Measurements from the downhole annular pressure sensor
170a may include both static annular pressure (pumps off) and
active annular pressure (pumps on).
[0030] 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.
[0031] The apparatus 100 may additionally or alternatively include
a shock/vibration sensor 170b that is configured to detect 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 drill 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 drill bit 175 by the one or more
motors 172.
[0032] 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.
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 170c may 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.
[0033] 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.
[0034] The top drive 140, drawworks 130, 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 may 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 may
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, drawworks
130, or other component of the apparatus 100.
[0035] 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 interfaces which may be local at the well/rig
site or located at another, remote location with a network link to
the system.
[0036] Referring to FIG. 2, illustrated is a block diagram of an
apparatus 200 according to one or more aspects of the present
disclosure. The apparatus 200 may include a user interface 260, a
BHA 210, a drive system 230, a drawworks 240, a deadline anchor
254, a mud pump 256, a controller 252, and a database 270. The
apparatus 200 may be implemented within the environment and/or
apparatus 100 shown in FIG. 1. For example, the BHA 210 may be
substantially similar to the BHA 170 shown in FIG. 1, the drive
system 230 may be substantially similar to the top drive 140 shown
in FIG. 1, the drawworks 240 may be substantially similar to the
drawworks 130 shown in FIG. 1, and the controller 252 may be
substantially similar to the controller 190 shown in FIG. 1.
[0037] The BHA 210, the drive system 230, the drawworks 240, the
deadline anchor 254, and the mud pump 256 may contain sensors that
measure various characteristics or qualities of the drilling rig.
These sensors may transmit readings to the various controllers 236,
242, 252 to be analyzed. In some implementations, the sensor
readings may be used to track the efficiency of a drilling
operation on the drilling rig. In particular, the sensor readings
may be analyzed to measure invisible lost time (ILT) periods or
invisible saved time (IST) periods.
[0038] The BHA 210 may include an MWD casing pressure sensor 212
that is configured to detect an annular pressure value or range at
or near the MWD portion of the BHA 210, and that may be
substantially similar to the downhole annular pressure sensor 170a
shown in FIG. 1. The casing pressure data detected via the MWD
casing pressure sensor 212 may be sent via electronic signal to the
controller 252 via wired or wireless transmission.
[0039] The BHA 210 may also include an MWD shock/vibration sensor
214 that is configured to detect shock and/or vibration in the MWD
portion of the BHA 210, 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
214 may be sent via electronic signal to the controller 252 via
wired or wireless transmission.
[0040] The BHA 210 may also include a mud motor pressure (.DELTA.P)
sensor 216 that is configured to detect a pressure differential
value or range across the mud motor of the BHA 210, 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 216 may be sent via electronic signal to the
controller 252 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.
[0041] The BHA 210 may also include a magnetic toolface sensor 218
and a gravity toolface sensor 220 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 218 may be or include a conventional
or future-developed magnetic toolface sensor which detects toolface
orientation relative to magnetic north. The gravity toolface sensor
220 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 implementation, the
magnetic toolface sensor 218 may detect the current toolface when
the end of the wellbore is less than about 7.degree. from vertical,
and the gravity toolface sensor 220 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., magnetic toolface sensor 218 and/or gravity
toolface sensor 220) may be sent via electronic signal to the
controller 252 via wired or wireless transmission.
[0042] The BHA 210 may also include an MWD torque sensor 222 that
is configured to detect a value or range of values for torque
applied to the bit by the motor(s) of the BHA 210, and that may be
substantially similar to the torque sensor 172b shown in FIG. 1.
The torque data detected via the MWD torque sensor 222 may be sent
via electronic signal to the controller 252 via wired or wireless
transmission. The BHA 210 may also include a MWD WOB sensor 224
that is configured to detect a value or range of values for WOB at
or near the BHA 210, and that may be substantially similar to the
WOB sensor 170d shown in FIG. 1. The WOB data detected via the MWD
WOB sensor 224 may be sent via electronic signal to the controller
252 via wired or wireless transmission.
[0043] The drive system 230 may include a surface torque/rpm sensor
232, a quill position sensor 234, and a controller 236. The surface
torque/rpm sensor 232 may be 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 surface torque/rpm
sensor 232 may also be configured to measure the rotation speed of
the quill or drill string. In some implementations, the surface
torque/rpm sensor 232 includes a single sensor that is operable to
measure torque and rotation speed, while in other implementations,
the surface torque/rpm sensor 232 includes two or more sensors that
individually measure the torque and rotation speed. The drive
system 230 may also include a quill position sensor 234 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, rotation speed, and quill position
data detected via the surface torque/rpm sensor 232 and the quill
position sensor 234, respectively, may be sent via electronic
signal to the controller 252 via wired or wireless transmission.
The drive system 230 also includes a controller 236 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 230 (such as the quill 145 shown in FIG. 1).
[0044] The drawworks 240 may include a position sensor 244 and a
controller 242 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 240 (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. The position sensor 244 may be operable to measure the
height of a drill string or the depth of a wellhole. The position
sensor 244 may be suitable for use on drilling rigs using a
traveling block 120 or a movable platform.
[0045] The deadline anchor 254 may include a load cell 246. The
load cell 246 may also be disposed on a hook, such as the hook 135
of FIG. 1. The load cell 246 may be operable to measure the weight
on a lifting system. The load cell 246 may also be configured for
use on a drilling rig with a movable platform. For example, some
drilling rigs may use a platform mounted on a rack and pinion
system as a primary lifting system. The load cell 246 may be used
to measure the weight of a drill string and other components on any
of these types of drilling rigs.
[0046] The mud pump 256 may include a flow sensor/stroke counter
258 which may be configured to measure the flow rate of fluid
issuing from the mud pump 256 as well as being configured to count
the strokes of the mud pump 256. In some implementations, the flow
sensor/stroke counter 258 is a single sensor device, while in other
implementations, the flow sensor/stroke counter 258 includes
several devices.
[0047] The controller 252 may be configured to receive one or more
of the above-described parameters from the user interface 260, the
BHA 210, the drive system 230, and/or the drawworks 240, and
utilize such parameters to continuously, periodically, or otherwise
determine efficiency metrics for the drilling rig. The controller
252 may be further configured to generate a control signal, such as
via intelligent adaptive control, and provide the control signal to
the drive system 230 and/or the drawworks 240 to adjust and/or
maintain a toolface orientation. For example, the controller 252
may provide one or more signals to the drive system 230 and/or the
drawworks 240 to increase or decrease WOB and/or quill position,
such as may be required to accurately "steer" the drilling
operation.
[0048] The user interface 260, controller 252, and database 270 may
be discrete components that are interconnected via wired or
wireless means. Alternatively, the user interface 260, controller
252, and database 270 may be integral components of a single system
or controller 250, as indicated by the dashed lines in FIG. 2.
[0049] The database 270 may be configured to store data for the
present well and drilling operation, as well as information about
wells and associated drilling rigs that share characteristics with
the present well and drilling rig. For example, the database 270
may be populated with data from wells nearby, wells having similar
geology, wells drilled to obtain similar types of hydrocarbons, or
wells operated by the same client. The database 270 may be any type
of reliable storage solution such as a RAID-based storage server,
an array of hard disks, a storage area network of interconnected
storage devices, an array of tape drives, or some other scalable
storage solution located either within a drilling rig or remotely
located (i.e., in the cloud).
[0050] The user interface 260 may include a user input 262, an
operations report input 264, a communication link 266, and a
display 268. The user interface 260 may be used to track the
efficiency of a drilling rig, produce reports, and communicate
efficiency results with others. In some implementations, the user
input 262 is used to input or more efficiency metrics or estimates.
For example, a user may input Key Performance Indicators (KPIs)
that refer to various metrics measured during a drilling procedure.
A user may also enter observed information about the well through
the user input 262 such as recorded times for various procedures,
the operator present, and estimated delays, as well as other types
of information. The user input 262 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 user input 262 may support
data input from local and/or remote locations. Alternatively, or
additionally, the user input 262 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
252 via the execution of one or more database look-up procedures.
In general, the user input 262 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.
[0051] The operations report input 264 may be used to input
operations reports, tour reports, and/or tour sheets. In
particular, operations reports include any report filled out by a
member of the rig crew detailing what activities the rig did during
a specified period of time. These may include IADC tour sheet
reports, CAODC tour sheet reports, daily morning reports, or other
company specific reports. In some implementations, operations
reports track operating times and Downtime (DT) for a drilling rig
and are updated regularly. In some implementations, operations
reports include DT information that is divided into separate
categories, such as DT for maintaining the top drive, DT for
repairing the drawworks, and DT for replacing a mud pump, for
example. Operations reports may be input through the operations
report input 264 at regular intervals, such as every hour, every
day, every week, every month, or at other intervals. Operations
reports may be automatically entered into the operations report
input 264. In some implementations, operations reports or tour
reports from several wells are input into the operations report
input 264.
[0052] The communication link 266 may be used to communicate
information between various components. In some implementations,
the communications link 266 may be operable to communicate across
networks, local area networks (LAN), wide area networks (WAN), the
Internet, satellite-links, and/or by radio communications, among
other means.
[0053] The display 268 may configured to display information to a
user. The display 268 may be any type of output device. In some
implementations, the display 268 is an electronic display device, a
text-based report, an electronic report, an email report, or a
printed report. In some implementations, the display 268 may be an
interface such as a computer screen. The display 268 may be used to
display analysis results, including operations reports, efficiency
diagrams, sensor readings, and measurements of ILT and IST, for
example. The display 268 may be used to display information such as
that shown in FIGS. 5-8.
[0054] FIG. 3 is a flow chart showing a method 300 of calculating
an ILT period and percentage and an IST period and percentage. The
calculation of these values may help a drilling rig operator
identify efficiency shortcomings as well as areas that are
performing well. In particular, the ILT and IST values are
calculated by analyzing sensor data and operations report data and
comparing that analysis to inputted data from other sources. The
sensor data is collected from various sensors on or around the
drilling well as well as operations reports. The sensors may track
various well functions. In some implementations, the well functions
include one or more KPIs that may be tracked for efficiency
measurement purposes. These KPIs may be measured and analyzed in
the method of claim 3, and are discussed in reference to FIGS. 4-6.
Exemplary KPIs may include tripping speed, tripping connection
time, drill connection time, rate of penetration (ROP), casing
running speed, and BOP work period. These KPIs may be measured in
steps 310, 312, 314, 316, 318, and 320 of method 300. Other KPIs
may include downtime, rig maintenance time, BHA handling time,
cementing, circulating, Run in Hole (RIH) connection time, total
RIH distance, Pull out of Hole (POOH) connection time, POOH
tripping speed, total POOH distance, casing connection, and Weight
to Weight connection time. The measurement of each KPI may include
intermediate steps, which are included within the dashed box of
each KPI.
[0055] At step 310, the method 300 may include measuring the
tripping speed of a drilling rig. Tripping may be defined as moving
pipe into or out of the well bore. The tripping speed may be
calculated by inputting sensor data from sensors on the drawworks
of the drilling rig (such as the position sensor 244 of FIG. 2), as
well as sensors on the deadline anchor (such as the load cell 246),
mud pumps (such as the mud motor pressure sensor 216), and top
drive (such as the surface torque/rpm sensor 232). This sensor data
may be collected when the sensor system and controller recognize
when tripping begins and ends. The tripping speed may then be
calculated for a selected and pre-established time period. In some
implementations, the tripping speed is calculated for one 12 hour
shift, also known as a tour. In other implementations, tripping
speed is measured for an hour, several hours, a day, or other time
periods.
[0056] At step 312, the method 300 may include measuring the
tripping connection time of a drilling rig. Tripping connection
time may be defined as the time required to connect or disconnect
tubulars during the tripping process. The tripping connection time
may be calculated by inputting sensor data from sensors on the
drawworks, rig floor, deadline anchor, and top drive of the
drilling rig such as the position sensor 244, load cell 246, or
surface torque/rpm sensor 232 of FIG. 2. This sensor data may be
collected when the sensor system and controller recognize when the
tripping connection process begins and ends. The tripping
connection time may then be calculated for a selected and
pre-established time period. In other implementations, tripping
time is measured for an hour, several hours, a day, or other time
periods.
[0057] At step 314, the method 300 may include measuring the
drilling connection time of a drilling rig. Drilling connection
time may be defined as the time required to connect or disconnect
tubulars and BHA components during the drilling process. The
drilling connection time may be calculated by inputting sensor data
from sensors on the drawworks, deadline anchor, rig floor, BHA, and
top drive of the drilling rig such as the position sensor 244, load
cell 246, or surface torque/rpm sensor 232 of FIG. 2. This sensor
data may be collected when the sensor system and controller
recognize when the drilling connection process begins and ends. The
drilling connection time may then be calculated for a selected and
pre-established time period. In some implementations, the drilling
connection time is calculated for one tour. In other
implementations, drilling connection time is measured for an hour,
several hours, a day, or other time periods.
[0058] At step 316, the method 300 may include measuring the ROP of
the drilling rig. ROP may be defined as the speed at which the BHA
"makes hole" or drills through the ground. In some implementations,
ROP may be further defined as the rotation rate of penetration
(which usually refers to vertical drilling operations) or slide
rate of penetration (which usually refers to drilling operations at
an angle, including horizontal drilling operations). The ROP may be
calculated by inputting sensor data from sensors on the drawworks,
BHA, mud pump, and top drive of the drilling rig, such as the
magnetic toolface sensor 218, the gravity toolface sensor 220, the
position sensor 244, the mud motor pressure sensor 216, and the
surface torque/rpm sensor 232 of FIG. 2. In some cases, the ROP is
also measured by inputting survey results that are generally taken
at certain increments of hole depth, such as every 100 feet. This
sensor data may be collected when the sensor system and controller
recognize movement of the BHA and associated drilling. The ROP may
then be calculated for a selected and pre-established time period.
In some implementations, the ROP is calculated for one tour. In
other implementations, ROP is measured for an hour, several hours,
a day, or other time periods.
[0059] At step 318, the method 300 may include measuring the casing
running speed of a drilling rig. Casing running speed may be
defined as the speed at which casing is run into the wellbore. The
casing running speed may be calculated by inputting sensor data
from sensors on the drive system, drawworks, or deadline anchor
such as the position sensor 244, surface torque/rpm sensor 232, and
load cell 246 of FIG. 2. This sensor data may be collected when the
sensor system and controller recognize when the casing running
process begins and ends. The casing running speed may then be
calculated for a selected and pre-established time period. In some
implementations, the casing running speed is calculated for one
tour. In other implementations, casing running speed is measured
for an hour, several hours, a day, or other time periods.
[0060] At step 320, the method 300 may include measuring time
associated with BOP work. BOP work may include the time required to
"nipple up" (e.g., install BOP components), "nipple down" (e.g.,
remove the entire BOP or BOP components), and test the BOP system.
BOP work time may be calculated by inputting operations report
data, identifying a category on the operations report associated
with BOP work, and calculating BOP work by category. The time
associated with BOP work may be calculated on a per event basis and
may be aggregated by well. The time associated with BOP work may
also be aggregated per tour, one hour, several hours, one day, one
week, one month, or other time periods.
[0061] At step 330, the method 300 may include inputting targets.
These targets may include estimated speeds, rates, and time periods
associated with each of the KPIs measured in steps 310, 312, 314,
316, 318, and 320. In some implementations, the targets include
data from similar wells (such as wells that are in the same area,
run by the same client, have the same drilling rig type, or are at
the same company level as the present well). In some
implementations, the target includes goals for each of the KPIs
that are slightly above normal operating standards. In some
implementations, the targets are based on the best time possible
for each KPI, or a best composite well time. Generating the target
will be discussed in more detail in reference to FIGS. 4, 5, 7 and
8.
[0062] At step 340 in FIG. 3, the method 300 may include the
comparing the values for each of the KPIs to corresponding values
from the targets. In some implementations, the measurement of the
KPIs in steps 310, 312, 314, 316, 318, and 320 may include multiple
drilling periods and multiple values. In this case, each of the
drilling periods may be compared to a corresponding target
value.
[0063] At step 342, KPI values that are better than the target
values may be used to calculate the IST period at step 344. In some
implementations, the IST period is calculated as the difference
between each of the KPI values and the target value. IST periods
for each of the KPIs are summed at step 346 to create a total IST
for the drilling rig for the time period. The IST period may show
the total amount of time saved at the drilling rig for the time
period.
[0064] At step 352, KPI values that are worse than the target
values may be used to calculate the ILT period at step 354. In some
implementations, the ILT period is calculated as the difference
between the each of the KPI values and the target value. The ILT
periods for each of the KPIs are summed at step 356 to create a
total ILT time for the drilling rig for the time period. The ILT
period may show the total amount of time lost at the drilling rig
for the time period.
[0065] At step 360, the user may input a time range representing a
period of drilling rig operation to be monitored. This time range
may be a tour, an hour, several hours, a day, or other time
periods. The time range may also be calculated for individual rigs,
operators, crews, and other groups. At step 370, operations reports
are input into the method. These operations reports may include
operations reports from the same time period as the function values
are measured. The operations reports may also include historical
tour sheets from the present well, as well as past or present tour
sheets from other, similar wells. The operations reports may also
contain information shown on display 600 of FIG. 6.
[0066] At step 380, the method 300 may include calculating the
operating time of the drilling rig. In some implementations, the
operating time may exclude move times for the drilling rig. At step
382, the method 300 may include calculating an IST percentage based
on the calculated operating time of step 380 and the summed IST and
ILT times. This calculation may include dividing the total IST time
by the operating time for the time period input by the user. At
step 392, the method 300 may include calculating an ILT percentage.
This calculation may include dividing the total ILT time by the
operating time for the time period input by the user.
[0067] In some implementations, the total ILT time and ILT
percentage may allow the user to see a categorized overview of time
lost on the drilling rig. This may help the user to target
improvements to the drilling process. Likewise, the total IST time
and IST percentage may allow the user to see which areas of the
drilling rig are functioning most efficiently.
[0068] FIG. 4 is a flow chart showing a method 400 of calculating a
best composite well time according to various aspects of the
present disclosure. The best composite well time may represent the
best time possible for a drilling rig on a well to complete a
drilling procedure. In some implementations, the best composite
well time is calculated for a specific type of drilling rig. For
example, the best composite time for a well may be calculated using
values from drilling rigs with similarities including location,
area, rig type, and operator. Once calculated, the best composite
well time may be used as an input target that may be entered at
step 330 of FIG. 3.
[0069] At step 410, the method 400 may include inputting user
selected information. The user selected information may include
selecting the location, area, rig type, client and/or company
owning a drilling rig. The user inputted information may help to
produce a relevant best composite well time for comparison with the
present well. The user selected information may be input into the
analysis system such as the controller 252 of FIG. 2 using a user
input 262 such as that depicted in FIG. 2.
[0070] At step 420, the method 400 may include retrieving well
information from a database. In some cases, the well information
may include operations reports, tour reports, drilling surveys, and
other information that is regularly gathered during a drilling
procedure. The well information may also include information
received by sensors associated with the drilling rig, such as those
discussed in reference to FIG. 2. In some implementations, the well
information is continually received by the analysis system. The
database may be the database 270 show in reference to FIG. 2.
[0071] At step 430, the method 400 may include inputting one or
more user selected KPIs including downtime, rig maintenance,
tripping speed, BHA handling time, casing/liner running speed,
running casing, cementing, circulating, BOP installation and
testing, ROP, and drilling connection time. In some
implementations, other KPIs associated with drilling rig efficiency
may also be input into the analysis system. In some
implementations, the KPIs chosen by the user may be based on
existing efficiency systems.
[0072] At step 440, the method 400 may include calculating minimum,
average, and maximum times associated with each user selected KPI.
This step may involve choosing fixed distances, quantities, and
time periods associated with the average well profile. For example,
the tripping speed may be measured during a 12-hour period at a
well with a minimum speed of 900 ft/hr, a maximum speed of 1,500
ft/hr, and an average speed of 1,000 ft/hr. The method may include
choosing a fixed distance for comparison purposes such as 10,000
ft. For this example, the maximum tripping speed time for the
drilling rig is 11.1 hours, the average time for the drilling rig
is 10 hours, and the minimum time for the drilling rig is 6.7
hours. The distances and time periods chosen for the various KPIs
may be varied so that the KPI times may be compared against KPIs at
other wells.
[0073] At step 450, the method 400 may include inputting minimum
times from other wells and associated drilling rigs. The other
wells and drilling rigs may have some basis for comparison to the
present drilling rig, such as a similar location or type. In some
implementations, the drilling rigs chosen for the comparison are
situated in the same area, owned or operated by the same client,
have the same rig type, are drilling in similar environmental
conditions, and/or are drilling through similar geology.
[0074] At step 460, the method 400 may include inputting an average
well duration for each KPI. This step may include further
specification of time frames for calculation purposes. For example,
the minimum time for tripping speed may be calculated in step 440
to be 6.7 hours, based on the fixed values of a 12-hour shift and a
distance of 10,000 ft. The well duration input at step 460 may be
set at a week. In this case, the method 400 may include multiplying
the minimum time of step 440 by the duration of step 460 for a
product of 46.7 hours.
[0075] At step 470, the method 400 may include calculating the
total time savings of all the KPI times. This may include comparing
the minimum KPI times calculated in step 440 to the minimum times
of other drilling rigs of step 450. If the minimum time for a
certain KPI is lower than the minimum time of other drilling rigs,
the difference between these minimum times is recorded as a time
saving period. The time saving periods of all the KPIs are then
added together to calculate the total time saving period. The time
savings periods of all the KPIs may be compared to the average well
duration of all wells in the dataset.
[0076] At step 480, the method 400 may include calculating a best
composite well time. This step may include determining the lowest
minimum time for each KPI from either the present drilling rig or
the other drilling rigs. These lowest minimum times for each KPI
are then added together to create the best composite time for the
drilling rig of the present well. In some implementations, the best
composite time may be used to represent an ideal drilling well with
similar characteristics to the present drilling well. In other
words, the best composite time may represent the "best case
scenario" for the present well.
[0077] At step 490, the method 400 may include transmitting a
report to a user containing the total time saving period and the
best composite time. The report may also contain the list of user
selected KPIs from step 430, the minimum, average, and maximum
times for each KPI from step 440, and the minimum times from other
wells from step 450. In some implementations, the report is
designed to allow the user to quickly assess the efficiency of the
drilling operation. In some implementations, the user is a driller
and the report is transmitted to a display device such as display
268 of FIG. 2. In some implementations, the report is used as a
target for other drilling operations and may be used, for example,
in step 330 of FIG. 3.
[0078] FIG. 5 is a representation of an exemplary display 500
showing ILT and IST measurements according to one or more aspects
of the present disclosure. In some implementations, the display 500
is a human-machine interface (HMI) according to one or more aspects
of the present disclosure. The display 500 may also represent a
report. The display 500 may be utilized and viewed by a human
operator during directional and/or other drilling operations to
measure and visualize IST and ILT values for various aspects of a
drilling operation. The display 500 may include windows and screens
that are selectably viewable 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. The display 500 may also be implemented as a
series of instructions recorded on a computer-readable medium. In
some implementations, the display 500 may be a user display such as
the display 268 depicted in FIG. 2.
[0079] The display 500 may receive sensor data from one or more
sensors associated with a drilling system. In some implementations,
the display 500 shows IST and ILT periods associated with the
drilling system. The display 500 may include a window 502 showing
composite ILT and IST times 504. In some cases, the window 502
represents a section of a report. The composite ILT and IST times
504 may include total ILT and IST times associated with one or more
KPIs. KPI windows 520, 522, 524, 526, 528 may each be configured to
show rates and time periods associated with each KPI. In
particular, the display 500 may include a KPI window 520 for
tripping speed, a KPI window 522 for connection time, a KPI window
524 for drilling speed, a KPI window 526 for casing running speed,
and a KPI window 528 for other KPIs. In particular, the KPI window
528 may include BOP work measurements, skid rig measurements, and
other miscellaneous KPIs. Other KPIs may be represented in the
display, either in KPI window 528 or in other KPI windows.
[0080] The KPI windows 520, 522, 524, 526, 528 may include recorded
measurements for one or more drillers. In the example of FIG. 5,
four drillers (Drillers A, B, C, and D) are represented in KPI
windows 520, 522, 524, 526. KPI windows 520, 522, 524, 526 may also
include a target distance or speed. The targets may include
estimates of distance or speed from the present well or other
similar wells, such as the input targets discussed in reference to
step 330 of FIG. 3. In some implementations, the targets are based
on a best composite well time such as that discussed in reference
to FIG. 4. The KPI windows 520, 522, 524, 526 may also include
actual measurements that reflect the performance of each driller.
The comparisons of actual measurements with the targets for each
KPI may be used to produce an ILT period and IST period for each
driller. These periods are then added together to produce a total
ILT period and a total IST period for each KPI.
[0081] The display 500 may also include other visual
representations of ILT periods and IST periods. For example, pie
charts 510 and 512 may show the relative proportions of ILT periods
and IST periods associated with various KPIs. These pie charts 510,
512 may be used by a driller to help visualize where the largest
amount of time is being saved or lost during the drilling
operation. The display 500 may also include other visual
representations, such as bar graphs in windows 514 and 516. In
particular, window 514 may include a bar graph showing ILT periods
for each driller, and window 516 may include a bar graph showing
IST periods for each driller. Other visual representation may be
included in the display 500 including charts, graphs, spreadsheets,
histograms, time reports, and other display elements.
[0082] FIG. 6 is a representation of an exemplary display 600
showing operation performance details. The operation performance
details may include KPIs 610 as discussed in reference to FIGS. 4
and 5. In some implementations, the operation performance details
may help a driller to track the performance of a drilling rig in
reference to various KPIs 610 during one or more tours. The KPIs
610 may be chosen by a user and may include rotary drilling ROP,
sliding ROP, RIH connection time, RIH tripping speed, total RIH
distance, POOH connection time, POOH tripping speed, total POOH
distance, casing connection, casing running speed, Weight to Weight
connection time, and other measurements.
[0083] The operation performance details of display 600 may include
measurements for each KPI 610 for a day tour 620 and a night tour
630. An average 640 value may be included on the display 600 that
is calculated by averaging the measurements of the day tour 620 and
the night tour 630 together. A target 650 may also be included. In
some implementations, the target 650 includes the best composite
well time as discussed in reference to FIG. 4. The display 600 may
also include a measured ILT period 660 and a measured IST period
670 corresponding to each KPI 610. The ILT period and the IST
period may be calculated by comparing the measurements for each KPI
610 with the measurements for the target 650.
[0084] FIGS. 7A-7D show exemplary efficiency tracking charts. The
controller 252 of FIG. 2 or other controllers may calculate the
data shown on the charts and present it to a user. Charts with
similar data to FIGS. 7A-7D may be included in display 500 of FIG.
5 and display 600 of FIG. 6. In particular, the charts of 7A-7D may
depict measurements of various KPIs tracked for several operators
or rigs. The data displayed on these graphs may be used to generate
a best composite well time, as well as allowing a side by side
comparison of drillers.
[0085] FIG. 7A shows measurements of an average cased hole tripping
speed by operators A-F. The performance of the operators has been
recorded for several drilling operations and the ranges of the
performances are shown by bars at the ends of each bar.
[0086] FIG. 7B shows average tripping connection time measurements
for operators A-F. The performance of the operators has been
recorded for several drilling operations.
[0087] FIG. 7C shows average ROP time measurements for operators
A-F. The performance of the operators has been recorded for several
drilling operations.
[0088] FIG. 7D shows average drilling connection time measurements
for operators A-F. In some implementations, the measurements are
subdivided into separate sections for Weight to Slip time, Slip to
Slip time, and Slip to Weight time.
[0089] FIG. 8 shows a representation of an exemplary time savings
estimate chart 800 according to one or more aspects of the present
disclosure. The chart 800 may show time savings estimates during a
drilling operation that are broken down into various categories or
KPIs. In some implementations, the time savings estimates include
IST values that are calculated in by method 300 in FIG. 3. The KPIs
represented on the graph may be chosen by a user and may include
drilling connection time, tripping and connection times, casing and
cementing times, circulation time, BOP work time, and other KPIs.
The chart 800 may also shows include a best possible well time that
may be calculated in way similar to the best composite well time
described in method 400 of FIG. 4. The chart 800 may be depicted on
the display 500 of FIG. 5. In some implementations, the chart 800
may be used by a driller to visualize the relative time savings of
different activities on a drilling rig.
[0090] In view of all of the above and the figures, one of ordinary
skill in the art will readily recognize that the present disclosure
introduces a drilling apparatus that may include: a first sensor
system connected to the drilling apparatus and configured to detect
at least one measureable parameter of the drilling apparatus; a
data input system operable to receive an efficiency target; a
controller in communication with the first sensor system and the
data input system, the controller being operable to generate an
efficiency report for a drilling operation, the efficiency report
including at least one Key Performance Indicator (KPI) based on the
at least one measurable parameter, the controller further operable
to calculate an Invisible Lost Time (ILT) period based on a
difference between the at least one KPI and the efficiency target;
and an output device in communication with the controller, the
output device configured to output to a user the efficiency report
and the ILT period.
[0091] In some implementations, the controller is further operable
to calculate an Invisible Saved Time (IST) period based on the
difference between the at least one KPI and the efficiency target.
The at least one KPI may include at least one of a tripping speed,
a tripping connection time, a drill connection time, a rate of
penetration (ROP), a casing running speed, a casing connection
time, a blow out preventer (BOP) work time period, a rig
maintenance time, a Bottom Hole Assembly (BHA) handling time, a
cementing time, and a circulating time. In some implementations, at
least one KPI is based on measured data from an operations
report.
[0092] The controller may be further operable to generate a
plurality of time periods required to complete tasks on the
drilling apparatus based on each of the at least one KPI. The
efficiency target may be based on a best composite well time for
the drilling apparatus, wherein the best composite well time is
calculated by adding together a lowest time period of the plurality
of time periods based on each of the at least one KPI. The output
device may include at least one of a display, an email report, or a
printed report.
[0093] In some implementations, the efficiency target includes at
least one KPI from the second drilling apparatus based on the
measurable parameters from the second drilling apparatus. The
second drilling apparatus may have at least one feature in common
with the drilling apparatus including at least one of a common
drilling area, a common drilling client, a common rig type, a
common well type, a common geology, a common location, and a common
operator.
[0094] In some implementations, a drilling rig efficiency tracking
system is provided which may include: a data input system operable
to receive sensor data for a first drilling rig, an operations
report, and a efficiency target; a controller in communication with
the data input system, the controller operable to compare the
sensor data and the operations report to the efficiency target to
generate an efficiency report for the first drilling rig, the
efficiency report including an Invisible Lost Time (ILT) period
based on a comparison of the sensor data to the efficiency target;
and an output device in communication with the controller, the
output device configured to output the efficiency report to a
user.
[0095] In some implementations, the efficiency report further
includes an Invisible Saved Time (IST) period based on the
comparison of the sensor data to the efficiency report. The
efficiency target may include an operations report from a second
drilling rig. In some implementations, the second drilling rig has
at least one feature in common with the first drilling rig
including at least one of a common drilling area, a common drilling
client, a common rig type, a common well type, a common geology, a
common location, and a common operator.
[0096] In some implementations, a method for tracking efficiency of
a drilling rig is provided, which may include: receiving, with a
controller, at least one measurable parameter for a drilling
operation from a sensor system associated with the drilling rig;
generating at least one Key Performance Indicator (KPI) based on
the drilling operation; calculating, with the controller, at least
one performance time period for each of the at least one KPI based
on the at least one measureable parameter, receiving, with the
controller, at least one target time period; calculating, with the
controller, an Invisible Lost Time (ILT) period based on a
difference between the at least one performance time period and the
at least one target time period; and outputting the ILT period to a
user on an output device.
[0097] In some implementations, the at least one target time period
is based on a best composite well time for the drilling rig,
wherein the best composite well time is calculated by adding
together a lowest time period associated with the at least one KPI.
The at least one KPI may include at least one of a tripping speed,
a tripping connection time, a drill connection time, a rate of
penetration (ROP), a casing running speed, a casing connection
time, a blow out preventer (BOP) work time period, a rig
maintenance time, a Bottom Hole Assembly (BHA) handling time, a
cementing time, and a circulating time.
[0098] In some implementations, the method further includes
defining a first operating time period for the drilling rig. The
method may further include calculating an ILT percentage by
dividing the ILT period by the first operating time period. In some
implementations, the method may also include calculating, with the
controller, an Invisible Saved Time (IST) period based on the
difference between the at least one performance time period and the
at least one target time period; and outputting the IST period to a
user on an output device or a report generated for the user. The
method may also include calculating an IST percentage by dividing
the IST period by a first operating time period.
[0099] The foregoing outlines features of several implementations
so that a person of ordinary skill in the art may better understand
the aspects of the present disclosure. Such features may be
replaced by any one of numerous equivalent alternatives, only some
of which are disclosed herein. One 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 implementations introduced herein. One 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.
[0100] The Abstract at the end of this disclosure is provided to
comply with 37 C.F.R. .sctn.1.72(b) to allow the reader to quickly
ascertain the nature of the technical disclosure. It is submitted
with the understanding that it will not be used to interpret or
limit the scope or meaning of the claims.
[0101] Moreover, it is the express intention of the applicant not
to invoke 35 U.S.C. .sctn.112(f) for any limitations of any of the
claims herein, except for those in which the claim expressly uses
the word "means" together with an associated function.
* * * * *