Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 1 -
WELL DRILLING METHODS WITH AUTOMATED RESPONSE TO
EVENT DETECTION
TECHNICAL FIELD
The present disclosure relates generally to equipment
utilized and operations performed in conjunction with a
subterranean well and, in an embodiment described herein,
more particularly provides well drilling methods with
automated response to event detection.
BACKGROUND
It is desirable in drilling operations for certain
events to be identified as soon as they occur, so that any
needed remedial measures may be taken as soon as possible.
Events can also be normal, expected events, in which case it
would be desirable to be able to control the drilling
operations based on identification of such events.
Therefore, it will be appreciated that improvements
would be desirable in the art.
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 2 -
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic view of a well system which can
embody principles of the present disclosure.
FIG. 2 is a flowchart representing a method which
embodies principles of this disclosure.
FIG. 3 is a flowchart of an example of a parameter
signature generation process which may be used in the method
of FIG. 2.
FIG. 4 is a flowchart of an example of an event
signature generation and event identification process which
may be used in the method of FIG. 2.
FIG. 5 is a listing of events and corresponding event
signatures which may be used in the method of FIG. 2.
DETAILED DESCRIPTION
Representatively and schematically illustrated in FIG.
1 is a well drilling system 10 and associated method which
can incorporate principles of the present disclosure. In the
system 10, a wellbore 12 is drilled by rotating a drill bit
14 on an end of a drill string 16. Drilling fluid 18,
commonly known as mud, is circulated downward through the
drill string 16, out the drill bit 14 and upward through an
annulus 20 formed between the drill string and the wellbore
12, in order to cool the drill bit, lubricate the drill
string, remove cuttings and provide a measure of bottom hole
pressure control. A non-return valve 21 (typically a
flapper-type check valve) prevents flow of the drilling
fluid 18 upward through the drill string 16 (e.g., when
connections are being made in the drill string).
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 3 -
Control of bottom hole pressure is very important in
managed pressure drilling, and in other types of drilling
operations. Preferably, the bottom hole pressure is
accurately controlled to prevent excessive loss of fluid
into the earth formation surrounding the wellbore 12,
undesired fracturing of the formation, undesired influx of
formation fluids into the wellbore, etc. In typical managed
pressure drilling, it is desired to maintain the bottom hole
pressure just greater than a pore pressure of the formation,
without exceeding a fracture pressure of the formation. In
typical underbalanced drilling, it is desired to maintain
the bottom hole pressure somewhat less than the pore
pressure, thereby obtaining a controlled influx of fluid
from the formation.
Nitrogen or another gas, or another lighter weight
fluid, may be added to the drilling fluid 18 for pressure
control. This technique is useful, for example, in
underbalanced drilling operations.
In the system 10, additional control over the bottom
hole pressure is obtained by closing off the annulus 20
(e.g., isolating it from communication with the atmosphere
and enabling the annulus to be pressurized at or near the
surface) using a rotating control device 22 (RCD). The RCD
22 seals about the drill string 16 above a wellhead 24.
Although not shown in FIG. 1, the drill string 16 would
extend upwardly through the RCD 22 for connection to, for
example, a rotary table (not shown), a standpipe line 26,
kelley (not shown), a top drive and/or other conventional
drilling equipment.
The drilling fluid 18 exits the wellhead 24 via a wing
valve 28 in communication with the annulus 20 below the RCD
22. The fluid 18 then flows through drilling fluid return
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 4 -
lines 30, 73 to a choke manifold 32, which includes
redundant chokes 34 (only one of which may be used at a
time). Backpressure is applied to the annulus 20 by variably
restricting flow of the fluid 18 through the operative
choke(s) 34.
The greater the restriction to flow through the choke
34, the greater the backpressure applied to the annulus 20.
Thus, bottom hole pressure can be conveniently regulated by
varying the backpressure applied to the annulus 20. A
hydraulics model can be used to determine a pressure applied
to the annulus 20 at or near the surface which will result
in a desired bottom hole pressure, so that an operator (or
an automated control system) can readily determine how to
regulate the pressure applied to the annulus at or near the
surface (which can be conveniently measured) in order to
obtain the desired bottom hole pressure.
Pressure applied to the annulus 20 can be measured at
or near the surface via a variety of pressure sensors 36,
38, 40, each of which is in communication with the annulus.
Pressure sensor 36 senses pressure below the RCD 22, but
above a blowout preventer (BOP) stack 42. Pressure sensor 38
senses pressure in the wellhead below the BOP stack 42.
Pressure sensor 40 senses pressure in the drilling fluid
return lines 30, 73 upstream of the choke manifold 32.
Another pressure sensor 44 senses pressure in the
drilling fluid injection (standpipe) line 26. Yet another
pressure sensor 46 senses pressure downstream of the choke
manifold 32, but upstream of a separator 48, shaker 50 and
mud pit 52. Additional sensors include temperature sensors
54, 56, Coriolis flowmeter 58, and flowmeters 62, 64, 66.
Not all of these sensors are necessary. For example,
the system 10 could include only two of the three flowmeters
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
-5-
62, 64, 66. However, input from the sensors is useful to the
hydraulics model in determining what the pressure applied to
the annulus 20 should be during the drilling operation.
Furthermore, the drill string 16 may include its own
sensors 60, for example, to directly measure bottom hole
pressure. Such sensors 60 may be of the type known to those
skilled in the art as pressure while drilling (PWD),
measurement while drilling (MWD) and/or logging while
drilling (LWD) systems. These drill string sensor systems
generally provide at least pressure measurement, and may
also provide temperature measurement, detection of drill
string characteristics (such as vibration, torque, rpm,
weight on bit, stick-slip, etc.), formation characteristics
(such as resistivity, density, etc.), fluid characteristics
and/or other measurements. Various forms of telemetry
(acoustic, pressure pulse, electromagnetic, etc.) may be
used to transmit the downhole sensor measurements to the
surface.
Additional sensors could be included in the system 10,
if desired. For example, another flowmeter 67 could be used
to measure the rate of flow of the fluid 18 exiting the
wellhead 24, another Coriolis flowmeter (not shown) could be
interconnected directly upstream or downstream of a rig mud
pump 68, etc. Pressure and level sensors could be used with
the separator 48, level sensors could be used to indicate a
volume of drilling fluid in the mud pit 52, etc.
Fewer sensors could be included in the system 10, if
desired. For example, the output of the rig mud pump 68
could be determined by counting pump strokes, instead of by
using flowmeter 62 or any other flowmeters.
Note that the separator 48 could be a 3 or 4 phase
separator, or a mud gas separator (sometimes referred to as
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 6 -
a "poor boy degasser"). However, the separator 48 is not
necessarily used in the system 10.
The drilling fluid 18 is pumped through the standpipe
line 26 and into the interior of the drill string 16 by the
rig mud pump 68. The pump 68 receives the fluid 18 from the
mud pit 52 and flows it via a standpipe manifold 70 to the
standpipe 26, the fluid then circulates downward through the
drill string 16, upward through the annulus 20, through the
drilling fluid return lines 30, 73, through the choke
manifold 32, and then via the separator 48 and shaker 50 to
the mud pit 52 for conditioning and recirculation.
Note that, in the system 10 as so far described above,
the choke 34 cannot be used to control backpressure applied
to the annulus 20 for control of the bottom hole pressure,
unless the fluid 18 is flowing through the choke. In
conventional overbalanced drilling operations, such a
situation will arise whenever a connection is made in the
drill string 16 (e.g., to add another length of drill pipe
to the drill string as the wellbore 12 is drilled deeper),
and the lack of circulation will require that bottom hole
pressure be regulated solely by the density of the fluid 18.
In the system 10, however, flow of the fluid 18 through
the choke 34 can be maintained, even though the fluid does
not circulate through the drill string 16 and annulus 20,
while a connection is being made in the drill string. Thus,
pressure can still be applied to the annulus 20 by
restricting flow of the fluid 18 through the choke 34, even
though a separate backpressure pump may not be used.
Instead, the fluid 18 is flowed from the pump 68 to the
choke manifold 32 via a bypass line 72, 75 when a connection
is made in the drill string 16. Thus, the fluid 18 can
bypass the standpipe line 26, drill string 16 and annulus
CA 02841771 2015-10-28
-7-
20, and can flow directly from the pump 68 to the mud return
line 30, which remains in communication with the annulus 20.
Restriction of this flow by the choke 34 will thereby cause
pressure to be applied to the annulus 20.
As depicted in FIG. 1, both of the bypass line 75 and the
mud return line 30 are in communication with the annulus 20
via a single line 73. However, the bypass line 75 and the mud
return line 30 could instead be separately connected to the
wellhead 24, for example, using an additional wing valve
(e.g., below the ROD 22), in which case each of the lines 30,
75 would be directly in communication with the annulus 20.
Although this might require some additional plumbing at the
rig site, the effect on the annulus pressure would be
essentially the same as connecting the bypass line 75 and the
mud return line 30 to the common line 73. Thus, it should be
appreciated that various different configurations of the
components of the system 10 may be used.
Flow of the fluid 18 through the bypass line 72, 75 is
regulated by a choke or other type of flow control device 74.
Line 72 is upstream of the bypass flow control device 74, and
line 75 is downstream of the bypass flow control device.
Flow of the fluid 18 through the standpipe line 26 is
substantially controlled by a valve or other type of flow
control device 76. Note that the flow control devices 74, 76
are independently controllable, which provides substantial
benefits to the system 10, as described more fully below.
Since the rate of flow of the fluid 18 through each of
the standpipe and bypass lines 26, 72 is useful in determining
how bottom hole pressure is affected by these flows, the
flowmeters 64, 66 are depicted in FIG. 1 as being
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 8 -
interconnected in these lines. However, the rate of flow
through the standpipe line 26 could be determined even if
only the flowmeters 62, 64 were used, and the rate of flow
through the bypass line 72 could be determined even if only
the flowmeters 62, 66 were used. Thus, it should be
understood that it is not necessary for the system 10 to
include all of the sensors depicted in FIG. 1 and described
herein, and the system could instead include additional
sensors, different combinations and/or types of sensors,
etc.
A bypass flow control device 78 and flow restrictor 80
may be used for filling the standpipe line 26 and drill
string 16 after a connection is made, and equalizing
pressure between the standpipe line and mud return lines 30,
73 prior to opening the flow control device 76. Otherwise,
sudden opening of the flow control device 76 prior to the
standpipe line 26 and drill string 16 being filled and
pressurized with the fluid 18 could cause an undesirable
pressure transient in the annulus 20 (e.g., due to flow to
the choke manifold 32 temporarily being lost while the
standpipe line and drill string fill with fluid, etc.).
By opening the standpipe bypass flow control device 78
after a connection is made, the fluid 18 is permitted to
fill the standpipe line 26 and drill string 16 while a
substantial majority of the fluid continues to flow through
the bypass line 72, thereby enabling continued controlled
application of pressure to the annulus 20. After the
pressure in the standpipe line 26 has equalized with the
pressure in the mud return lines 30, 73 and bypass line 75,
the flow control device 76 can be opened, and then the flow
control device 74 can be closed to slowly divert a greater
proportion of the fluid 18 from the bypass line 72 to the
standpipe line 26.
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 9 -
Before a connection is made in the drill string 16, a
similar process can be performed, except in reverse, to
gradually divert flow of the fluid 18 from the standpipe
line 26 to the bypass line 72 in preparation for adding more
drill pipe to the drill string 16. That is, the flow control
device 74 can be gradually opened to slowly divert a greater
proportion of the fluid 18 from the standpipe line 26 to the
bypass line 72, and then the flow control device 76 can be
closed.
Note that the flow control device 78 and flow
restrictor 80 could be integrated into a single element
(e.g., a flow control device having a flow restriction
therein), and the flow control devices 76, 78 could be
integrated into a single flow control device 81 (e.g., a
single choke which can gradually open to slowly fill and
pressurize the standpipe line 26 and drill string 16 after a
drill pipe connection is made, and then open fully to allow
maximum flow while drilling).
However, since typical conventional drilling rigs are
equipped with the flow control device 76 in the form of a
valve in the standpipe manifold 70, and use of the standpipe
valve is incorporated into usual drilling practices, the
individually operable flow control devices 76, 78 are
presently preferred. The flow control devices 76, 78 are at
times referred to collectively below as though they are the
single flow control device 81, but it should be understood
that the flow control device 81 can include the individual
flow control devices 76, 78.
Note that the system 10 could include a backpressure
pump (not shown) for applying pressure to the annulus 20 and
drilling fluid return line 30 upstream of the choke manifold
32, if desired. The backpressure pump could be used instead
CA 02841771 2015-10-28
-10-
of, or in addition to, the bypass line 72 and flow control
device 74 to ensure that fluid continues to flow through the
choke manifold 32 during events such as making connections in
the drill string 16. In that case, additional sensors may be
used to, for example, monitor the pressure and flow rate
output of the backpressure pump.
The use of a backpressure pump is described in
International Application No. PCT/US10/38586, filed 15 June
2010. That international application also describes a method
of correcting an annulus pressure setpoint during drilling.
In other examples, connections may not be made in the
drill string 16 during drilling, for example, if the drill
string comprises a coiled tubing. The drill string 16 could be
provided with conductors and/other lines (e.g., in a sidewall
or interior of the drill string) for transmitting data,
commands, pressure, etc. between downhole and the surface
(e.g., for communication with the sensors 60).
Methods of controlling pressure and flow in drilling
operations, including the use of data validation and a
predictive device, are described in International Application
No. PCT/US10/56433, filed 12 November 2010.
Referring additionally now to FIG. 2, a well drilling
method 90 which may be used with the system 10 of FIG. 1 is
schematically illustrated. However, it should be clearly
understood that the method 90 could be used in conjunction
with other systems.
The method 90 includes an event detection process which
can be used to alert an operator if an event occurs, such as,
by triggering an alarm or displaying a warning if the event is
an undesired event (e.g., unacceptable fluid loss to the
formation, unacceptable fluid influx from the
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 11 -
formation into the wellbore, etc.), or by displaying
information about the event if it is a normal, expected or
desired event, etc. Well drilling methods incorporating
event detection are described in International Application
No. PCT/US09/52227, filed 30 July 2009.
An event can be a precursor to another event happening,
in which case detection of the first event can be used as an
indication that the second event is about to happen or is in
process of occurring. In addition, a series of events can
also provide an indication that another event is about to
happen. Thus, one or more prior events can be used as a
source of data for determining if another event will occur.
Many different events and types of events can be
detected in the method 90. These events can include, but are
not limited to, a kick (influx), partial fluid loss, total
fluid loss, standpipe bleed down, plugged choke, washed out
choke, poor hole cleaning (wellbore packed off about drill
string), downhole crossf low, wellbore washout, under gauged
wellbore, drilling break, ballooning while circulating,
ballooning while mud pump is off, stuck pipe, twisted off
pipe, back off, plugging of bit nozzle, bit nozzle washed
out, leak in surface processing equipment, rig pump failure,
backpressure pump failure, downhole sensor 60 failure,
washed out drill string, non-return valve failure, start of
drill pipe connection, drill pipe connection finished, etc.
In order to detect the events, drilling parameter
"signatures" produced in real time are compared to a set of
event "signatures" in order to determine if any of the
events represented by those event signatures is occurring.
Thus, what is happening now in the drilling operation (the
drilling parameter signatures) is compared to a set of
signatures which correspond to drilling events and, if there
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 12 -
is a match, this is an indication that the event
corresponding to the matched event signature is occurring.
Drilling properties (e.g., pressure temperature, flow
rate, etc.) are sensed by sensors, and output from the
sensors is used to supply data indicative of the drilling
properties. This drilling property data is used to determine
drilling parameters of interest.
Data can also be in the form of data from offset wells
(e.g., other wells drilled nearby or in similar lithologies,
conditions, etc.). Previous experience of drillers can also
serve as a source for the data. Data can also be entered by
an operator prior to or during the drilling operation.
A drilling parameter can comprise data related to a
single drilling property, or a parameter can comprise a
ratio, product, difference, sum or other function of data
related to multiple drilling properties. For example, it is
useful in drilling operations to monitor the difference
between the flow rate of drilling fluid injected into the
well (e.g., via the standpipe line 26 as sensed by flowmeter
66) and the flow rate of drilling fluid returned from the
well (e.g., via the drilling fluid return line 30 as sensed
by the flowmeter 67). Thus, a parameter of interest, which
can be used to define a part or segment of a signature can
be this difference in drilling properties (flow rate in -
flow rate out).
During a drilling operation, the drilling properties
are sensed over time, either continuously or intermittently.
Thus, data related to the drilling properties is available
over time, and the behavior of each drilling parameter can
be evaluated in real time. Of particular interest in the
method 90 is how the drilling parameters change over time,
that is, whether each parameter is increasing, decreasing,
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 13 -
remaining substantially the same, remaining within a certain
range, exceeding a maximum, falling below a minimum, etc.
These parameter behaviors are given appropriate values,
and the values are combined to generate parameter signatures
indicative of what is occurring in real time during the
drilling operation. For example, one segment of a parameter
signature could indicate that standpipe pressure (e.g., as
measured by sensor 44) is increasing, and another segment of
the parameter signature could indicate that pressure
upstream of the choke manifold (e.g., as measured by sensor
40) is decreasing.
A parameter signature can include many (perhaps 20 or
more) of these segments. Thus, a parameter signature can
provide a "snapshot" of what is happening in real time
during the drilling operation.
An event signature, on the other hand, does not
represent what is occurring in real time during a drilling
operation. Instead, an event signature is representative of
what the drilling parameter behaviors will be when the
corresponding event does happen. Each event signature is
distinctive, because each event is indicated by a
distinctive combination of parameter behaviors.
As discussed above, an event can be a precursor to
another event. In that case, the event signature for the
first event can be a distinctive combination of parameter
behaviors which indicate that the second event is about to
(or at least is eventually going to) happen.
Events can be parameters, for example, in the
circumstance discussed above in which a series of events can
indicate that another event is going to happen. In that
case, the corresponding parameter behavior can be whether or
not the precursor event(s) have happened.
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 14 -
Event signatures can be generated prior to commencing a
drilling operation, and can be based on experience gained
from drilling similar wells under similar conditions, etc.
Event signatures can also be refined as a drilling operation
progresses and more experience is gained on the well being
drilled.
In basic terms, sensors are used to sense drilling
properties during a drilling operation, data relating to the
sensed properties are used to determine drilling parameters
of interest, values indicative of the behaviors of these
parameters are combined to form parameter signatures, and
the parameter signatures are compared to pre-defined event
signatures to detect whether any of the corresponding events
is occurring, or is substantially likely to occur.
Steps in the event detection process are schematically
represented in FIG. 2 in flowchart form. However, it should
be understood that the method 90 can include additional,
alternative or optional steps as well, and it is not
necessary for all of the depicted steps to be performed in
keeping with the principles of this disclosure.
In a first step 92 depicted in FIG. 2, data is
received. The data in this example is received from a
central database, such as an INSITE" database utilized by
Halliburton Energy Services, Inc. of Houston, Texas USA,
although other databases may be used if desired.
The data typically is in the form of measurements of
drilling properties as sensed by various sensors during a
drilling operation. For example, the sensors 36, 38, 40, 44,
46, 54, 56, 58, 60, 62, 64, 66, 67, as well as other
sensors, will produce indications of various properties
(such as pressure, temperature, mass or volumetric flow
rate, density, resistivity, rpm, torque, weight, position,
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 15 -
etc.), which will be stored as data in the database.
Calibration, conversion and/or other operations may be
performed for the data prior to the data being received from
the database.
The data may also be entered manually by an operator.
As another alternative, data can be received directly from
one or more sensors, or from another data acquisition
system, whether or not the data originates from sensor
measurements, and without first being stored in a separate
database. Furthermore, as discussed above, the data can be
derived from an offset well, previous experience, etc. Any
source for the data may be used, in keeping with the
principles of this disclosure.
In step 94, various parameter values are calculated for
later use in the method 90. For example, it may be desirable
to calculate a ratio of data values, a sum of data values, a
difference between data values, a product of data values,
etc. In some instances, however, the value of the data
itself is used as is, without any further calculation.
In step 96, the parameter values are validated and
smoothing techniques may be used to ensure that meaningful
parameter values are utilized in the later steps of the
method 90. For example, a parameter value may be excluded if
it represents an unreasonably high or low value for that
parameter, and the smoothing techniques may be used to
prevent unacceptably large parameter value transitions from
distorting later analysis. A parameter value can correspond
to whether or not another event has occurred, as discussed
above.
In step 98, the parameter signature segments are
determined. This step can include calculating values
indicative of the behaviors of the parameters. For example,
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 16 -
if a parameter has an increasing trend, a value of 1 may be
assigned to the corresponding parameter signature segment,
if a parameter has a decreasing trend, a value of 2 may be
assigned to the segment, if the parameter is unchanged, a
value of 0 may be assigned to the segment, etc. To determine
the behavior of a parameter, statistical calculations
(algorithms) may be applied to the parameter values
resulting from step 96.
Comparisons between parameters may also be made to
determine a particular signature segment. For example, if
one parameter is greater than another parameter, a value of
1 may be assigned to the signature segment, if the first
parameter is less than the second parameter, a value of 2
may be assigned, if the parameters are substantially equal,
a value of 0 may be assigned, etc.
In step 100, the parameter signature segments are
combined to make up the parameter signatures. Each parameter
signature is a combination of parameter signature segments
and represents what is happening in real time in the
drilling operation.
In step 102, the parameter signatures are compared to
the previously defined event signatures to see if there is a
match. Since data is continuously (or at least
intermittently) being generated in real time during a
drilling operation, corresponding parameter signatures can
also be generated in the method 90 in real time for
comparison to the event signatures. Thus, an operator can be
informed immediately during the drilling operation whether
an event is occurring.
Step 104 represents defining of the event signatures
which, as described above, can be performed prior to and/or
during the drilling operation. Example event signatures are
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 17 -
provided in FIG. 5, and are discussed in further detail
below.
In step 106, an event is indicated if there is a match
between an event signature and a parameter signature. An
indication can be provided to an operator, for example, by
displaying on a computer screen information relating to the
event, displaying an alert, sounding an alarm, etc.
Indications can also take the form of recording the
occurrence of the event in a database, computer memory, etc.
A control system can also, or alternatively, respond to an
indication of an event, as described more fully below.
In step 108, a probability of an event occurring is
indicated if there is a partial match between an event
signature and a parameter signature. For example, if an
event signature comprises a combination of 30 parameter
behaviors, and a parameter signature is generated in which
28 or 29 of the parameter behaviors match those of the event
signature, there may be a high probability that the event is
occurring, even though there may not be a complete match
between the parameter signature and the event signature. It
could be useful to provide an indication to an operator in
this circumstance that the probability that the event is
occurring is high.
Another useful indication would be of the probability
of the event occurring in the future. For example if, as in
the example discussed above, a substantial majority of the
parameter behaviors match between the parameter signature
and the event signature, and the unmatched parameter
behaviors are trending toward matching, then it would be
useful (particularly if the event is an undesired event) to
warn an operator that the event is likely to occur, so that
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 18 -
remedial measures may be taken if needed (for example, to
prevent an undesired event from occurring).
Referring additionally now to FIG. 3, a flowchart of
another example of the process of generating the parameter
signatures in the method 90 is representatively illustrated.
The process begins with receiving the data as in step 92
described above. Parameter value calculations are then
performed as in step 94 described above.
In step 110, preprocessing operations are performed for
the parameter values. For example, maximum and minimum
limits may be used for particular parameters, in order to
exclude erroneously high or low values of the parameters.
In step 112, the preprocessed parameter values are
stored in a data buffer. The data buffer is used to queue up
the parameter values for subsequent processing.
In step 114, conditioning calculations are performed
for the parameter values. For example, smoothing may be used
(such as, moving window average, Savitzky-Golay smoothing,
etc.) as discussed above in relation to step 96.
In step 116, the conditioned parameter values are
stored in a data buffer.
In step 118, statistical calculations are performed for
the parameter values. For example, trend analysis (such as,
straight line fit, determination of trend direction over
time, first and second order derivatives, etc.) may be used
to characterize the behavior of a parameter. Values assigned
to the parameter behaviors become segments of the resulting
parameter signatures, as discussed above for step 98.
In step 120, the parameter signature segments are
output to the database for storage, subsequent analysis,
etc. In this example, the parameter signature segments
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 19 -
become part of the INSITE" database for the drilling
operation.
In step 100, as discussed above, the parameter
signature segments are combined to form the parameter
signatures.
Referring additionally now to FIG. 4, a flowchart of a
process for identifying that an event has occurred, or will
occur, in the method 90 is representatively illustrated. The
process begins with step 122, in which an event signature
database is configured. The database can be configured to
include any number of event signatures to enable any number
of corresponding events to be identified during a drilling
operation. Preferably, the event signature database can be
separately configured for different types of drilling
operations, such as underbalanced drilling, overbalanced
drilling, drilling in particular lithologies, etc.
In step 124, a desired set of event signatures are
loaded into the event signature database. As discussed
above, any number, type and/or combination of event
signatures may be used in the method 90.
In step 126, the event signature database is queried to
see if there are any matches to the parameter signatures
generated in step 100. As discussed above, partial matches
may optionally be identified, as well.
In step 128, events are identified which correspond to
event signatures which match (or at least partially match)
any parameter signatures. The output in step 130 can take
various different forms, which may depend upon the
identified event. An alarm, alert, warning, display of
information, etc. may be provided as discussed above for
step 106. At a minimum, occurrence of the event should be
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 20 -
recorded, and in this example preferably is recorded, as
part of the INSITE" database for the drilling operation.
Referring additionally now to FIG. 5, four example
event signatures are representatively tabulated, along with
parameter behaviors which correspond to the segments of the
signatures. In practice, many more event signatures may be
provided, and more or less parameter behaviors may be used
for determining the signature segments.
Note that each event signature is distinctive. Thus, a
kick (influx) event is indicated by a particular combination
of parameter behaviors, whereas a fluid loss event is
indicated by another particular combination of parameter
behaviors.
If, during a drilling operation, a parameter signature
is generated which matches (or at least partially matches)
any of the event signatures shown in FIG. 5, an indication
will be provided that the corresponding event is occurring.
If a parameter signature is generated which matches an event
signature to a predetermined level, or if the parameter
signature's segments are trending toward matching, then an
indication may be provided that the corresponding event is
substantially likely to occur. This can happen even without
any human intervention, resulting in a more automated,
precise and safe drilling environment.
The event indications provided by the method 90 can
also be used to control the drilling operation. For example,
if a kick event is indicated, the operative choke(s) 34 can
be adjusted in response to increase pressure applied to the
annulus 20 in the system 10. If fluid loss is detected, the
choke(s) 34 can be adjusted to decrease pressure applied to
the annulus 20. If a drill pipe connection is starting, the
flow control devices 81, 74 can be appropriately adjusted to
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 21 -
maintain a desired pressure in the annulus 20 during the
connection process, and when completion of the drill pipe
connection is detected, the flow control devices can be
appropriately adjusted to restore circulation flow through
the drill string 16 in preparation for drilling ahead.
These and other types of control over the drilling
operation can be implemented based on detection of the
corresponding events using the method 90 automatically and
without human intervention, if desired. In one example, a
control system such as that described in International
Application No. PCT/US08/87686 may be used for implementing
the control over the drilling operation.
In some embodiments, human intervention could be used,
for example, to determine whether the control over the
drilling operation should be implemented in response to
detection of events in the method 90. Thus, if an event is
detected (or if the event is indicated as being likely to
happen), a human's authorization may be required before the
drilling operation is automatically controlled in response.
As depicted in FIG. 1, a controller 84 (such as a
programmable logic controller or another type of controller
capable of controlling operation of drilling equipment) is
connected to a control system 86 (such as the control system
described in International Application No. PCT/US08/87686,
or as described in International Application No.
PCT/US10/56433). The controller 84 is also connected to the
flow control devices 34, 74, 81 for regulating flow injected
into the drill string 16, flow through the drilling fluid
return line 30, and flow between the standpipe injection
line 26 and the return line 30.
The control system 86 can include various elements,
such as one or more computing devices/processors, a
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 22 -
hydraulic model, a wellbore model, a database, software in
various formats, memory, machine-readable code, etc. These
elements and others may be included in a single structure or
location, or they may be distributed among multiple
structures or locations.
The control system 86 is connected to the sensors 36,
38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 which sense
respective drilling properties during the drilling
operation. As discussed above, offset well data, previous
operator experience, other operator input, etc., may also be
input to the control system 86. The control system 86 can
include software, programmable and preprogrammed memory,
machine-readable code, etc. for carrying out the steps of
the method 90 described above.
The control system 86 may be located at the wellsite,
in which case the sensors 36, 38, 40, 44, 46, 54, 56, 58,
60, 62, 64, 66, 67 could be connected to the control system
by wires or wirelessly. Alternatively, the control system 86
could be located at a remote location, in which case the
control system could receive data via satellite
transmission, the Internet, wirelessly, or by any other
appropriate means. The controller 84 can also be connected
to the control system 86 in various ways, whether the
control system is locally or remotely located.
In one example, the control system 86 can cause one or
any number of the chokes 34 to close (e.g., increasingly
restrict flow of the fluid 18 through the return line 30) by
a predetermined amount automatically in response to the step
130 output indicating that a kick (influx) has occurred, or
is substantially likely to occur. For example, if the
parameter signature matches (or substantially matches) the
event signature for a kick, then the control system 86 will
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 23 -
operate the controller 84 to close the operative choke(s) 34
by the predetermined amount (e.g., a percentage of the
choke's operating range, such as 1%-10% of that range).
The predetermined amount could be preprogrammed into
the control system 86, and/or the predetermined amount could
be input, for example, via a human-machine interface. After
the choke(s) 34 have been closed the predetermined amount,
control over operation of the choke(s) 34 can be returned to
an automated system whereby a wellbore or standpipe pressure
set point is maintained (which set point may be obtained,
e.g., from a hydraulics model or manual input), the choke(s)
can be manually operated, or another manner of controlling
the choke(s) can be implemented.
In another example, the control system 86 can cause one
or any number of the chokes 34 to open (e.g., decrease
restriction to flow of the fluid 18 through the return line
30) by a predetermined amount automatically in response to
the step 130 output indicating that a fluid loss has
occurred, or is substantially likely to occur. For example,
if the parameter signature matches (or substantially
matches) the event signature for a fluid loss, then the
control system 86 will operate the controller 84 to open the
operative choke(s) 34 by the predetermined amount (e.g., a
percentage of the choke's operating range, such as 1%-10% of
that range).
The predetermined amount could be preprogrammed into
the control system 86, and/or the predetermined amount could
be input, for example, via a human-machine interface. After
the choke(s) 34 have been opened the predetermined amount,
control over operation of the choke(s) 34 can be returned to
the automated system whereby the wellbore or standpipe
pressure set point is maintained (which set point may be
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 24 -
obtained, e.g., from a hydraulics model or manual input),
the choke(s) can be manually operated, or another manner of
controlling the choke(s) can be implemented.
In another example, the control system 86 can provide
an alert or an alarm to an operator that a particular event
has occurred, or is substantially likely to occur. The
operator can then take any needed remedial actions based on
the alert/alarm, or can override any actions taken by the
control system 86 automatically in response to the step 130
output. If action has already been taken by the control
system 86, the operator can undo or reverse such actions, if
desired.
In another example, the control system 86 can switch
between maintaining a desired wellbore pressure to
maintaining a desired standpipe pressure in response to the
step 130 output indicating that an event has occurred, or is
substantially likely to occur. A technique by which a
control system can maintain a wellbore pressure is described
in International Application Nos. PCT/US10/38586 and
PCT/US10/56433, and a technique by which a control system
can maintain a standpipe pressure is described in
International Application No. PCT/US11/31767.
The control system 86 can switch between such wellbore
pressure set point and standpipe 26 pressure set point modes
automatically in response to the step 130 output indicating
that an event has occurred, or is substantially likely to
occur. For example, if a kick (influx) event is detected,
the control system 86 can switch from maintaining a desired
wellbore 12 pressure to maintaining a desired standpipe 26
pressure. This switch may actually be performed after
verifying that conditions are acceptable for making the
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 25 -
switch, and after providing an operator with an option (such
as, via a displayed alert) to initiate the switch.
In another example, the control system 86 can
automatically provide an operator (such as a driller) with
instructions or guidance for what remedial measures to take
in response to the step 130 output indicating that an event
has occurred or is substantially likely to occur. The
instructions or guidance may be provided by a local well
site display, and/or may be transmitted between the well
site and a remote location, etc.
In another example, the control system 86 can implement
a well control procedure automatically in response to the
step 130 output indicating that an event has occurred, or is
substantially likely to occur. The well control procedure
could include routing return flow of the fluid 18 to a
conventional rig choke manifold 82 and gas buster 88 (see
FIG. 1) designed for handling well control situations.
Alternatively, the well control procedure could include
the control system 86 automatically operating the choke
manifold 32 to optimally circulate out an undesired influx.
An example of automated operation of a choke manifold to
circulate out an undesired influx is described in
International Application No. PCT/US10/20122, filed 5
January 2010.
In another example, the control system 86 can
manipulate a choke 34 (e.g., alternately open and close the
choke a certain amount, etc.) automatically in response to
the step 130 output indicating that the choke is plugged, or
is substantially likely to become plugged. The choke 34
plugging event can be represented by an event signature
which, for example, includes a parameter segment indicating
increasing pressure differential across the choke. The
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 26 -
manipulation of the choke 34 automatically in response to
the step 130 output can potentially dislodge whatever has
plugged or is increasingly plugging the choke.
In another example, the control system 86 can switch
flow of the fluid 18 from one of the chokes 34 to another of
the chokes automatically in response to the step 130 output
indicating that one of the chokes has become plugged, washed
out, locked or otherwise compromised, or is substantially
likely to become so compromised. The switching from one
choke 34 to another can be performed progressively and
automatically, so that a desired wellbore pressure or
standpipe pressure can also be maintained by the control
system 86 during the switching.
The control system 86 can switch flow of the fluid 18
from one of the chokes 34 to another of the chokes
automatically in response to the step 130 output indicating
that the fluid 18 flow is out of, or is substantially likely
to become out of, an optimum operating range of one of the
chokes. The chokes 34 can have different trim sizes, so that
the chokes have different optimum operating ranges. When the
flow of the fluid 18 is outside of the optimum operating
range of the choke 34 being used to variably restrict the
flow, it can be beneficial to switch the flow to another of
the chokes having an optimum operating range which better
matches the flow.
The control system 86 can open an additional choke 34
automatically in response to the step 130 output indicating
that an operating range of the operative choke is exceeded,
or is substantially likely to be exceeded, by the flow of
the fluid 18. By increasing the number of operative chokes
34 through which the fluid 18 flows, the flow through each
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 27 -
choke is reduced, so that the operating range of each choke
is not exceeded.
In another example, the control system 86 can modify or
correct a pressure set point (e.g., received from a
hydraulics model) automatically in response to the step 130
output indicating that: a) a sensor (such as the sensor 60,
a pressure while drilling (PWD) tool, etc.) has failed or is
substantially likely to fail, b) the drill string 16 has
parted (e.g., twisted off, disconnected, backed off, etc.)
downhole or is substantially likely to do so, and/or c) an
influx or loss event has occurred or is substantially likely
to occur, making adjustment of fluid 18 density in the
wellbore desirable in models, such as the hydraulics model
and/or a well model. The control system 86 can operate the
controller 84 using the modified/corrected set point,
instead of the set point received from, e.g., the hydraulics
model. The control system 86 can update the hydraulics
and/or well model(s) with revised fluid 18 density based on
the detection of the fluid influx or loss event.
In another example, the control system 86 can
automatically communicate to the hydraulics and/or well
model(s) that an event has been detected. For example, if
the event is a failure of the sensor 60 (such as a PWD
sensor, etc.), the control system 86 can automatically
communicate this to the hydraulics model, which will cease
correcting the pressure set point based on actual
measurements from the sensor. As another example, if the
event is parting of the drill string 16, the control system
86 can automatically communicate this to the hydraulics
and/or well model(s), which will adjust a volume of the
annulus 20 and/or other parameters in the model(s).
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 28 -
In another example, the control system 86 can open one
or more of the previously inoperative chokes 34
automatically in response to the step 130 output indicating
that excessive pressure exists in the wellbore 12, or at
least upstream of the choke manifold 32. A maximum pressure
can be preprogrammed into the control system 86 so that, if
the maximum pressure is exceeded, one or more of the chokes
34 will be opened by the controller 84 to relieve the excess
pressure.
In another example, the control system 86 can divert
flow to a rig choke manifold 82, or another choke manifold
similar to the choke manifold 32, automatically in response
to the step 130 output indicating that a sealing element of
the RCD 22 has failed, or is substantially likely to fail.
The control system 86 could also automatically open the
choke(s) 34 a desired amount, to thereby relieve pressure
under the RCD 22.
In another example, the control system 86 can modify an
annulus 20 volume used by the hydraulics and/or well
model(s) automatically in response to the step 130 output
indicating that a floating rig is heaving. For example, the
control system 86 could receive indications of rig heave
from a conventional motion compensation system of the
floating rig. The annulus 20 volume can be
modified/corrected by the control system 86 automatically in
response to indications that the rig has risen or fallen,
thereby enabling the wellbore or standpipe pressure set
point to be updated based on the modified/corrected annulus
volume.
It may now be fully appreciated that the above
disclosure provides many benefits to the art of well
drilling and event detection during drilling operations. The
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 29 -
methods described above enable drilling events to be
detected accurately and in real time, so that appropriate
actions may be taken if needed. The control system 86 can
automatically perform the appropriate actions (such as,
providing an alert or alarm, controlling operation of the
chokes 34, controlling operation of various flow control
devices, etc.) in response to an indication that a
particular drilling event has occurred, or is substantially
likely to occur.
In particular, the above disclosure provides to the art
a well drilling method 90 which can include the steps of
detecting a drilling event by comparing a parameter
signature generated during drilling to an event signature
indicative of the drilling event, and automatically
controlling a drilling operation in response to at least a
partial match resulting from comparing the parameter
signature to the event signature.
Automatically controlling may include automatically
adjusting a choke 34 in response to the detecting.
The drilling event may comprise an influx, and
automatically controlling may include automatically closing
a choke 34 a predetermined amount in response to detecting
the influx.
The drilling event may comprise a fluid 18 loss, and
automatically controlling may include automatically opening
a choke 34 a predetermined amount in response to detecting
the fluid 18 loss.
The detecting step may include detecting that the
drilling event has occurred, or is substantially likely to
occur.
CA 02841771 2014-01-03
WO 2013/006165
PCT/US2011/042917
- 30 -
The drilling event may comprise a start or a completion
of a drill pipe connection process. Automatically
controlling may include automatically restoring circulation
flow through a drill string 16 in response to detecting the
completion of the drill pipe connection process.
Automatically controlling may include automatically
switching between a) maintaining a desired wellbore 12
pressure, and b) maintaining a desired standpipe 26
pressure.
The drilling event may comprise an influx.
Automatically controlling may include automatically
implementing a well control procedure. The well control
procedure may comprise diverting fluid 18 flow to a rig
choke manifold 82, automatically circulating an undesired
influx out of a well, and/or automatically operating a choke
manifold 32, thereby circulating an undesired influx out of
the well.
The drilling event may comprise plugging of a choke 34,
and automatically controlling may include automatically
manipulating the choke 34. Manipulating the choke 34 may
include alternately opening and closing the choke 34.
Automatically controlling may include automatically
switching flow from a first choke 34 to a second choke 34.
The drilling event may comprise flow through the first choke
34 being outside of an optimum operating range of the first
choke 34, the first choke 34 being compromised, the first
choke 34 being locked, the first choke 34 being plugged,
and/or the first choke 34 being washed out. Switching flow
may include automatically maintaining a desired pressure
during the switching.
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 31 -
The drilling event may comprise exceeding an operating
range of one or more operative chokes 34, and automatically
controlling may include automatically increasing a number of
the operative chokes 34.
The drilling event may comprise failure of a rotating
control device 22 seal. Automatically controlling may
include automatically diverting flow to a rig choke manifold
82, and/or opening a choke 34 a predetermined amount,
thereby increasingly relieving pressure across the rotating
control device 22.
Automatically controlling may include communicating rig
heave information to a model.
The drilling event may comprise rig heave.
Automatically controlling may include automatically
adjusting annulus 20 volume, and/or automatically updating a
pressure set point.
The drilling event may comprises failure of a sensor
36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67.
Automatically controlling may include communicating the
sensor 36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67
failure to a model.
Automatically controlling the drilling operation may be
performed further in response to human authorization of such
automatic control of the drilling operation.
Also described above is a well drilling system 10. The
well drilling system 10 may include a control system 86
which compares a parameter signature for a drilling
operation to an event signature indicative of a drilling
event, and a controller 84 which controls the drilling
operation automatically in response to the drilling event
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 32 -
being indicated by at least a partial match between the
parameter signature and the event signature.
The controller 84 may automatically adjust a choke 34
in response to the drilling event being indicated.
The drilling event may comprise an influx, and the
controller 84 may automatically close a choke 34 a
predetermined amount in response to the influx being
indicated.
The drilling event may comprise a fluid 18 loss, and
the controller 84 may automatically open a choke 34 a
predetermined amount in response to the fluid 18 loss being
indicated.
The at least partial match may indicate that the
drilling event has occurred, or that the drilling event is
substantially likely to occur.
The drilling event comprises a start or a completion of
a drill pipe connection. The controller 84 may automatically
restore circulation flow through a drill string 16.
The control system 86 may automatically switch between
a) maintenance of a desired wellbore pressure, and b)
maintenance of a desired standpipe pressure.
The drilling event may comprise an influx. The control
system 86 may automatically implement a well control
procedure. The well control procedure may comprise diversion
of fluid 18 flow to a rig choke manifold 82, automatic
circulation of an undesired influx out of a well, and/or
automatic operation of a choke manifold 32, whereby the
undesired influx is circulated out of the well.
The drilling event may comprise a choke 34 being
plugged, and the controller 84 may automatically manipulate
CA 02841771 2014-01-03
WO 2013/006165 PCT/US2011/042917
- 33 -
the choke 34. Manipulation of the choke 34 may comprise
alternately opening and closing the choke 34.
The control system 86 may automatically switch flow
from a first choke 34 to a second choke 34. The drilling
event may comprise flow through the first choke 34 being
outside of an optimum operating range of the first choke 34,
or the first choke 34 being compromised, locked, plugged,
and/or washed out. The control system 86 may automatically
maintain a desired pressure while the flow is switched from
the first choke 34 to the second choke 34.
The drilling event may comprise an operating range of
one or more operative chokes 34 being exceeded, and the
control system 86 may automatically increase a number of the
operative chokes 34.
The drilling event may comprise failure of a rotating
control device 22 seal. The control system 86 may
automatically divert flow to a rig choke manifold 82, and/or
automatically open a choke 34 a predetermined amount,
whereby pressure across the rotating control device 22 is
increasingly relieved.
The control system 86 may automatically communicate rig
heave information to a model.
The drilling event may comprise rig heave. The control
system 86 may automatically adjust annulus 20 volume, and/or
automatically update a pressure set point.
The drilling event may comprises failure of a sensor
36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67. The
control system 86 may automatically communicate the sensor
36, 38, 40, 44, 46, 54, 56, 58, 60, 62, 64, 66, 67 failure
to a model.
CA 02841771 2015-10-28
-34-
The control system 86 may provide an alert, an alarm,
guidance to an operator, and/or at least one option for
response to the drilling event being indicated.
The controller 84 may control the drilling operation
automatically further in response to human authorization of
such control of the drilling operation.
It is to be understood that the various embodiments of
the present disclosure described herein may be utilized in
various orientations, such as inclined, inverted, horizontal,
vertical, etc., and in various configurations, without
departing from the principles of this disclosure. The
embodiments are described merely as examples of useful
applications of the principles of the disclosure, which is not
limited to any specific details of these embodiments.
Of course, a person skilled in the art would, upon a
careful consideration of the above description of
representative embodiments of the disclosure, readily
appreciate that many modifications, additions, substitutions,
deletions, and other changes may be made to the specific
embodiments. Accordingly, the scope of the claims should not
be limited by the preferred embodiments set forth in the
examples, but should be given the broadest interpretation
consistent with the description as a whole.
