U.S. patent application number 13/391833 was filed with the patent office on 2012-07-26 for well drilling method utilizing real time response to ahead of bit measurements.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Michael S. Bittar, Craig W. Godfrey, Derrick W. Lewis, James Randolph Lovorn, Sara Shayegi.
Application Number | 20120186873 13/391833 |
Document ID | / |
Family ID | 46543319 |
Filed Date | 2012-07-26 |
United States Patent
Application |
20120186873 |
Kind Code |
A1 |
Shayegi; Sara ; et
al. |
July 26, 2012 |
WELL DRILLING METHOD UTILIZING REAL TIME RESPONSE TO AHEAD OF BIT
MEASUREMENTS
Abstract
A well drilling method utilizing real time response to ahead of
bit measurements. A well drilling method includes measuring a
property of a portion of the earth prior to drilling a wellbore
into the earth portion; and varying a drilling parameter in real
time while drilling the wellbore, in response to measuring the
property.
Inventors: |
Shayegi; Sara; (Houston,
TX) ; Lewis; Derrick W.; (Conroe, TX) ;
Bittar; Michael S.; (Houston, TX) ; Lovorn; James
Randolph; (Tomball, TX) ; Godfrey; Craig W.;
(Dallas, TX) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
46543319 |
Appl. No.: |
13/391833 |
Filed: |
October 5, 2010 |
PCT Filed: |
October 5, 2010 |
PCT NO: |
PCT/US10/51384 |
371 Date: |
February 23, 2012 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
PCT/US09/59541 |
Oct 5, 2009 |
|
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13391833 |
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Current U.S.
Class: |
175/25 ; 175/24;
175/27 |
Current CPC
Class: |
E21B 21/08 20130101;
E21B 44/00 20130101 |
Class at
Publication: |
175/25 ; 175/24;
175/27 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 21/08 20060101 E21B021/08; E21B 7/06 20060101
E21B007/06; E21B 44/02 20060101 E21B044/02 |
Claims
1. A well drilling method, comprising: collecting ahead-of-bit
measurements while drilling; determining a desired value of at
least one drilling parameter based at least in part on the
ahead-of-bit measurements; and providing an adjustment to the
drilling parameter to match the desired value, wherein said
providing includes using a rate-of-penetration measurement to
determine timing for said adjustment.
2. The method of claim 1, wherein the at least one drilling
parameter comprises bottom hole pressure.
3. The method of claim 2, further comprising estimating a formation
pore pressure based at least in part on the ahead-of-bit
measurements.
4. The method of claim 3, further comprising estimating a formation
fracture pressure based at least in part on the ahead-of-bit
measurements.
5. The method of claim 2, further comprising verifying that the
desired value of the drilling parameter is suitable for previously
penetrated formations.
6. The method of claim 5, further comprising activating an alarm if
the desired value is not suitable for previously penetrated
formations.
7. The method of claim 1, wherein the ahead-of-bit measurements
include formation resistivity.
8. The method of claim 1, wherein the ahead-of-bit measurements
include at least one of acoustic velocity, acoustic impedance, and
formation density.
9. The method of claim 1, wherein the ahead-of-bit measurements
include at least one of natural gamma radiation, prompt gamma
response to neutron radiation, and formation porosity.
10. The method of claim 1, further comprising processing the
ahead-of-bit measurements to identify a position of at least one of
a bed boundary, a formation fluid interface, a fracture, and a
borehole.
11. The method of claim 10, wherein the drilling parameter
comprises a steering direction.
12. A well drilling system that comprises: a drillstring having at
least one tool that collects look-ahead measurements; and a control
system that regulates a drilling parameter based at least in part
on the look-ahead measurements.
13. The system of claim 12, wherein the control system further
regulates the drilling parameter based at least in part on timing
information derived partly from rate of penetration
measurements.
14. The system of claim 13, wherein the drilling parameter
comprises bottomhole pressure.
15. The system of claim 14, wherein the control system determines
formation pore pressure based at least in part on the ahead-of-bit
measurements.
16. The system of claim 14, wherein the control system determines
formation fracture pressure based at least in part on the
ahead-of-bit measurements.
17. The system of claim 14, wherein the control system verifies
that a desired value of the drilling parameter is suitable for
previously penetrated formations and activates an alarm if the
desired value is not suitable for previously penetrated
formations.
18. The system of claim 12, wherein the look-ahead measurements
include at least one of formation resistivity and dielectric
constant.
19. The system of claim 12, wherein the look-ahead measurements
include at least one of acoustic velocity, acoustic impedance, and
formation density.
20. The system of claim 12, wherein the look-ahead measurements
include at least one of natural gamma radiation, prompt gamma
response to neutron radiation, and formation porosity.
21. The system of claim 12, wherein the drilling parameter
comprises a steering direction, and wherein the control system
further processes the look-ahead measurements to identify a
position of at least one of a bed boundary, a formation fluid
interface, a fracture, and a borehole.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of Patent
Cooperation Treaty application PCT/US09/59541, titled "Well
drilling method utilizing real time response to ahead of bit
measurements" and filed Oct. 5, 2009 by inventors Sara Shayegi,
Derrick W. Lewis, Michael Bittar, James Randolph Lovorn, and Craig
W. Godfrey, and which is hereby incorporated herein by
reference.
TECHNICAL FIELD
[0002] 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 a well drilling method utilizing real time
response to ahead of bit measurements.
BACKGROUND
[0003] In the past, properties of an earth formation have been
estimated, modeled or predicted prior to drilling into the
formation. However, the actual properties of a particular part of a
formation are typically not known until after a drill bit drills
into that part of the formation. Thus, operators in those
circumstances cannot make proactive or preemptive decisions based
on advance knowledge of the actual properties of the formation
prior to the drill bit cutting into the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] FIG. 1 is a schematic partially cross-sectional view of a
well drilling system which can embody principles of the present
disclosure.
[0005] FIG. 2 is an enlarged scale schematic partially
cross-sectional view to illustrate a method embodying principles of
the present disclosure.
[0006] FIG. 3 illustrates detection of a formation boundary prior
to drilling into the formation boundary.
[0007] FIG. 4 illustrates steering of a wellbore toward a desirable
zone.
[0008] FIG. 5 illustrates detection of another wellbore prior to
drilling into that wellbore.
[0009] FIG. 6 is a flowchart of an illustrative method for real
time or anticipatory response to ahead-of-bit measurements.
DETAILED DESCRIPTION
[0010] 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).
[0011] 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. As
explained below, a number of techniques can be used to control
bottom hole pressure.
[0012] Gravity acts on the column of drilling mud flowing in and
out of the hole, causing the fluid pressure to increase with depth.
In the absence of dynamic flow effects, the rate of pressure
increase is proportional to the fluid density. (Where the fluid is
relatively incompressible, this results in a linear pressure
increase with depth. Where the fluid density increases with
pressure, gravity can produce an exponential pressure increase.)
Accordingly, one way to control pressure is to decrease the average
fluid density by adding nitrogen or another gas, or another lighter
weight fluid, to the drilling fluid 18. This technique is useful,
for example, in underbalanced drilling operations.
[0013] When dynamic flow effects are considered, a second technique
for controlling bottomhole pressure becomes evident. When the
drilling fluid flows slowly, dynamic flow effects are minimal and
the pressure distribution within the well is dominated by gravity
effects. However at higher flow rates, the dynamic flow effects
become increasingly important. As the fluid flows through the
tubing and returns along the annulus, it experiences a frictional
flow resistance which tends to create a linear pressure drop along
the fluid flow path. At sufficient flow rates these effects
dominate over the gravity effects. Moreover, constrictions along
the flow path can have a significant effect on the pressure
profile, causing a pressure differential that raises upstream
pressures and lowers downstream pressures. In some systems, a
turbulent flow may develop, causing vortices and eddys which have
similar effects to flow path constrictions. Accordingly, such
effects can be used to control bottom hole pressure, either by
varying the flow rate or by varying downhole flow path
constrictions or both.
[0014] Another bottom hole pressure control method is illustrated
in system 10. Here, 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 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.
[0015] 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.
[0016] 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 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.
[0017] Furthermore, the drill string 16 preferably includes at
least one sensor 60. Such sensor(s) 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.
Alternatively, or in addition, the drill string 16 may comprise
wired drill pipe (e.g., having electrical conductors extending
along the length of the drill pipe) for transmitting data and
command signals between downhole and the surface or another remote
location.
[0018] 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.
[0019] 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.
[0020] Note that the separator 48 could be a 3 or 4 phase
separator, or a mud gas separator (sometimes referred to as 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.
[0021] 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.
[0022] 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 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.
[0023] 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 RCD 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, without departing from the
principles of this disclosure.
[0024] 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.
[0025] 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 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.
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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 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.
[0030] 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
sensor 60).
[0031] 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 Patent
Cooperation Treaty application PCT/US08/87686, titled "Pressure and
Flow Control in Drilling Operations" and filed Dec. 19, 2008 by
inventors Lovorn, Bruder, Skinner, and Karigan). 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 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.
[0032] 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, or any portion of it, 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.
[0033] In one example, data signals from the sensors 36, 38, 40,
44, 46, 54, 56, 58, 60, 62, 64, 66, 67 are transmitted to the
control system 86 at a remote location, the data is analyzed there
(e.g., utilizing computing devices/processors, a hydraulic model, a
wellbore model, a database, software in various formats, memory,
and/or machine-readable code, etc.) at the remote location. A
decision as to how to proceed in the drilling operation (such as,
whether to vary any of the drilling parameters) may be made
automatically based on this analysis, or human intervention may be
desirable in some situations. Instructions as to how to proceed are
then transmitted as signals to the controller 84 for execution at
the wellsite. Even though all or part of the control system 86 may
be at a remote location, the drilling parameter can still be varied
in real time in response to measurement of properties of the
formation ahead of the bit, since modern communication technologies
(e.g., satellite transmission, the Internet, etc.) enable
transmission of signals without significant delay.
[0034] It is not necessary for a surface choke to be used in the
well control system and method. Instead, a downhole choking/flow
restricting device could be used. The downhole choke could, for
example, comprise an inflatable packer on the drill string to choke
flow through the annulus. Inflation of the packer and the resulting
flow restriction could be controlled so that a desired downhole
pressure is achieved/maintained. Alternatively a variable orifice
could be used within the drillstring and actuated in response to
external parameter measurements including flow rates and pressure.
Downhole flow measurement system and/or a PWD (downhole pressure
measurement system) can be used for early influx detection.
Detected changes in pressure, flow, fluid type, etc., may provide
rapid detection of formation fluid influx to the borehole and
enable fast response. Preferably, the well control system stops an
undesired influx and circulates the influx fluid out of a well,
using a hydraulics model to automatically control the choke or flow
restrictors based on a desired surface pressure profile and desired
downhole pressure. Such a system can prevent break down of a casing
shoe, and can be remotely monitored and controlled.
[0035] Referring additionally now to FIG. 2, an enlarged scale
schematic partially cross-sectional view of the drill string 16 as
it is being used in a method 90 for drilling the wellbore 12 is
representatively illustrated apart from the remainder of the system
10. However, it should be clearly understood that the method 90 may
be practiced with other well drilling systems in keeping with the
principles of this disclosure. FIG. 2 shows a sensor 60 connected
in close proximity to the drill bit 14. For example, the sensor 60
may be positioned between the drill bit 14 and a fluid motor 94
(e.g., a "mud" motor) used to rotate the drill bit in response to
flow of the drilling fluid 18 through the motor. In other
embodiments, the sensor can be partly or fully integrated into the
drill bit.
[0036] In this example, the sensor 60 is capable of measuring one
or more properties of a portion 92 of the earth prior to the drill
bit 14 cutting into the earth portion. For example, the sensor 60
may measure a property of an earth formation approximately 10 to 50
feet (-3 to 17 meters) ahead of the bit 14. More advanced sensors
may be capable of measuring a property of an earth formation up to
about 100 feet (-30 meters) ahead of the bit 14. However, it should
be understood that measurement of formation properties at any
distance ahead of the bit 14 may be used, in keeping with the
principles of this disclosure. Contemplated look-ahead sensors
include resistivity logging tools, radar tools, acoustic tools,
nuclear radiation tools, and combinations thereof These various
technologies are each discussed in turn below.
[0037] A number of logging tools have been developed that can
provide look-ahead capabilities including, for example, those
described in U.S. Pat. No. 6,181,138 "Directional resistivity
measurements for azimuthal proximity detection of bed boundaries"
filed Feb. 22, 1999 by inventors Hagiwara and Song, U.S. Pat. No.
6,480,118 "Method of drilling in response to looking ahead of
drillbit" filed Mar. 27, 2000 by inventor Vikram Rao, U.S. Pat. No.
6,958,610 "Method and apparatus measuring electrical anisotropy in
formation surrounding a wellbore" filed June 17, 2002 by inventor
Stanley Gianzero, U.S. Pat. No. 7,350,568 "Logging a well" filed
Feb. 9, 2005 by inventors Mandal and Bittar, and PCT application
"Deep Evaluation of Resistive Anomalies in Borehole Environments"
filed Oct. 5, 2009 by inventors Bittar and Donderici (agent file
reference 09-021339). That is, previously disclosed resistivity
tools can be configured to measure galvanic resistivities of
formations ahead of the bit by using the bit to inject current into
the surrounding formation and using a plurality of return
electrodes to isolate the contribution of the currents flowing
through formation portion 92 ahead of the bit. To accomplish this,
the geometrical spreading of currents from the injection electrode
to each of the return electrodes is modeled and used to identify
that combination of measurements which is most representative of
the resistivity ahead of the bit. Similarly, one or more horizontal
or tilted magnetic dipole antennas can induce current flows in the
formations around the drill bit and an array of receivers can
isolate the measurement contributions of those currents flowing in
the regions ahead of the bit to measure resistivity and/or
dielectric constant. It is even possible to modify a drillstring
radar system (such as that described in U.S. Pat. No. 6,778,127
"Drillstring Radar" filed Nov. 4, 2002 by inventors Stolarczyk and
Stolarczyk) to provide a look ahead capability. A waveguide directs
a series of high-power radar pulses or a modulated continuous wave
electromagnetic signal forward from the bit. The receiver signals
are then analyzed to detect signal reflections from which target
strength and distance can be measured. Further processing can be
performed to estimate the dielectric constant of the formations
traversed by the radar signals.
[0038] Many of the above mentioned references also discuss acoustic
look-ahead measurements. In some embodiments, acoustic pulses are
transmitted forward from the bit and received with acoustic
transducers. Analysis of the received signals indicates travel time
to those sources of acoustic signal reflections. When combined with
measurements or estimates of acoustic velocities, such travel times
can be readily converted to target distances. Other embodiments
rely on the drilling noise as an acoustic source and apply a
correlation processing technique to the received signals to observe
and measure signal reflections. As with the resistivity tools, an
array of receivers can be employed to improve tool performance
and/or to provide beam steering. (When the signals from the
receiver array are combined in the appropriate fashion, the array
can be "focused" to enhance signals arriving from a given direction
and to suppress signals arriving from other directions.) In
addition to identifying boundaries, fractures, and interfaces,
acoustic signal measurements can provide estimates of formation
density and, in some cases, formation breakdown or fracture
pressures.
[0039] Neutron and gamma ray tools can also be used for look-ahead
measurements. Though the range of such tools is generally much more
limited than that of resistivity or acoustic tools, neutron tools
can still be expected to have a range of up to a meter under the
right conditions. An important consideration in maximizing the
range of such tools is placing the detector as near the end of the
drillstring as feasible, and preferably in the bit itself. It is
expected that the detector would take the form of a scintillation
detector, which measures gamma ray flux by the count rate of
flashes in a scintillation crystal. Note that measurements of
natural gamma ray radiation can be combined with resistivity
measurements to estimate pore pressure. See, e.g., W. A. Zoeller,
"Pore Pressure Detection from the MWD Gamma Ray", SPE 12166, 1983.
Pore pressure trends can be combined with overburden pressure
information to predict fracture pressures. See, e.g., V. A.
Akinbinu, "Prediction of fracture gradient from formation pressures
and depth using correlation and stepwise multiple regression
techniques", J. Petroleum Sci. Engr., 72(1), pp. 10-17, May
2010.
[0040] Sensor 60 can use any one or more of these techniques to
measure resistivity, dielectric constant, acoustic impedance,
natural radioactivity, prompt gamma response to neutrons, and/or
other properties of the formation ahead of the bit. The sensor
measurements can be used to measure porosity of the earth portion
92, pore pressure in the earth portion, fracture pressure of the
earth portion, density of the earth portion, strength of the earth
portion, fluid type in the earth portion, and/or other properties.
Furthermore, by measuring multiple such properties of the earth
portion 92, the tool can identify the presence of a water
interface, a gas interface, an oil interface, salt, a fault, a
formation boundary and/or another wellbore, etc. in the earth
portion. Some tool embodiments may further identify lithology based
on gamma, density, and resistivity measurements, and may warn of
imminent fracture pressure changes, rate of penetration changes,
etc. Based on pore pressure profiles, the system can also alert the
operator to potential bypass flows before the borehole connects the
candidate formations.
[0041] Note that the method 90 includes actually measuring one or
more properties of the earth portion 92 prior to drilling into the
earth portion, rather than merely predicting or estimating what
such properties should be based, for example, on offset well data,
models, etc. Instead, the method 90 enables a drilling parameter
(such as choke position, operation of a flow control device, drill
bit steering, drilling fluid weight, torque, rpm, bit type, weight
on bit, etc.) to be varied in real time, in response to the actual
measurement of at least one property of the earth portion 92 prior
to drilling into that earth portion.
[0042] This capability can be very valuable in a drilling
operation. For example, control of drilling parameters in response
to real time measurement of formation properties ahead of the drill
bit 14 can be used to proactively adjust flow control devices 34,
74, 81 (e.g., to compensate for increased or decreased pore
pressure in the earth portion 92, to compensate for increased or
decreased fracture pressure of the earth portion, to maintain a
desired bottom hole pressure, etc.), to guide a determination of
whether and where to set casing (e.g., when a margin between pore
and fracture pressure indicates that casing should be set, waiting
until a high strength or increased pressure zone is drilled into,
etc.), to avoid drilling into a water-bearing zone, to avoid
drilling into an existing open or cased wellbore, to avoid or steer
into salt, to avoid or steer into a fault, fracture, karst or
formation boundary, to continue drilling through or to steer toward
a hydrocarbon-bearing zone, etc.
[0043] Referring additionally now to FIG. 3, the method 90 is
representatively illustrated in the situation where a formation
boundary 95 exists in the earth portion 92 which is in the path of
the wellbore 12 as it is being drilled. One type of earth formation
96 is positioned on one side of the boundary 94, and another type
of earth formation 98 is positioned on the other side of the
boundary. Using the sensor 60, the presence of the formation
boundary 95 can be detected in real time prior to drilling into the
boundary, and so various pertinent decisions can be made in a
timely, proactive or even preemptive manner. Furthermore, the
sensor 60 can measure properties of the formations 96, 98 for use
in the decision-making process. For example, if it is determined
that the formation 98 comprises shale, then it may be desirable to
make preparations for increasing bottom hole pressure in the
wellbore 12 somewhat (e.g., by increasing the weight of the
drilling fluid 18, increasingly restricting flow through the choke
34, and/or altering the flow rate). If it is determined that the
formation 98 comprises salt, then a decision may be made to either
drill into, avoid or steer away from the formation boundary 95. If
it is determined that the formation 98 comprises a water-bearing
zone, then a decision may be made to avoid or steer away from the
formation boundary 95 (unless, of course it is desired to drill
into a water-bearing zone, for example, in a disposal or
conformance operation, etc.). If it is determined that the
formation 98 comprises a hydrocarbon-bearing zone, then a decision
may be made to steer toward and drill into the formation, delay
setting casing until after drilling into the formation, etc.
[0044] If it is determined that the formation 98 has a
significantly different pore or fracture pressure, or a
significantly different margin between pore and fracture pressures,
as compared to the formation 96, then it may be desirable to: a)
make preparations for increasing or decreasing bottom hole pressure
in the wellbore 12 accordingly, b) avoid drilling into the
formation 98, c) set casing prior to drilling into the formation
98, d) continue to drill ahead into the formation 98 prior to
setting casing, or e) steer toward or away from the formation 98,
etc. If it is determined that the formation 98 is a higher strength
or more stable formation as compared to the formation 96, then a
decision may be made to delay setting casing until after drilling
into the formation 98. If it is determined that the formation 98
should be drilled using another type of drill bit, then the drill
bit 14 may be replaced with the other type of drill bit prior to,
or just as, the formation 98 is drilled into. For example, it may
be beneficial to change between a tri-cone rock bit and a fixed
cutter PDC bit, depending on the characteristics of the formations
96, 98.
[0045] Referring additionally now to FIG. 4, the method 90 is
representatively illustrated in another example for which the
principles of this disclosure may be used advantageously. The drill
string 16 is not depicted in FIG. 4, but it will be understood
that, as described above, the drill string would be used for
drilling the wellbore 12 in the direction indicated by arrow 100.
In this example, it is desired to continue drilling the wellbore 12
through a hydrocarbon-bearing zone 102, and to avoid drilling into
a water-bearing zone 104. The capability of measuring properties of
the earth portion 92 in the path of the wellbore 12, as described
above, enables steering of the wellbore so that it stays in the
zone 102 and avoids the zone 104. Furthermore, formation anomalies
(such as a fracture, karst or fault 106 in the path of the wellbore
12) can be detected before drilling into the anomalies, so that
pertinent decisions (whether to steer toward, drill into or avoid
the fault, etc.) can be made beforehand. If, in the example of FIG.
4, the decision is made to drill through the fault 106, then the
wellbore 12 could be steered so that it continues to drill through
the zone 102 on an opposite side of the fault.
[0046] Referring additionally now to FIG. 5, the method 90 is
representatively illustrated in another example for which the
principles of this disclosure may be used advantageously. In this
example, it is desired to avoid drilling into another wellbore 108
previously drilled into the earth in the path of the wellbore 12.
If the wellbore 108 is present in the earth portion 92 ahead of the
bit 14, then the sensor 60 can detect the presence of the wellbore
(for example, due to the change in density, etc.), whether the
wellbore is open hole or has casing 110 therein. In response, the
wellbore 12 can be steered to avoid drilling into the other
wellbore 108.
[0047] FIG. 6 provides a flowchart to further illustrate the
various stages of the look-ahead response method. Beginning in
block 602 the drillers assemble a drilling system that, among other
things, provides continuous and adjustable control of bottomhole
pressure using any one or more of the techniques described above.
The drilling system would naturally also permit control of other
downhole drilling parameters such as rotations per minute (RPM),
weight on bit (WOB), rate of penetration (ROP), and steering
direction. (To control this last parameter, the drillstring may
include a steering assembly such as a rotary steerable system or
hydraulically actuated steering fins.) The assembled system
includes one or more look-ahead sensors in the drillstring's
bottomhole assembly. In block 604, the drilling system uses these
sensors to collect look-ahead measurements during the drilling
process. The sensors can employ any one or more of the previously
discussed techniques to detect faults, boundaries, boreholes, fluid
interfaces, and/or formation properties such as density, pore
pressure, and fracture pressure.
[0048] In block 606 the system (typically, though not necessarily,
in a data processing unit at the surface) combines the look ahead
measurements with the other available data including borehole logs
to determine the desired drilling parameters at one or more
positions ahead of the bit. Thus, for example, the system may
determine the bottom hole pressure that would be desirable at the
time when the bit reaches the region being surveyed by the
look-ahead sensors, or it may determine the desired steering
direction that would be desirable at that time. In block 608, the
system determines whether an alarm condition exists, i.e., whether
the desired drilling parameters would be incompatible with existing
borehole conditions or with the capabilities of the drilling
system. This situation could arise where the desired bottom hole
pressure would be too high for some of the previously penetrated
formations to tolerate (e.g., high enough to cause undesired
fracturing and/or fluid loss from the borehole), or too high for
the seals on the well head. Conversely, the desired bottomhole
pressure could be too low, enabling fluid inflows from other
formations that could lead to a blow out or to bypass flows from
one formation to another via the borehole. Other alarm examples
include faults, boreholes, boundaries, or interfaces that are
desirable to avoid, but which the steering apparatus is incapable
of steering around.
[0049] If an alarm condition is detected, an alarm is activated in
block 610 to alert the drilling operator to halt drilling or to
re-evaluate the situation before proceeding cautiously. In block
612, the drilling system employs position and rate of penetration
measurements to determine the timing for adjusting the drilling
parameters to the desired drilling parameters. Thus, for example,
the system can maintain the bottomhole pressure at a value that
provides optimal drilling conditions for the current formation, and
can avoid changing that pressure too early or too late. Of course,
the desired parameter values and timing can be adjusted as drilling
progresses and the drilling path changes or the look-ahead
measurements for a given portion of the formation are refined. In
block 614, the drilling system operates at the selected time to
signal the automatic controls and/or the drilling operator to
change the drilling parameter to the desired values. Thus, for
example, the system may increase fluid density and/or increase back
pressure to bring up the bottomhole pressure just before the bit
contacts a high pore pressure formation. At least some method
embodiments include a margin to allow for timing errors. In block
616, the system determines whether drilling has halted and if so,
the method completes. Otherwise the various blocks are repeated
beginning with block 604.
[0050] It may now be appreciated that the above disclosure provides
many benefits to the art of well drilling. The system 10 and method
90 enable drilling operations to be controlled based on real time
measurements of formation properties ahead of the drill bit 14.
More specifically, the above disclosure provides to the art a
drilling method 90 which includes measuring a property of a portion
92 of the earth prior to drilling a wellbore 12 into the earth
portion 92; and varying a drilling parameter in real time while
drilling the wellbore 12, in response to measuring the property.
The earth portion 92 may be at least initially in a path of a drill
bit 14 being used to drill the wellbore 12. Measuring the property
may include measuring at least one of resistivity of the earth
portion 92, acoustic impedance of the earth portion 92, and gamma
counts due to gammas emanating from the earth portion 92. Measuring
the property may include measuring at least one of porosity of the
earth portion 92, pore pressure in the earth portion 92, fracture
pressure of the earth portion 92, density of the earth portion 92,
strength of the earth portion 92, and fluid type in the earth
portion 92. Measuring the property may include detecting the
presence of at least one of water, hydrocarbon fluid, salt, a fault
106, a formation boundary 95 and another wellbore 108. Measuring
the property may include receiving at least one of a geochemical
signal, an isotope reading and a chromatograph reading indicative
of the property of the earth portion 92. Measuring the property may
include characterizing a fluid in the earth portion. Measuring the
property may include detecting the presence of at least one of a
fracture and a karst in the earth portion 92. Measuring the
property may be performed utilizing a resistivity sensor 60
positioned between a fluid motor 94 and a drill bit 14 in a drill
string 16 used to drill the wellbore 12.
[0051] Varying the drilling parameter may include varying pressure
in the wellbore 12. Varying pressure in the wellbore 12 may include
adjusting a flow control device 34, 74, 76, 78, 81. The flow
control device 34 may variably restrict flow through a return line
30 for discharging drilling fluid 18 from an annulus 20 formed
between the wellbore 12 and a drill string 16. The flow control
device 81 may variably restrict flow through a standpipe line 26
for injecting drilling fluid 18 into a drill string 16 used to
drill the wellbore 12. The flow control device 74 may variably
restrict flow between a standpipe line 26 for injecting drilling
fluid 18 into a drill string 16 used to drill the wellbore 12 and a
return line 30 for discharging drilling fluid 18 from an annulus 20
formed between the wellbore 12 and the drill string 16. Varying
pressure in the wellbore 12 may be performed in response to at
least one of: determining that the earth portion 92 comprises
shale, determining that a pore pressure of the earth portion 92 is
greater than that of an already drilled portion, determining that
the pore pressure of the earth portion 92 is less than that of the
already drilled portion, determining that a fracture pressure of
the earth portion 92 is greater than that of the already drilled
portion, determining that the fracture pressure of the earth
portion 92 is less than that of the already drilled portion, and
determining that the earth portion 92 comprises a formation
boundary 95.
[0052] Varying the drilling parameter may include adjusting a flow
control device 34, 74, 81, thereby maintaining a desired pressure
in the wellbore 12. Varying the drilling parameter may include
steering the wellbore 12 and thereby continuing to drill in a
hydrocarbon-bearing zone 102. Varying the drilling parameter may
include steering the wellbore 12 toward the hydrocarbon-bearing
zone 102. Varying the drilling parameter may include steering the
wellbore 12 toward or away from a water-bearing zone 104. Varying
the drilling parameter may include steering the wellbore 12 toward
or away from a fault 106, toward or away from a formation boundary
95, and/or toward or away from another wellbore 108. Varying the
drilling parameter may include changing a drill bit 14 on a drill
string 16 used to drill the wellbore 12.
[0053] The method 90 may also include transmitting a signal
representative of the measured property to a remote location for
analysis prior to varying the drilling parameter. During the
drilling parameter varying, pressure in the wellbore 12 may be
greater than, equal to, or less than pore pressure in an earth
formation exposed to the wellbore 12.
[0054] It is to be understood that the various embodiments of the
present disclosure described above may be utilized in various
orientations, with various types of wellbores and well drilling
systems, 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, and such changes
are contemplated by the principles of the present disclosure.
Accordingly, the foregoing detailed description is to be clearly
understood as being given by way of illustration and example only,
the spirit and scope of the present invention being limited solely
by the appended claims and their equivalents.
[0055] In the above description of the representative embodiments
of the disclosure, directional terms, such as "above," "below,"
"upper," "lower," etc., are used for convenience in referring to
the accompanying drawings. In general, "above," "upper," "upward"
and similar terms refer to a direction toward the earth's surface
along a wellbore, and "below," "lower," "downward" and similar
terms refer to a direction away from the earth's surface along the
wellbore.
* * * * *