METHODS AND APPARATUS FOR MONITORING WELLBORE TORTUOSITY
PRIORITY APPLICATION
[0001] This application claims the benefit of U.S. Provisional Application
Serial No. 62/077,758, filed on November 10, 2014 which application is
incorporated by reference herein in its entirety.
BACKGROUND
[0002] The present disclosu re relates to measuring while drill ing techniques
and, more particularly, to methods and apparatus for measu ring bending
moments in a tool string as an indicator of wel lbore tortuosity, and for using
such measu red bending moments.
[0003] To obtain hyd rocarbons such as oil and gas, boreholes are drilled by
rotating a drill bit attached at a dril l string end. A proportion of the current
drilling activity involves directional drill ing (e.g., drilling deviated and/or
horizontal boreholes) t o steer a wel l towards a target zone and increase
hyd rocarbon production from subterranean formations. Modern directional
drilling systems general ly employ a drill string having a bottom-hole assem bly
(BHA) and a drill bit situated at an end thereof t hat may be rotated by rotating
the drill string from the surface, using a mud motor arranged downhole near
the drill bit, or a combination of the mud motor and rotation of the drill string
from the surface.
[0004] The BHA generally includes a number of downhole devices placed in
close proximity to the drill bit and configured t o measure certain downhole
operating parameters associated with the drill string and drill bit. Such devices
typically include sensors for measuring downhole temperature and pressure,
azimuth and inclination measu ring devices, and a resistivity measuring device
t o determine the presence of hydrocarbons and water. Add itional downhole
instruments, known as logging-while-drilling ("LWD" ) and measu ring- whiledrilling
("MWD") tools, are frequently attached t o the drill string to determine
the formation geology and formation fluid conditions during the drill ing
operations.
[0005] Boreholes are usually drilled generally along predetermined desired
paths identified in a well plan and typically exten d through a plurality of
different earth formations. In the cou rse of such following of a well plan, a
number of adjustments in the drilled well bore trajectory are requ ired in order
t o make adjustments in inclination or azimuth, and even t o maintain drilling in a
gen erally linear path. As a resu lt, during the drilling of a wel l there can be many
adjustments in steering of the bit, and of maintaining direction of a bit, which
result in changes in inclination and/or azimuth .While su rvey measu rements
performed during the drilling of the well can indicate the path of the wel lbore,
which may then be compared t o a wel l-plan, such survey measurements tend
t o present a relatively general ized indication of the well bore path, and can
suggest a smoother well bore profile that actually exists. For example, such
survey measurements provide minimal information regard ing spiraling of the
well bore, or of localized directional shifts (i.e., deflections or "dog-legs"), of
magnitudes that can present greater strains upon a tool string than would be
apparent from conventional survey measu rements. Such spiraling or dog-legs,
or other forms of well bore tortuosity, can be problematic to the dril ling
operations or su bsequent operations within the well .
BRI EF DESCRI PTION OFTHE DRAWINGS
[0006] FIG URES 1 is a schematic diagram of an example dril ling system,
according to an embodiment of the present disclosu re.
[0007] Figu res 2 is a schematic diagram of an example bottom-hole
assem bly, according to one or more embodiments of the present disclosure.
[0008] Figu res 3 is a schematic representation of a generalized wellbore
traversing a plurality of su bterranean formations.
[0009] Figu res 4A-B, are graphical representations of example bending
moment measurements under different loads as might be determined in an
example wellbore; in which Figure 4A compares example determined bending
moments under tension with example determined bend ing moments under
drilling conditions (i.e., during compression ); and in which Figure 4B compares
example determined bend ing moments under tension with example
determined bending moments under drilling condition s as a function of
direction.
[0010] Figu res 5 is a graphic depiction of a dog-leg severity as determined
from the measu red bending moment compared to expected val ues of dog-leg
severity.
[0011] Figu re 6 is a graph ical representation of an example dog-leg severity
index determined from the bending moment, in comparison with a dog-leg
severity as determined from survey data.
[0012] Figu res 7 is a flow chart of an example method of performing
operations for mon itoring wel lbore tortuosity as described herein.
DETAILED DESCRI PTION
[0013] The following detailed description refers t o the accompanying
drawings that depict various details of examples selected t o show how
particu lar embodiments may be implemented. The discussion herein addresses
various examples of the inventive su bject matter at least partial ly in reference
t o these drawings and describes the depicted embodiments in sufficient detail
t o enable those skil led in the art to practice the invention. Many other
embodiments may be utilized for practicing the inventive su bject matter than
the illustrative examples discussed herein, and many structu ral and operational
changes in addition to the alternatives specifical ly discussed herein may be
made without departing from the scope of the inventive su bject matter.
[0014] The present disclosu re describes various methods and apparatus for
monitoring wel lbore tortuosity the measurements of bending moments within
a drillstring or tool string. In some example embod iments, the bending
moments within the tool string will be monitored, either over selected intervals
of time or depth, or essential ly continuously. In some examples, though the
bending moments may be measu red essentially continuously, they may be
averaged together over selected periods, for example of time or depth, to
facilitate further analysis. In some of these examples, the bending moments
with in the tool string will be measured through use of an assem bly having a
plurality of strain gauges. In many such examples the strain gauges will be
arranged in a selected spacing around the circu mference of the tool string, in
many examples at a common plane extending generally perpendicu lar to the
longitudinal axis of the string proximate the strain gauges. In some
embodiments, the measurements from the plu ral ity of strain gauges at
essentially a common point in time will be correlated to define a bending
moment present on the string. In many examples, however the bending
moments may be determined, they will be further evaluated to provide a
measure of well bore tortuosity. For example, the bending moments may be
utilized to define a rad ius of cu rvature associated with the determined bending
moments in some examples, the determined radius of cu rvature may be further
correlated with a directional measurement that may be referenced, for
example, to a high or low side of the well bore, and/or to a azimuthal
orientation to thereby facilitate applying a direction to the bending moment,
and therefore to the tortuosity. In many examples, the above measu rements
and determinations will be performed in essentially real time during a drilling
operation. The determinations as to well bore deflections and/or tortuosity can
be used to perform remedial measures, where dictated .
[0015] Referring to Figure 1, illustrated is an exemplary drilling system 100
that can be used in concert with one or more embodiments of the present
disclosure. Boreholes are created by drill ing into the earth 102 using the drilling
system 100. The drilling system 100 is configu red to drive a bottom hole
assem bly (BHA) 104 positioned at the bottom of a drill string 106 extended into
the earth 102 from a derrick 108 arranged at the su rface 110. The derrick 108
includes a kelly 112 used to lower and raise the drill string 106.
[0016] The BHA 104 includes a drill bit 114 and a tool string 116 which is
moveable axially within a drilled wellbore 118 as attached to the drill string 106.
Du ring operation, the drill bit 114 is provided with sufficient weight on bit
(WOB) and torque on bit (TOB) to penetrate the earth 102 and thereby create
the wellbore 118. The BHA 104 also provides directional control of the drill bit
114 as it advances into the earth 102. The depicted example BHA 104 can
include one or more stabilizers, a mud motor, and/or other components for
steering the path of the drill bit 114 during a drill ing operation, so as to create a
well bore consistent with a pre-defined well plan.
[0017] The tool string 116 can be semi-permanently mounted with various
measurement tools (not shown ) such as, but not limited to, measurementwhile-
drilling (MWD) and logging-while-dril ling (LWD) tools, that are configured
to take downhole measurements of drilling cond itions. In other embod iments,
the measurement tools are self-contained within the tool string 116, as shown
in Figure 1. As is apparent from the above discussion, the term "tool string," as
used herein, includes a drill string, as well as other forms of a tool string known
in the art.
[0018] Drilling fluid or "mud" from a mud tank 120 is pumped down hole
using a mud pump 122 powered by an adjacent power sou rce, such as a prime
mover or motor 124. The mud is pumped from the mud tan k 120, through a
stand pipe 126, which feeds the mud into the drill string 106 and conveys the
same to the drill bit 114. The mud exits one or more nozzles arranged in the
drill bit 114 and in the process cools the drill bit 114. After exiting from the drill
bit 114, the mud circulates back to the su rface 110 via the an nulus defined
between the wel lbore 118 and the drill string 106, and in the process returns
drill cuttings and debris to the surface. The cuttings and mud mixtu re are
passed through a flow line 128 and into a shaker and optional centrifuge (not
shown), which separates the majority of solids, such as cuttings and fines, from
the mud, and returns the cleaned mud down hole through stand pipe 126 once
again .
[0019] A telemetry su b 130 coupled to the BHA transmits telemetry data to
the su rface via mud pulse telemetry. A transmitter in the telemetry su b 130
modulates a resistance to drilling fluid flow to generate pressure pulses that
propagate along the fluid stream at the speed of sound to the surface. One or
more pressure transducers convert the pressure signal into electrical signal (s)
for a signal digitizer. Note that other forms of telemetry exist and may be used
t o communicate signals from downhole to the digitizer. Such telemetry may
employ acoustic telemetry, electromagnetic telemetry, or telemetry via wired
drillpipe.
[0020] A digital form of the telemetry signals is supplied via a
communications link 132 t o a processing unit 134 or some other form of a data
processing device. In some examples, the processing unit 134 (which may be a
conventional "computer" such as il lustrated in Figu re 1 or in any of a variety of
known forms) provides a suitable user interface and can provide and control
storage and retrieval of data. In many examples, the processing unit 134 will
include one or more processors in combination with additional hardware as
needed (volatile and/or non-volatile memory; commun ication ports; I/O
device(s) and ports; etc.) to provide the control functionality as described
herein. An example processing unit 134 can serve t o control the functions of
the drill ing system 100 and t o receive and process downhole measu rements
transmitted from the telemetry su b 130 to control drilling parameters. In such
examples, one or more a non-volatile, machine-readable storage devices 136
(i.e., a memory device (such as DRAM, FLASH, SRAM, or any other form of
storage device; which in all cases shall be considered a non-transitory storage
med ium), a hard drive, or other mechanical, electronic, magnetic, or optical
storage mechan ism, etc.) will contain instructions suitable to cause the
processor t o describe the desired functionality, such as the various examples
discussed herein ). The processing unit 134 operates in accordance with
software (which may be stored on non-volatile, mach ine-reada ble storage
devices 136) and user in put via an input device 138 t o process and decode the
received signals. The resulting telemetry data may be further analyzed and
processed by the processing unit 134 to generate a display of useful
information on a computer monitor 140 or some other form of a display device.
Of course, these functions may be implemented by separate processing units,
as desired, and additional functions may be performed by such one or more
processing units in response t o similarly stored instructions.
[0021] For purposes of illustration, the example of Figure 1 shows a
vertically-oriented borehole configuration, though persons skilled in the art that
boreholes wil l often be formed in a wide variety of configu rations, includ ing in
some cases some generally horizontally extending portions (as addressed in
more detail relative t o Figure 3 herein). Although the drilling system 100 is
shown and described with respect t o a rotary drill system in Figu re 1, those
skilled in the art will read ily appreciate that many types of drilling systems can
be employed in carrying out embodiments of the disclosure. For instance, dril ls
and drill rigs used in embodiments of the disclosu re may be used onshore (e.g.,
as depicted in Figu re 1) or in offshore environ ments as wel l, such as for subsea
operations (not shown). In particu lar, offshore or su bsea operations may
include use of the MWD/LWD drilling apparatus and techniques including
aspects of the examples herein. Offshore oil rigs that may be used in
accordance with embod iments of the disclosure include, for example, floaters,
fixed platforms, gravity-based structures, drill ships, semi-su bmersi ble
platforms, jack-up drilling rigs, tension-leg platforms, and the like; and
embodiments of the disclosu re can be applied t o rigs ranging anywhere from
smal l and portable to bul ky and permanent.
[0022] Fu rther, although described herein with respect t o oil drilling,
various embodiments of the disclosure may be used in many other applications.
For example, disclosed methods can be used in drill ing for mineral exploration,
environ mental investigation, natu ral gas extraction, undergrou nd installation,
mining operations, water wells, geothermal wells, and the like.
[0023] Referring now to Figure 2, with continued reference t o Figure 1,
illustrated is an exemplary bottom-hole assem bly (BHA) 104 that can be
employed in concert with one or more embodiments of the present disclosure.
Although described throughout with respect t o a BHA, the embodiments
described herein can be alternatively or add itionally applied at multiple
locations t hroughout a drill string, and are therefore not limited to the
gen eralized location with in only a conventional BHA (i.e., at the bottom of a
drill string). As shown, the BHA 104 includes the drill bit 114, a rotary steera ble
tool 202, an MWD/LWD tool 204, and a drill collar 206.
[0024] The MWD/LWD tool 204 further includes an MWD sensor package
having one or more sensors 216 of an appropriate configuration to collect and
transmit one or more of directional information, mechan ical information,
formation information, and the like. In particular, the one or more sensors 216
include one or more internal or external sensors such as, but not limited to, an
inclinometer, one or more magnetometers (i.e., compass units) or other
azimuthal sensor, one or more accelerometers (or other vibration sensor), a
shaft position sensor, an acoustic sensor, as well as other forms of sensors
(such as various forms of formation sensors), as well as combinations of the
above. The distance between the sensors 216 and the drill bit 114 can be any
axial length requ ired for the particu lar wel lbore application. Directional
information (e.g., wellbore trajectory in three-dimensional space) of the BHA
104 within the earth 102 (Figure 1), such as inclination and azimuth, can be
obtained in real-time using the sensors 216.
[0025] The MWD/LWD tool 204 can further include a formation sensor
package that includes one or more sensors configured to measure formation
parameters such as resistivity, porosity, sonic propagation velocity, or gamma
ray transmissibility. In some embodiments, the MWD and LWD tools, and their
related sensor packages, are in commu nication with one another to share
collected data. The MWD/LWD tool 204 can be battery driven or generator
driven, as known in the art, and any measu rements obtained from the
MWD/LWD tool 204 can be processed at the surface 110 (Figure 1) and/or at a
downhole location.
[0026] The drill col lar 206 is configured to add weight to the BHA 104 above
the drill bit 114 so that there is sufficient weight on the drill bit 114 to drill
t hrough the req uisite geological formations. In oth er embodiments, weight is
also applied to the drill bit 114 t hrough the drill string 106 as extended from the
surface 110. Weight may be added or removed to/from the drill bit 114 during
operation in order to optimize drilling performance and efficiency. For example,
the curvature of the borehole can be pred icted and the weight applied t o the
drill bit 114 optimized in order t o take into account drag forces or friction
caused by the cu rvature. As will be appreciated, increased amounts of drag
forces will be present where the borehole cu rvature is more dramatic.
[0027] The BHA 104 further includes a sensor su b 208 cou pled t o or
otherwise forming part of the BHA 104. The sensor su b 208 is configu red to
monitor various operational parameters in the downhole environment with
respect t o the BHA 104. For instance, the sensor su b 208 can be configu red t o
monitor operational parameters of the drill bit 114 such as, but not limited to,
weight-on-bit (WOB), torque-on-bit (TOB), rotations per minute (RPM) of the
drill bit 114, bending moment of the drill string 106, vibration potential ly
affecting the drill bit 114, and the like. As illustrated, the sensor su b 208 is
positioned uphole from the MWD/LWD tool 204 and the drill col lar 206. In
other embodiments, however, the sensor su b 208 can be positioned at any
location along the BHA 104 without departing from the scope of the disclosu re.
In order t o measure the bending moment, the sensor su b 208 wil l preferably
include a plu rality of strain gauges. For purposes of the presently described
methods and apparatus, the strain gauges will inclu de a plu rality of groups of
strain gauges, with each group includ ing at least two strain gauges oriented t o
measure strain in orthogonally-oriented directions. Preferably, at least one
strain gauge in each grou p will be oriented to measure strain on an axis parallel
t o the longitudinal axis through the sensor sub.
[0028] In some embodiments, the sensor su b 208 is a DRILLDOC® tool
commercially available from Sperry Drill ing of Houston, Texas, USA. The
DRI LLDOC® tool, or another similar type of sensor sub 208, can be configured t o
provide real-time measurements of weight, torque and bending on an adjacent
cutting tool (e.g., the drill bit 114) and/or drill string 106 t o characterize the
transfer of energy from the surface t o the cutting tool and/or drill string 106.
For example, the DRI LLDOC® tool is a MWD tool which is placed inside the drill
collar 206 t o provide the real-time measu rements of tension, torsion, bending,
and vibration at the drill collar 206. The strain force and torque measu rements
from the DRI LLDOC® tool are used to estimate the bit force and torque. As will
be appreciated, these measurements help optimize drilling parameters t o
maximize performance and minimize wasted energy transfer and vibration.
[0029] The DRI LLDOC® sensor su b 208 includes t hree groups of strain
sensors distributed at positions azimuthally offset at essentially 120° apart from
one another around the periphery of the sub. The DRI LLDOC® sensor sub
includes four strain gauges in each group that are oriented axial ly (i.e. general ly
parallel to the longitudinal axis through the sub) to measu re tension and
compression of the BHA; and four strain gauges in each grou p that are oriented
orthogonally to the axially oriented gauges (i.e., extending lateral ly, generally
perpend icular relative t o the longitudinal axis t hrough the su b) to measu re the
torque present in the su b. The axially oriented strain gauges are also used t o
define the bend ing moment which results from varia ble tension and
compression in the su b under applied axial load. These strain gauges are in a
known configuration relative t o an orienting sensor for the su b or drillstring t o
identify the direction of any identified bending moment under the applied axial
load . As a resu lt, both the magnitude and direction of a deflection in the
well bore resu lting in the bending moment can be identified .
[0030] The BHA 104 further includes a bi-directional communications
module 210 coupled t o or otherwise forming part of the drill string 106. The
communications module 210 can be communicably coupled to each of the
sensor su b 208 and the MWD/LWD tool 204 (e.g., its sensor(s) 216) via one or
more communication lines 212 such that the communications mod ule 210 is
configured to send and receive data to/from the sensor su b 208 and the
MWD/LWD tool 204 in real time.
[0031] The communications module 210 can further be commun icably
coupled to the surface (not shown) via one or more communication lines 214
such that the communications module 210 is able t o send and receive data in
real time to/from the su rface 110 (e.g., from Figure 1) during operation. For
instance, the communications modu le 210 communicates t o the surface 110
various downhole operational parameter data as acq uired via the sensor su b
208 and the MWD/LWD tool 204. In other embodiments, however, the
communications module 210 com municates with a computerized system (not
shown) or the like configu red to receive the various downhole operational
parameter data as acquired through the sensor sub 208 and the MWD/LWD
tool 204. As will be appreciated, such a computerized system arranged either
downhole or at the surface 110.
[0032] The communication lines 212, 214 can be any type of wired
telecommunications devices or means known to those skilled in the art such as,
but not limited to, electric wires or lines, fiber optic lines, etc. For instance, in
some embodiments, a wired dril l pipe (not shown) is used for two-way data
transmission between the surface 110 and the communications module 210.
Using a wired drill pipe, the BHA 104 and the drill string 106 have electrical
wires built in to one or more of their components such that measurements and
signals from the MWD/LWD tool 204 and the sensor su b 208 are carried
directly to the su rface 110 at high data transmission rates. Alternatively or
add itionally, the communications modu le 210 includes or otherwise comprises
a telemetry module used to transmit measu rements to the surface 110
wirelessly, if desired, using one or more downhole telemetry techn iques
including, but not limited to, mud pulse, acoustic, electromagnetic freq uency,
com binations thereof, and the like.
[0033] Referring now to Figure 3, that figure is a schematic representation
of a generalized wellbore, indicated generally at 300, traversing a plurality of
su bterranean formations, indicated generally at 302. Well bore 300 extends
from a wellhead, 304 at the surface and extends in a general ly vertical section,
indicated generally at 306. A first radius, indicated generally at 308, causes the
well bore to extend azimuthally relative to the general ly vertical section 306,
initially in a general ly linear inclined region, indicated general ly at 310, before
reaching a another radius, ind icated general ly at 312, causing well bore 300 to
extend along a generally horizontal path, as indicated at 314. While inclined
region 310 is generally linear, the specific path is not entirely linear, by virtue of
deflection points (or "dog-legs"), as shown at 316, 318, 320, and 322. Such doglegs
(deflections) in the wellbore can occur as a resu lt of subsurface anomalies
that impede direction of the bit in a controlled manner or by the alternation
between a period of steering the bit and a period of non-steering of the bit, as
commonly occurs during a directional drilling operation.
[0034] The passage of the tool string past each of these deflection points
316, 318, 320, and 322 will impose some bend ing moment upon the tool string.
As described herein, the present invention provides an apparatus to measu re
these bend ing moments, when imposed, which can faci litate both identification
of the location of a local discontinuity in the wellbore path (which may be
either a deviation from an identified radius, or from a linear path), and
determination of the magnitude, or severity, of the dog-leg. In selected
embodiments, a plu ral ity of determined dog-legs and their severities will be
compiled over at least some portion of the length of the wellbore, and can then
be used to determine a dog-leg severity index as a function of depth within the
well bore. Use of such a dog-leg severity index facilitates performing of
su bseq uent operations within the wellbore, as discu ssed in more detail later
herein.
[0035] The radius of curvatu re (Rc) at a location with in the wel lbore,
expressed in degrees/100 ft., can be determined from the measured bend ing
moment such as through the following relation :
Rc = (M/El) X (180/ ) eq . 1
Where:
M = the measured bending moment (ft-l bs);
E=the modulus of elasticity of the tool string; and
I = the moment of inertia, which, for a cylindrical pipe can be expressed as:
Where:
d =the outer diameter of the pipe; and
d = the in ner diameter of the pipe.
In complex tools containing non-homogeneous cross-sections that incl ude
electronics and wiring, the equivalent stiffness dimensions of the components
can be used .
[0036] Referring now to Figure 4A-B, those figures depict graphical
representations of example bending moment measurements under different
loads as might be determined in an example well bore; in which Figure 4A
compares example determined bending moments with the tool string under
tension, in cu rve 402 with example determined bending moments with the tool
string under dril ling cond itions (i.e., with the tool string in compression), in
curve 404; and in which Figure 4B compares example determined bending
moments under tension as a function of direction, in curve 406, with
corresponding determined bend ing moments under dril ling conditions, in curve
408. In Figure 4B, 0° represents the high side of the well bore.
[0037] Referring now to Figure 4A, the bend ing moments determined
under tension and compression are generally compara ble. When the tool string
is in tension the tool string should be generally straight, at least between
sta bil ized locations, but for a deflection in the well bore acting upon the tool
string. The general correspondence between the direction of the bending
moment under both tension and compression, as shown in Figu re 4B, further
indicates that the identified bend ing moment should be a function of the
well bore conformation, and not some other anomaly.
[0038] Referring now to Figure 5, the figure is a graphic depiction of a dog
leg severity determined from the measured bending moment, indicated a curve
502, in comparison to both: a calculated dog-leg severity based upon a
minimu m curvature analysis of the well plan, indicated at locations 504a-i, and
a dog-leg severity as could be determined from wel l su rvey measu rements,
indicated by cu rve 506. As can be seen from the locations of the well plan
minimu m curve analysis, the path of the reflected wel lbore would be a
gen erally smooth and continuous one. The dog-leg severity as determined from
the su rvey information, at 506, reflects significantly greater tortuosity than
wou ld be anticipated from the well plan. However the dog-leg severity as
determined from the measu red bending moments reflects far greater
tortuosity, and more significant localized curvatu re, than is suggested by the
survey-based dog-leg severity.
[0039] Referring now to Figure 6, that figure is a graphical representation of
an example dog-leg severity index determined from the measu red bending
moment, depicted by curve 602 in comparison with a dog-leg severity as
determined from su rvey data, depicted by curve 604. In comparing the
measured dog-leg severity 604, with an expected dog-leg severity (not shown )
supports the derivation of the dog-leg severity index. The value of "one" (1)
indicates that the survey-determined-dog-leg severity and the bend ing
moment-measu red dog-leg severity are the same, and no additional tortuosity
exists. In the depicted example, the dogleg severity is relatively mild, and even
the measured dog-leg severities are likely wel l with in design tolerances.
However, the example il lustrates the graphical identification of the magnitude
of dog-leg severity in various locations within the well bore in a form that may
be used to guide further drilling and/or other operations within the same well,
and/or to guide drilling in other wells with in the geograph ical area.
[0040] A dog-leg severity index based upon the measured bending
moments can be determined by relationship such as the following (which is
similar to equation 1 above but which factors in the differences between an
expected bending moment and a measured bending moment):
Rc = ( - M ) 2 /(EI) X (180/ p ) eq. 4
Where:
M = the bend ing moment as determined from the strain gauge measurements;
and
Me = the expected bend ing moment, which may be based, for example, on
survey measurements or the well plan .
[0041] Deviation of the bending moment-based dog-leg severity from
either the well plan or su rvey measu rements may be indicative of performance
characteristics of the BHA configuration used in the wel l . In some example
operations it may be desira ble to change the configuration of the BHA for
continued drilling and that well or for use in nearby wel ls. In some example
operations, the configu ration or the method of operation of a given BHA may
result in greater than expected dog-leg severity, and therefore may be used to
change the method of operation of the BHA to minimize such effects.
Additional ly, the bending moment-based dog-leg severity index may be used to
define a well path for future wells in the area, as it provides a measu re of the
capability of not only a given BHA, but also of potential formation tendencies
upon a wel l plan using that BHA.
[0042] For example, remedial actions may be undertaken to minimize the
severity of a dog-leg at one or more locations, for example, so as to facilitate
placement of casing with in the wel lbore, including the cementing of the casing.
As just one example, the dog-leg severity index can be used to identify when
there is spiraling of the wellbore, caused by the drill bit travel ing in a generally
spiral ing path, leading to highly rugose su rfaces defining the wellbore, which
can complicate subseq uent cementing of a casing in place. In cases where the
dog-leg severity index indicates such spiraling, it may be possible to enlarge
that portion of the wel lbore, such as t hrough use of a reamer t o minimize the
undesira ble properties in that section of the well bore, by changing the
dimensions of the well bore in that region . Other types of wellbore operations
may be performed as a result of the identified areas of dog-leg severity,
including wellbore conditioning (such as by extended circulating times and/or
add itives placed into the wellbore, by reaming or otherwise enlarging portions
of the wellbore, or other operations, as will be apparent to persons skil led in
the art.
[0043] Referring now to Figure 7, the Figure depicts a flow chart 700 of an
example method of performing operations as described herein . At step 702, a
measurement will be made of strainer deflection of the tool string within a
well bore. At 704, a first bending moment on the tool string will be determined
in response t o that measure deflection or strain, as measured at a first location
with in the wel lbore. At 706, a second bend ing moment on the tool string will be
determined in response t o a measured deflection or strain at a second location
with in the wel lbore. And at 708, a measure of dog-leg severity will be
determined in response t o at least one of the first and second determined
bending moments, as described earlier herein. Optionally, it may be desired t o
determine the dog-leg severity index for the tool string within the wellbore in
reference t o the first and second determined bending moments, as ind icated at
710. The dog-leg severity index may be configured in such a way as t o provide
an indication of the magnitude of the dog-leg severity over a desired section of
the wellbore, or may be configured, as described earlier herein to provide a
comparison of the dog-leg severity relative t o one or more expected dog-leg
magnitudes. In many implementations, the comparison will be a visually
identifiable indicator of the measured dog-leg such as the graphical
representations as shown in Figures 5 and 6. Also optionally, as indicated at
712, either a determined dog-leg severity index or at least one of the first and
second determined bending moments can be used t o perform a well bore
operation, either in the well bore containing the tool string or in a another
well bore. As described earlier herein, a variety of different types of operations
may be performed based upon the information provided by the determined
bending moments present upon the tool string and/or an index of the severity
of the dog-leg associated with such bending moments.
[0044] In some embodiments, the present disclosure may be embodied as a
set of instructions on a computer reada ble medium comprising ROM, RAM, CD,
DVD, hard drive, flash memory device, or any other non-volatile, machinereadable
storage devices, now known or unknown, that when executed causes
one or more processing units of a computerized system (such as processing unit
134 of Figu re 1) to implement a method of the present disclosure, for example
the method described in Figure 10.
[0045] In some examples, the processing unit 134 (which may be a
conventional "computer" (in any of a variety of known forms)) provides a
suitable user interface and can provide and control storage and retrieval of
data. In many examples, the processing unit 134 will include one or more
processors in combination with add itional hardware as needed (volatile and/or
non-volatile memory; communication ports; I/O device(s) and ports; etc.) to
provide the control functionality as described herein. An example processing
unit 134 can serve t o control the functions of the drilling system and to receive
and process downhole measurements from the sensor subs to estimate bit
forces and control drilling parameters. In such exa mples, one or more a non
volatile, machine-reada ble storage devices (i.e., a memory device (such as
DRAM, FLASH, SRAM, or any other form of storage device; w hich in all cases
shall be considered a non-transitory storage medium ), a hard drive, or other
mechanical, electron ic, magnetic, or optical storage mechan ism, etc. ) will
contain instructions suitable to cause the processor to describe the desired
functionality, such as the various examples discussed herein). Of cou rse, these
functions may be implemented by separate processing units, as desired, and
add itional functions may be performed by such one or more processing units in
response t o similarly stored instructions.
[0046] In some embodiments, a portion of the operations, such as those set
forth in reference t o Figu re 7, and elsewhere herein may be performed
downhole, by a processing unit in the BHA, while another portion may be
performed by a processing unit at the su rface, as discussed in reference t o
Figure 1. As just one example, bending moments might be determined
downhole in reference t o measurements from the strain gauges (or other
deflection measurement sensors), and then communicated to the su rface, as
described herein, for correlation with predicted or planned bending moment
val ues. In such case, each processing unit will include some machine-readable
storage mechan ism containing at the instructions necessa ry t o cause the
processer at that location to perform the operations to be performed at that
location.
[0047] Though method of performing the described measu rements and
determinations are described serially in the examples of FIGS. 1-7, one of
ordinary skill in the art will recognize that other examples may reorder the
operations, omit one or more operations, and/or execute two or more
operations in parallel using multiple processors or a single processor organized
as two or more virtual mach ines or sub-processors. Moreover, still other
examples can implement the operations as one or more specific interconnected
hardware or integrated circuit modules with related control and data signals
communicated between and through the mod ules. Thus, any process flow is
applicable to software, firmware, hardware, and hybrid implementations.
[0048] In this description, references to "one embodiment" or "an
embodiment," or to "one example" or "an example" mean that the feature
being referred to is, or may be, included in at least one embodiment or
example of the invention. Separate references to "an embodiment" or "one
embodiment" or to "one example" or "an example" in this description are not
intended to necessarily refer to the same embod iment or example; however,
neither are such embodiments mutually exclusive, unless so stated or as will be
read ily apparent to those of ordinary skill in the art having the benefit of this
disclosure. Thus, the present disclosu re includes a variety of combinations
and/or integrations of the embodiments and examples described herein, as
well as further embodiments and examples as defined within the scope of all
claims based on this disclosure, as wel l as all legal equivalents of such claims.
[0049] In no way should the embodiments described herein be read to
limit, or define, the scope of the disclosu re. Embodiments described herein
with respect to one implementation, such as MWD/LWD, are not intended to
be limiting.
[0050] The accompanying drawings that form a part hereof, show by way of
illustration, and not of limitation, specific embod iments in which the subject
matter may be practiced. The embodiments illustrated are described in
sufficient detail to enable those skilled in the art to practice the teachings
disclosed herein. Other embodiments may be used and derived therefrom, such
that structu ral and logical substitutions and changes may be made without
departing from the scope of this disclosure. This Detailed Description,
therefore, is not to be taken in a limiting sense, and the scope of various
embodiments is defined only by the appended claims, along with the full range
of equivalents to which such claims are entitled.
[0051] Although specific embodiments have been illustrated and descri bed
herein, it should be appreciated that any arrangement calculated to ach ieve the
same purpose may be su bstituted for the specific embodiments shown . This
disclosure is intended to cover any and all adaptations or variations of various
embodiments. Combinations of the above embod iments, and other
embodiments not specifically described herein, will be apparent to those of skil l
in the art upon reviewing the above description.

CLAIMS
What is claimed is:
1. A method for monitoring wel lbore tortuosity through a tool string,
comprising:
measuring deflection of the tool string at a plu ral ity of locations surround ing
the tool string when the tool string is at a first depth within the
well bore;
determining a first bend ing moment on the tool string in response t o the
measured deflection; and
determining a first measure of dog-leg severity in response t o the determined
first bending moment.
2. The method of claim 1, further comprising;
measuring deflection of the tool string at a plurality of locations surrounding
the tool string when the tool string is at a second depth within the
well bore;
determining a second bend ing moment on the tool string in response t o the
measured deflection at the second depth; and
determining a second measure of dog-leg severity in response t o the
determined second bending moment.
3. The method of claim 2, further comprising determ ining a dog-leg
severity index in reference t o the first and second measures of dog-leg severity,
and to an expected dog-leg severity.
4. The method of claim 3, wherein the deflection of the tool string is
measured at a plurality of radially spaced locations around the tool string
wherein the locations are placed at essentially a common depth along the tool
string.
5. The method of claim 4, wherein the plurality of rad ially spaced locations
around the tool string where deflection is measured comprises at least three
locations at a common depth along the tool string.
6. The method of claim 2, further comprising esta blish ing a graph ical
representation of the deflection of the wellbore at the first and second depths
in the wellbore.
7. An apparatus for monitoring wellbore tortuosity through a tool string,
comprising:
a tool string having a plurality of groups of strain gauges,
wherein the groups are arranged around the periphery of a tool in the
tool string,
wherein each strain gauge grou p comprises at least two strain gauges
arranged to measure strain relative to at least two perpendicular
axes, and
wherein the groups of strain gauges are symmetrically arranged relative
to a common plane extending generally perpend icular to the
tool sting proximate the location of the strain gauges;
one or more processors in communication with one or more machine reada ble
med ia bearing instructions, which when executed by the one or more
processors, collectively perform operations comprising,
receiving a first set of measurements from strain gauges in the plurality
of groups of strain gauges,
determining a first bend ing moment on the tool string in response to
first set of measurements; and
determining a first measure of dog-leg severity in response to the
determined first bending moment.
8. The apparatus of claim 7, wherein the operations further comprise:
receiving a second set of measurements from strain gauges in the plu rality of
grou ps of strain gauges,
determining a second bend ing moment on the tool string in response to the
second set of measurements; and
determining a second measure of dog-leg severity in response to the
determined second bending moment.
9. The apparatus of claim 8, wherein the operations further comprise
creating a dog-leg severity index based at least in part on the first and second
measures of dog-leg severity.
10. A method for evaluating a drilling operation, comprising:
measuring deflection of a tool string relative to a first axis at a plurality of
depths with in a well bore, the deflection measu red by measuring strain
in a component of a drillstring at each of the plurality of depths, the
strain measured at a plu rality of azimuthal ly offset locations around the
component at each of the plurality of depths;
determining a bending moment on the drillstring at each of the plurality of
depths in response to the measured deflection at su ch depth; and
determining directional shifts of the well bore in response to the measured
bending moments at each of the plurality of depths.
11. The method of claim 10, further comprising determining a measu re of
the directional shifts of the well bore in reference to both the directional sh ifts
of the wellbore as determined from the measured bending moments and also
the expected directional shifts of the well bore.
12. The method of claim 11, further comprising changing the wel lbore in
response to the determined measure of the directional shifts of the wellbore.
13. The method of claim 12, wherein changing the well bore in response to
the determined measure of the directional sh ifts of the wellbore incl udes
enlarging a portion of the wellbore.
14. The method of claim 11, wherein determining a measure of the
directional shifts of the wellbore comprises determ ining a dogleg severity
index.
15. The method of claim 10, further comprising measuring lateral deflection
of a tool string at the plurality of depths with in the wel lbore, the lateral
deflection measured by determining strain in the lateral direction of the tool
string at a plurality of azimuthally offset locations around the tool string.
16. An apparatus for monitoring directional shifts in a wel lbore, comprising:
a tool string having a measurement tool comprising a plu rality of strain gauges
azimuthally offset from one another around the periphery of the
measurement tool, each strain gauge arranged to measure strain in a
longitudinal direction;
one or more processors;
one or more machine reada ble media in communication with one or more of
the processors, the machine reada ble media bearing instructions, which
when executed by the one or more processors, col lectively perform
operations comprising,
receiving measurements from the strain gauges at a plurality of depths
in the wellbore,
determining a first bend ing moment on the tool string at at least one
depth in the well bore in response to the received
measurements; and
establishing a visually identifiable indicator of the deflection of the
well bore at least one depth in the wellbore in response to the
determined first bending moment.
17. The apparatus of claim 16, wherein the instructions, when executed by
the one or more processors, perform further operations, comprising
determining additional bending moments on the tool string at additional
depths in the wellbore.
18. The apparatus of claim 16, wherein the visually identifiable indicator of
the deflection of the well bore comprises a graphica l representation.
19. The apparatus of claim 16, wherein the visually identifiable indicator of
the deflection of the well bore includes an indication of the magnitude of the
deflection of the wellbore relative to a planned deflection of the wellbore at
the at least one depth in the well bore.
20. The apparatus of claim 17, wherein the visually identifiable indicator of
the deflection of the well bore comprises a graphica l representation of the
deflection of the wellbore relative to a planned deflection of the wellbore at a
plurality of depths in the well bore.