TECHNICAL FIELD
The present disclosure relates generally to rotary steerable tools and, more particularly, to
systems and methods for packaging gamma radiation sensors in the rotating section of rotary
steerable tools.
BACKGROUND
Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations
that may be located onshore or offshore. The development of subterranean operations and the
processes involved in removing hydrocarbons from a subterranean formation typically involve a
number of different steps such as, for example, drilling a wellbore at a desired well site, treating
the wellbore to optimize production of hydrocarbons, and performing the necessary steps to
produce and process the hydrocarbons from the subterranean formation.
Wellbores are created for a variety of purposes, including exploratory drilling for locating
underground deposits of different natural resources, mining operations for extracting such
deposits, and construction projects for installing underground utilities. Wellbores are often
drilled vertically through a subterranean formation. However, in many applications it is
desirable to drill wellbores that have vertically deviated or horizontal geometries. A well-known
technique employed for drilling horizontal, vertically deviated, and other complex boreholes is
directional drilling. Directional drilling is generally typified as a process of boring a hole which
is characterized in that at least a portion of the course of the bore hole in the earth is in a
direction other than strictly vertical—i.e., the axes make an angle with a vertical plane (known as
"vertical deviation"), and are directed in an azimuth plane.
Various options are available for providing steering capabilities to a drilling tool for
controlling and varying the direction of the wellbore. For example, directional drilling may also
be accomplished with a "rotary steerable" drilling system wherein the entire drill pipe string is
rotated from the surface, which in turn rotates the bottom hole assembly (BHA), including the
drilling bit, connected to the end of the drill pipe string. In a rotary steerable drilling system, the
drilling string may be rotated while the drilling tool is being steered either by being pointed or
pushed in a desired direction (directly or indirectly) by a steering device. Some rotary steerable
drilling systems include a component which is non-rotating relative to the drilling string in order
to provide a reference point for the desired direction and a mounting location for the steering
devices. Other rotary steerable drilling systems may be "fully rotating". Rotary steerable
drilling systems can provide relatively high steering accuracy for directional drilling operations.
Directional drilling typically involves controlling and varying the direction of the
wellbore as it is being drilled. Oftentimes the goal of directional drilling is to reach a position
within a target subterranean destination or formation with the drill string. Downhole sensors in
the rotary steerable system can be used to evaluate the formations being drilled through, in order
to determine what changes in direction of the rotary steerable tool should be made. Some
downhole tools utilize gamma detection sensors that are designed to measure an amount of
natural gamma radiation emitted from a subterranean formation. Such information can be useful
since pay-zones and formations containing oil will oftentimes emit more gamma radiation than
less productive formations. Unfortunately, gamma detection sensors are often housed in nonrotating
parts of the drill string, or located far above the drill bit, making it difficult to base quick
directional decisions on the sensed gamma radiation.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present disclosure and its features and
advantages, reference is now made to the following description, taken in conjunction with the
accompanying drawings, in which:
FIG. 1 is a schematic illustration of a drilling system with a rotary steerable tool, in
accordance with an embodiment of the present disclosure;
FIG. 2 is a partial cutaway side view of components of a rotary steerable tool, in
accordance with an embodiment of the present disclosure;
FIG. 3 is a perspective view of components of the rotary steerable tool of FIG. 2, in
accordance with an embodiment of the present disclosure;
FIG. 4 is a cross-sectional side view of a gamma sensing section of the rotary steerable
tool of FIGS. 2 and 3, in accordance with an embodiment of the present disclosure;
FIG. 5 is a front cutaway view of components of the rotary steerable tool of FIGS. 3 and
4, in accordance with an embodiment of the present disclosure;
FIG. 6 is a schematic cross-sectional view of the gamma sensing section of FIG. 3 having
two shielding components used to facilitate an azimuthal gamma measurement, in accordance
with an embodiment of the present disclosure;
FIG. 7 is a schematic cross-sectional view of the gamma sensing section of FIG. 3 with
four shielding components used to facilitate azimuthal gamma measurements, in accordance with
an embodiment of the present disclosure; and
FIG. 8 is a process flow diagram illustrating a method for operating a gamma sensing
assembly of a rotary steerable tool, in accordance with an embodiment of the present disclosure.
DETAILED DESCRIPTION
Illustrative embodiments of the present disclosure are described in detail herein. In the
interest of clarity, not all features of an actual implementation are described in this specification.
It will of course be appreciated that in the development of any such actual embodiment,
numerous implementation specific decisions must be made to achieve developers' specific goals,
such as compliance with system related and business related constraints, which will vary from
one implementation to another. Moreover, it will be appreciated that such a development effort
might be complex and time consuming, but would nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of the present disclosure. Furthermore, in no
way should the following examples be read to limit, or define, the scope of the disclosure.
Certain embodiments according to the present disclosure may be directed to systems and
methods for sensing gamma radiation in a rotating section of a rotary steerable tool to take
measurements of natural gamma radiation of formations while drilling. Such rotary steerable
tools are generally used to perform directional drilling operations. Directional drilling typically
involves controlling and varying the direction of the wellbore as it is being drilled. Oftentimes
the goal of directional drilling is to reach a position within a target subterranean destination or
formation with the drill string. For instance, the drilling direction may be controlled to direct the
wellbore towards a desired target destination, to control the wellbore horizontally to maintain it
within a desired pay zone, or to correct for unwanted or undesired deviations from a desired or
predetermined path. Frequent adjustments to the direction of the wellbore are often applied
during a drilling operation, either to accommodate a planned change in direction or to
compensate for unintended or unwanted deflection of the wellbore.
Naturally emitted gamma radiation in the formations can provide insight into the makeup
and desirability of the formations being drilled through by a rotary steerable tool. Accordingly,
it is desirable to perform gamma radiation measurements in order to inform decisions on
controlling and varying the direction of the wellbore as it is being drilled. Many rotary steerable
tools do not have gamma detection capabilities at all. Other existing rotary steerable tools may
work in conjunction with formation evaluation tools (with gamma sensors) that are disposed
higher up in the drill string to take rotating gamma measurements. However, in order to make
better geo-steering decisions based on gamma measurements, it may be desirable to take these
measurements via gamma detection sensors at or near the drill bit. Measurements near the bit
may allow for the most accurate and quickest steering decisions to be made for either continuing
drilling through the desired formations or avoiding certain types of formations. However, at
present, any tools that feature gamma sensors near the drill bit have these sensors located in a
non-rotating section of the drill string.
The disclosed embodiments are directed to rotary steering tools and gamma sensor
sections of such tools that are designed address these shortcomings. The systems disclosed
herein may include scintillation detection sensors mounted in a pressure sleeve assembly coupled
to a rotating drive shaft and/or electronics insert of the rotary steerable tool. The sensors may
each be mounted in a respective pressure sleeve designed to provide an atmospheric pressure
environment. The pressure sleeves may each rotate with the drive shaft and the electronics
insert. The arrangement of the systems described below may facilitate relatively high sensitivity
measurements to be taken at a rotating portion of the rotary steerable tool.
In some embodiments, the disclosed gamma sensor section may be used to take bulk
gamma measurements at the rotating section of the rotary steerable tool, based on the amount of
sensed gamma radiation collected via the gamma detection sensors arranged around the drive
shaft of the rotary steerable tool. In other embodiments, the gamma sensor section may be
equipped with one or more shielding components (e.g., tungsten shields) that may be positioned
in the available spaces around the individual sonde-packaged gamma detection sensors. The
shielding components may prevent certain gamma detection sensors from detecting gamma
radiation emitted from certain directions within the wellbore. Therefore, such arrangements of
the gamma sensor section may be utilized to determine azimuthal (i.e., directional) gamma
measurements at the rotating section of rotary steerable tool.
Turning now to the drawings, FIG. 1 illustrates a directional drilling system, designated
generally as 10, in accordance with aspects of the present disclosure. Many of the disclosed
concepts are discussed with reference to drilling operations for the exploration and/or recovery
of subsurface hydrocarbon deposits, such as petroleum and natural gas. However, the disclosed
concepts are not so limited, and can be applied to other drilling operations. To that end, the
aspects of the present disclosure are not necessarily limited to the arrangement and components
presented in FIG. 1. For example, many of the features and aspects presented herein can be
applied in horizontal drilling applications and vertical drilling applications without departing
from the intended scope and spirit of the present disclosure.
The directional drilling system 10 exemplified in FIG. 1 includes a tower or "derrick" 12
that is buttressed by a rig floor . The rig floor 14 may support a rotary table 6 that is driven at
a desired rotational speed to provide rotational force to a drill string 18. The drill string 18,
which may include a drill pipe section 20, extends downwardly from the rotary table 16 into a
directional wellbore 22. As illustrated, the wellbore 22 may travel along a multi-dimensional
path or "trajectory." The three-dimensional direction of a bottom 24 of the wellbore 22 of FIG. 1
is represented by a pointing vector 26.
A drill bit 28 is generally attached to the distal, downhole end of the drill string 18. When
rotated, e.g., via the rotary table 16, the drill bit 28 may operate to break up and generally
disintegrate a geological formation 30. The drill string 18 may be coupled to a "drawworks"
hoisting apparatus 32, for example, via a kelly joint 34, swivel 36, and line 38 through a pulley
system (not shown). The drawworks 32 may include various components, such as a drum, one or
more motors, a reduction gear, a main brake, and an auxiliary brake. During a drilling operation,
the drawworks 32 may be operated, in some embodiments, to control the weight on the bit 28
and the rate of penetration of the drill string 18 into the wellbore 22. The operation of the
drawworks 32 is generally known and is thus not described in detail herein.
During drilling operations, a suitable drilling fluid (commonly referred to as "mud") 40
may be circulated, under pressure, out from a mud pit 42 and into the wellbore 22 through the
drill string 18 by a hydraulic "mud pump" 44. The drilling fluid 40 may include, for example,
water-based muds, oil-based muds, synthetic-based muds, as well as gaseous drilling fluids. The
drilling fluid 40 may pass from the mud pump 44 into the drill string 18 via a fluid conduit
(commonly referred to as a "mud line") 46 and the kelly joint 34. The drilling fluid 40 may be
discharged at the wellbore bottom 24 through an opening or nozzle in the drill bit 28, and
circulate in an "uphole" direction towards the surface through an annulus 48 between the drill
string 18 and the wall of the wellbore 22. As the drilling fluid 40 approaches the rotary table 16,
it may be discharged via a return line 50 into the mud pit 42. A variety of surface sensors 52,
which are appropriately deployed on the surface of the wellbore 22, may operate alone or in
conjunction with downhole sensors deployed within the wellbore 22, to provide information
about various drilling-related parameters, such as fluid flow rate, weight on bit, and hook load,
among others.
A surface control unit 54 may receive signals from surface and downhole sensors and
devices via a sensor or transducer 56, which can be placed on the fluid line 46. The surface
control unit 54 may be operable to process such signals according to programmed instructions
provided to the surface control unit 54. The surface control unit 54 may present to an operator
desired drilling parameters and other information via one or more output devices 58, such as a
display, a computer monitor, speakers, lights, etc., which may be used by the operator to control
the drilling operations. The surface control unit 54 may contain a computer, memory for storing
data, a data recorder, and other known and hereinafter developed peripherals. The surface control
unit 54 may also include models and may process data according to programmed instructions,
and respond to user commands entered through a suitable input device 60, which may be in the
nature of a keyboard, touchscreen, microphone, mouse, joystick, etc.
In some embodiments of the present disclosure, the rotatable drill bit 28 is attached at a
distal end of a bottom hole assembly (BHA) 62. In the illustrated embodiment, the BHA 62 may
be coupled between the drill bit 28 and the drill pipe section 20 of the drill string 18. The BHA
62 may include a rotary steerable tool, designated generally as 64 in FIG. 1, with various sensors
to provide information about the formation 30 and downhole drilling parameters. The sensors in
the rotary steerable tool 64 may include, but are not limited to, a device for measuring the
formation resistivity near the drill bit, a gamma ray device for measuring the formation gamma
ray intensity, devices for determining the inclination and azimuth of the drill string, and pressure
sensors for measuring drilling fluid pressure downhole. The rotary steerable tool 64 may also
include additional/alternative sensing devices for measuring shock, vibration, torque, telemetry,
etc. The above-noted devices may transmit data to a downhole transmitter 66, which in turn
transmits the data uphole to the surface control unit 54. In some embodiments, the BHA 62 may
also include a measuring while drilling (MWD) system or a logging while drilling (LWD)
system.
In some embodiments, a mud pulse telemetry technique may be used to communicate
data from downhole sensors and devices during drilling operations. In other embodiments, the
system 10 may utilize electromagnetic telemetry, acoustic telemetry, and wired drill pipe
telemetry, among others. The transducer 56 placed in the mud supply line 46 may detect mud
pulses responsive to the data transmitted by the downhole transmitter 66. The transducer 56 in
turn may generate electrical signals, for example, in response to the mud pressure variations and
transmit such signals to the surface control unit 54. In other embodiments, other telemetry
techniques such as electromagnetic and/or acoustic techniques or any other suitable techniques
known or hereinafter developed may be utilized. By way of example, hardwired drill pipe may
be used to communicate between the surface and downhole devices. In another example,
combinations of the techniques described may be used. As illustrated in FIG. 1, a surface
transmitter receiver 68 may communicate with downhole tools using, for example, any of the
transmission techniques described, such as a mud pulse telemetry technique. This may enable
two-way communication between the surface control unit 54 and the downhole tools described
below.
According to aspects of this disclosure, the rotary steerable tool 64 may include gamma
detection sensors disposed in a rotating portion of the rotary steerable tool 64. Similar
techniques may be used to provide gamma detection sensors in rotating portions of other
downhole components near the drill bit 28 (e.g., BHA 62 proximate a directional drill bit). By
placing the gamma detection sensors in a rotatable portion of the downhole system near the drill
bit, the gamma detection sensors may provide relatively accurate measurements of detected
gamma radiation within downhole formations at a position near the drill bit 28. As a result,
decisions for controlling the trajectory of the rotary steerable tool 64 may be made relatively
quickly based on the detected gamma radiation, in order to advance the wellbore 22 into desired
zones of the formation 30.
FIG. 2 is a more detailed illustration of an embodiment of the disclosed rotary steerable
tool 64. The rotary steerable tool 64 may include, among other things, a drive shaft 90, an
electronics insert assembly 92, and a gamma sensor assembly 94. The drive shaft 90 may be
coupled between the drill string 18 and the drill bit 28 of FIG. 1 when the rotary steerable tool 64
is in use. In some embodiments, the drive shaft 90 may include a drill string connection 96
formed at one end thereof for coupling the rotary steerable tool 64 to the drill string.
The electronics insert assembly 92 may include a housing 98 disposed around various
electronics 100 that may be used to process signals from downhole sensing components and/or to
control operation of the rotary steering tool 64. The electronics 100 may include one or more
processor components, memory components, storage components, and so forth designed for the
execution of various instructions relating to rotary steerable sensing and control. For example,
the electronics 00 may include a signal processor programmed to receive a signal indicative of a
detected amount of gamma radiation emitted by the formation from the gamma sensor assembly
94. In addition, the electronics 100 may include one or more processors programmed to execute
instructions for outputting a control signal to adjust a trajectory of the rotary steerable tool 64
based on a signal received from the surface and/or a signal received from the gamma sensor
assembly 94. Furthermore, the electronics 100 may include a storage component for storing a
log of the amount of gamma radiation detected via the gamma sensor assembly 94 over a period
of time. Still other electronics 100 may be present within the electronics insert assembly 92.
The housing 98 of the electronics insert assembly (or insert) 92 may function as a
pressure vessel for holding the electronics 100 at a desired pressure. Maintaining the insert 92 at
this desired pressure (e.g., atmospheric pressure) may facilitate operation of the electronics 100
disposed therein as the rotary steerable tool 64 is disposed down the wellbore. In some
embodiments, the wall of the housing 98 may be relatively thick in order to accommodate the
desired internal pressure of the insert 92. The drive shaft 90 may extend through a bore formed
in the electronics insert 92. The insert 92 may be coupled to the drive shaft 90 (e.g., via a
connection component 101), thus enabling rotation of the insert 92 in response to rotation of the
drive shaft 90 used to turn the drill bit.
The gamma sensor assembly 94 may be an entirely separate component from the insert
assembly 92 holding the electronics 100. The gamma sensor assembly 94 may be a sonde-based
assembly including one or more gamma detection sensors 102 disposed therein. The term
"sonde" may refer to an encapsulated sensor that is contained separately from other sensors. The
gamma detection sensors 02 may be shaped as elongated tubes that are aligned longitudinally
along an axis 104 of the rotary steerable tool 64. As illustrated, the gamma detection sensors 102
may be disposed circumferentially around a periphery of the drive shaft 90, which extends
through the gamma sensor assembly 94.
As described in detail below, the gamma sensor assembly 94 may also include a pressure
sleeve assembly 106 used to isolate the individual gamma detection sensors 102 at a desired
pressure. The walls of the sondes used in the pressure sleeve assembly 06 may be relatively
thinner than the housing 98 of the insert 92. In addition to the walls of the individual sondes
defined by the pressure sleeve assembly 106, the gamma sensor assembly 94 may also be
disposed in a housing 108 of the rotary steerable tool 64. This housing 108 may be used for
holding the insert electronics as well as the sensor equipment, although the housing 108 is
generally not configured for use as a pressure vessel.
The gamma sensor assembly 94 may be coupled to the drive shaft 90 and/or coupled to
the insert assembly 92 in order to be rotatable in response to rotation of the drive shaft 90. To
that end, the gamma sensor assembly 94 may include a connector component 1 0 used to fasten
the gamma sensor assembly 94 to a distal end of the insert 92 and/or to an outer periphery of the
drive shaft 90. In other embodiments, different types or arrangements of connectors may be used
to couple the gamma sensor assembly 94 to the drive shaft 90 and/or insert assembly 92. As
illustrated, the drive shaft 90 may extend through a bore formed in the gamma sensor assembly
94.
In presently disclosed embodiments, the gamma sensor assembly 94 may be rotatable in
response to rotation of the drive shaft 90, and the gamma sensor assembly 94 may be disposed
proximate the drill bit used with the rotary steerable tool 64. For example, in the illustrated
embodiment, the gamma sensor assembly 94 may be positioned between the insert assembly 92
and the end of the drive shaft 90 designed to couple with the drill bit. Other embodiments of the
rotary steerable tool 64 may include other relative arrangements of the components making up
the tool 64 with respect to one another along a length of the tool 64.
The disclosed rotary steerable tool 64 may enable more effective real-time measurements
of the gamma radiation from the formation to be taken using the gamma sensor assembly 94
located close to the drill bit. In addition, by enabling the gamma sensor assembly 94 to rotate
with the drive shaft 90, the disclosed tool 64 may be used to provide directional gamma
measurements as well as bulk gamma measurements using the relatively accurate gamma sensor
assembly 94 located at the end of the tool 64. The sonde-based design may also provide a
minimized thickness (and therefore density) between the gamma detection sensors 102. This
decreased density may increase the sensitivity of the individual gamma detection sensors 102,
since less material is blocking incoming gamma radiation. In addition, the decreased thickness
may allow more gamma detection sensors 102 to be disposed in the assembly using an efficient
spatial arrangement. This may ultimately increase the amount and quality of gamma sensor data
that can be collected through the gamma sensor assembly.
FIG. 3 illustrates a more detailed embodiment of the rotary steerable tool 64 having the
gamma sensor assembly 94 coupled to an end 130 of the insert assembly 92 with the drive shaft
90 extending therethrough. As shown, the gamma detection sensors 102 may be disposed in
individual pressure sleeves 132 that make up the pressure sleeve assembly 106.
This sonde-based design may help to increase the pressure rating of the gamma detection
sensors 102 when compared to more conventional insert-based designs. That is, instead of the
gamma detections sensors 102 all being disposed with the larger insert housing 98, the gamma
detection sensors 102 may be disposed one in each of the individual pressure sleeves 132 of the
pressure sleeve assembly 106. The insert 92 may utilize a relatively thick- walled housing 98 in
order to maintain the larger pressure vessel (insert 92) at the desired pressure. However, the
individually contained gamma detection sensors 102 may each be kept at a desired atmospheric
pressure via a pressure sleeve 132 sized with a smaller wall thickness due to the lower volume of
the pressure sleeve 132 (compared to the insert 92). Thus, the gamma detection sensors 102 may
be arranged so that less material is disposed between the sensors 102 and the gamma radiation
from the formation, enabling a more sensitive data measurement via the gamma detection
sensors 102.
Additionally, the sonde-based design may provide relatively easy access to the one or
more gamma detection sensors 102 of the rotary steerable tool 64 for services, maintenance,
repairs, etc. This is because the gamma detection sensors 102 may be disposed outside of the
larger electronics insert assembly 92. Instead of an operator having to open the pressure vessel
housing 98 of the insert 92, the operator may just remove a non-pressurized housing (e.g., 108
from FIG. 2) from the gamma sensor assembly 94 to access the individual gamma detection
sensors 102. Thus, an operator may perform evaluations, repairs, and any other desired services
on the gamma detection sensors 102 without having to disassemble the electronics insert
assembly 92.
The sonde-based arrangement of the gamma detection sensors 102 disposed in the
pressure sleeve assembly 106 may also help to simplify the assembly procedure of the rotary
steerable tool 64, since the gamma detection sensors 102 do not have to be fitted within the insert
92 holding the electronics 100. Indeed, some embodiments of the gamma sensor assembly 94
may be retro-fit onto existing rotary steerable tools having the insert 92 and the drive shaft 90
(but no or limited gamma sensor components). To that end, the gamma sensor assembly 94 may
be disposed over the drive shaft 90 of an existing rotary steerable tool proximate the electronics
insert 92 of the tool. The gamma sensor assembly 94 may then be fixed to the end 130 of the
insert 92 (e.g., using bolts to couple the connection component 110 to the end 130). Electrical
and other connections may be made up between the connection component 110 and the end 130
of the insert assembly 92.
As illustrated, the gamma sensor assembly 94 may be equipped with bolts 134 or some
other connector mechanism disposed between the connection component 110 at one end and
another connection component 136 (or end cap) at the opposite end. The bolts 134 may
generally be used to secure the pressure sleeves 132 and the end cap 136 to the electronics insert
92. The connection component/end cap 136 may also be used to couple the gamma sensor
assembly 94 to the drill bit (not shown). Other types of connectors (e.g., electrical) and fluid
lines may be disposed between the two connection components 1 0 and 136 of the gamma
sensor assembly 94 to provide desired communication between components of the insert
assembly 92 and components of the drill bit (or other parts of the rotary steerable tool).
FIG. 5 illustrates a cross-sectional view of the gamma sensor assembly 94 used to take
gamma radiation readings in the rotary steerable tool 64. As illustrated, the gamma sensor
assembly 94 may include at least two gamma detection sensors 102 disposed on opposite sides of
the drive shaft 90 relative to the axis 104. Each of the gamma detection sensors 102 may be
disposed in a corresponding pressure sleeve 132, as mentioned above. In the illustrated
embodiment, each pressure sleeve 132 of the pressure sleeve assembly 106 may be equipped
with a portion of the end cap 136 sealingly disposed at each end of the pressure sleeve 132, in
order to seal the pressure sleeve 132 at the desired pressure.
The gamma detection sensors 102 may include scintillator sensors designed to emit
energy when excited by ionizing radiation (specifically gamma radiation in present
embodiments). In some embodiments, the gamma detection sensors 102 may each include a
photomultiplier tube (PMT) coupled to a scintillator. In other embodiments, the gamma
detection sensors 02 may each include a Geiger Muller (GM) tube coupled to a scintillator for
detecting gamma radiation from the formation. It may be desirable to use PMT sensors in some
embodiments since these types of gamma detection sensors 102 may be operable at relatively
high differential pressures (e.g., downhole pressures). In addition, PMT sensors are currently
produced in sizes having a cross-sectional area (e.g., diameter of approximately 1 inch) that can
be easily fit into the pressure sleeves 132 of the disclosed pressure sleeve assembly 106 without
compromising the pressure rating of the sensor. That is, the PMT sensors may be sized for
placement in the pressure sleeves 132 without requiring a pressure sleeve with a relatively high
diameter and subsequently large wall thickness. Instead, the PM sensors may allow relatively
low wall thicknesses of the pressure sleeves 132, thereby decreasing the density of material
surrounding the gamma detection sensors 102 and ensuring a high effective sensitivity of the
gamma detection sensors 102.
In the illustrated embodiment, the gamma detection sensors 102 may include PMT
sensors. In these sensors, a photomultiplier crystal 152 may be disposed in the gamma detection
sensor 102, and this crystal 152 may emit light in response to the sensor absorbing gamma
radiation. In some embodiments, the gamma detection sensor 102 may include a photo-detector
for sensing the light emitted from the crystal 152 and outputting a signal indicative of the
detected gamma radiation. In other embodiments, the gamma detection sensor 102 may include
a fiber-optic or similar type of cable moving outward from the sensor 102. The gamma sensor
assembly 94 may include paths 154 formed through the connection component 110 leading to
each corresponding gamma detection sensor 102, in order to facilitate communication of sensor
signals from the gamma detection sensors 102 to the electronics in the insert assembly.
The gamma detection sensors 102 may be of any desirable length in the disclosed gamma
sensor assembly 94. In general, a detection sensor 102 having a longer length may operate with
a higher sensitivity than a sensor of the same diameter and a shorter length. Specifically, a
higher ratio of a length dimension 156 to a diameter dimension 158 of the crystal 152 may
generally correlate to a higher sensitivity of the sensor, up to a certain limit depending on the
sensor type. For example, the aspect ratio of crystal length to diameter that gives the greatest
sensitivity may be approximately 6 to 1 in PMTs. Accordingly, it may be desirable to construct
the gamma sensor assembly 94 with gamma detection sensors 102 that are as long as possible.
As illustrated, the gamma detection sensors 102 may be arranged in a longitudinal alignment
with the axis 104 within the pressure sleeve assembly 106.
FIG. 5 illustrates a cutaway view of the rotary steerable tool 64 taken in a direction
perpendicular to the longitudinal axis 104 of the rotary steerable tool 64. In the illustrated
embodiment, the gamma sensor assembly 94 includes a plurality of gamma detection sensors
02. It may be desirable to arrange as many gamma detection sensors 102 as possible within the
gamma sensor assembly 94, in order to increase an overall tool sensitivity to bulk gamma
radiation in the wellbore environment.
Due to limitations in space for arranging the gamma sensor assembly 94, the illustrated
embodiment may include four gamma detection sensors 102, each one being individually set into
a respective pressure sleeve 132. The pressure sleeves 132 may be arranged in the pressure
sleeve assembly 106 at 90 degree angles from each other about the axis 104. The pressure
sleeves 132 may be circumferentially positioned around a periphery of the drive shaft 90. In
other embodiments, other numbers and relative arrangements of the individual gamma detection
sensors 102 may be utilized in the disclosed gamma sensor assembly 94 of the rotary steerable
tool 64.
In the illustrated embodiment, the gamma sensor assembly 94 may also include one or
more electrical connectors 170 disposed on the connector component 1 0 to provide a desired
communication connection between various electrical lines that may be selectively coupled to
the insert assembly 92. For example, the electrical connectors 170 may include a six-pin
connector. An electrical cable may be coupled to one or more of the electrical connectors 170 to
provide control communication between, for example, the insert assembly 92 and a hydraulic
actuating unit located lower on the rotary steerable tool 64. These connectors 170, along with
the hydraulic lines 134, may facilitate a relatively easy assembly or retro-fit of the rotary
steerable tool 64 since they allow the rotatable gamma sensor assembly 94 to be added between
any two components of the rotary steerable tool 64 (e.g., near bit) while still providing the
desired connections between these components.
As discussed above, it may be desirable to provide relatively sensitive gamma
measurements using the gamma sensor assembly 94 in the rotary steerable tool 64. This may be
accomplished in a number of ways using the disclosed sonde-based gamma sensor design.
Specifically, the gamma measurement sensitivity of the overall rotary steerable tool 64 may
increase as the number of gamma detection sensors 102 increase within the assembly. In
addition, the measurement sensitivity may increase as a result of a decrease in the amount of
material (i.e., sleeve or housing thickness) between the gamma detection sensors 102 and the
formation. The sonde-based detection assembly makes use of noticeably thinner housings of the
pressure sleeves 132 and possibly another housing disposed over the pressure sleeves 132, as
opposite to the relatively thick-walled housing 98 of the insert assembly 92. The lower pressure
sleeve thickness may be designed under a proper pressure rating that allows better measurements
sensitivities for bulk gamma measurements.
The reduced thickness of the pressure sleeves 132 may reduce the space constraints
within the gamma sensor assembly 94. This reduction of space constraints may facilitate a usage
of more sensitive PMTs (as shown), instead of GM tubes. Furthermore, the reduced space taken
up by the pressure sleeve assembly 106 may enable more gamma detection sensors 102 to be
used overall, thereby further increasing measurement sensitivity.
Increased sensitivity of the gamma sensor assembly 94 may result in increased accuracy
in identifying subsurface formations. This may increase the reliability of the rotary steerable tool
64 as well as reduce the time required to evaluate the formations while drilling. The reduced
evaluation time may enable an operator or controller to make quicker steering decisions for
adjusting and improving wellbore placement. In addition, as discussed above, the gamma sensor
assembly 94 may be disposed near the drill bit of the rotary steerable tool 64, thus enabling the
system to accurately identify the formations at a position near the bit during drilling operations.
Further, the gamma sensor assembly 94 is rotatable with the drive shaft 90 and, as a result, may
provide desirable types of measurements considering gamma radiation detected from all
directions within the formation.
In some embodiments, the individual gamma detection sensors 102 may not be able to
determine the direction from which the gamma ray is emitted. Rather, the gamma detection
sensor 102 is able to detect the collision of the gamma ray with the scintillator crystal.
Therefore, a direction of the gamma ray source may be determined, statistically, when there is a
difference in the probability of the gamma ray reaching the scintillator crystal based on the
gamma ray's direction of travel. This probability difference may be achieved by shielding or
attenuating gamma rays from reaching the gamma detection sensors 102 in certain directions.
FIG. 6 shows an embodiment of the gamma sensor assembly 94 with one of the gamma
detection sensors 102 being shielded on two sides via shielding components 180. The shielding
components 180 may be plates or other inserts formed from tungsten, or some other material that
attenuates gamma rays. The shielding components 180 may be used to narrow the range of
azimuthal directions in which gamma rays 182 may be detected via the gamma detection sensor
102.
As shown in FIG. 6, the shielded gamma detection sensor 102 is able to more easily
detect gamma rays 82 coming from a certain direction or range of rotational angles around the
gamma detection sensor 102. Gamma rays that may be emitted from an opposite side or range of
angles 184 relative to the gamma detection sensor 102 may be generally blocked from reaching
the sensor by the shielding components 180 as well as by the drive shaft 90. Accordingly, the
shielding components 180 may facilitate an azimuthal (or directional) measurement of gamma
radiation via the shielded gamma detection sensor 102. As the rotary steering tool rotates the
gamma sensor assembly 94 about the axis, the directional gamma measurements may be
evaluated along with a sensed depth and/or orientation of the rotating portions of the tool within
the wellbore.
FIG. 7 illustrates another embodiment of the gamma sensor assembly 94 using multiple
shielding components 180 disposed between adjacent gamma detection sensors 102. It should be
noted that the sonde-based arrangement of the gamma detection sensors 102 within the gamma
sensor assembly 94 may facilitate the placement of such shielding inserts 180 without adding
substantial bulk to the packaged sensor assembly 94. Indeed, as shown, all the shielding
components 180 may generally fit within the housing 108 of the rotary steerable tool, in
positions between the gamma detection sensors 102. Any desirable number or arrangement of
these shielding components 180 may be used to provide the desired directional gamma
measurements.
In some embodiments, the shielding components 180 may be removably disposed within
the gamma sensor assembly 94 while the rotary steerable tool is being configured at a shop
location or at the surface of a wellsite. In other embodiments, the shielding components 180
may be designed to be selectively actuated into position while the rotary steerable tool is
positioned downhole. For example, the shielding components 80 may be initially positioned
within another component of the rotary steerable tool adjacent the gamma sensor assembly 94,
and these shielding components 180 may be hydraulically actuated from this position to the
position between the gamma detection sensors 102. This actuation of the shielding components
180 into positions between the sensors 102 may be controlled based on a desired type of gamma
measurement to be obtained. That is, when bulk gamma measurements are requested, a control
component may actuate the shielding components 180 into a position away from the gamma
detection sensors 102. Likewise, when directional gamma measurements are requested, the
control component may actuate one or more of the shielding components 180 into position
between the gamma detection sensors 102 to provide the azimuthal shielding.
The disclosed rotary steerable tool 64 may obtain gamma radiation sensor data and
evaluate the formations using this data according to a method 190, as illustrated in FIG. 8. It
should be noted that certain parts of the method 190 may be implemented as a computer or
software program (e.g., code or instructions) that may be executed by an electronic processor in
the insert assembly 92 to execute one or more of the steps of the method 190. Additionally, the
program (e.g., code or instructions) may be stored in any suitable article of manufacture that
includes at least one tangible non-transitory, computer-readable medium that at least collectively
stores these instructions or routines, such as a memory component or a storage component
disposed in the electronics insert assembly 92.
The method 190 may include maintaining (block 192) the gamma detection sensors in
fixed positions relative to each other and coupled between an end of an electronics insert
assembly and the drill bit. The method 190 also may include rotating (block 194) the electronics
insert and the gamma detection sensors in response to the drive shaft rotation. In addition, the
method 190 may include detecting gamma radiation (block 196) emitted from the subterranean
formation via the sensors and providing a signal (block 198) indicative of the detected gamma
radiation from the sensors to the electronics in the insert assembly.
Upon receiving the signal, the electronics may determine a bulk gamma measurement
(block 200) based on the signal taken in all directions relative to the rotary steerable tool over a
period of time. This type of data acquisition may be relatively easy to implement when the
gamma detection sensors (e.g., PMTs) have a lower sensitivity, since the quantity of counts
provided in the signal while the tool is rotating may be too low to provide immediate feedback.
To determine the bulk gamma measurement, the electronics may receive signals from each of the
sensors over a relatively long sampling period and average the measurements in all directions.
This may help to resolve any signal fluctuations due to slow count rates from the sensors.
Although the bulk gamma measurement is an average measurement from all directions, drillers
can look at trends in radiation level changes in order to decide where to stop the tool to take
more specific directional measurements as desired. The bulk gamma measurement may yield a
relatively high combined count rate (or sensitivity) of the overall sensor measurements.
In other embodiments, upon receiving the signal, the electronics may determine a
directional gamma measurement (block 202) while the rotary steerable tool is rotating.
Relatively accurate directional gamma measurements may be taken using gamma detection
sensors with a relatively high sensitivity (e.g., count rate). To determine the gamma
measurements in a specific direction, the rotary steerable tool may include one or more sensors
for determining a directional measurement while the tool rotates. This directional measurement
may be tracked and recorded as an angle of the sensor assembly relative to a reference point on a
housing (e.g., approximately geo-stationary outer housing) of the rotary steerable tool. The
directional gamma measurements may be taken for different angular regions that are arranged
around the axis of the tool. These angular regions may be arranged in many fashions, such as
using multiple equally sized regions around the axis, or using an number of irregularly sized
larger and smaller regions. The electronics may account for a relative rotation between the insert
assembly and the reference point.
After determining either the bulk gamma measurement (200) or the directional gamma
measurement (202), the electronics assembly may store (block 204) the measurements onboard
the tool. In some embodiments, the electronics assembly may output a control signal (block 206)
for controlling a deflection or other operating parameter of the rotary steerable tool to change
trajectories of the tool through the formation (e.g., in response to a directional gamma
measurement). In other embodiments, the electronics assembly may generate and output a signal
indicative of the gamma measurement (bulk or directional) to a telemetry module for
communicating the signal to a surface control component. From here, the signal may provide a
log to operators at the surface, and in some cases the signal may be used to control a speed of
rotation of the drill string and rotary steerable tool.
Embodiments disclosed herein include:
A. A rotary steerable tool for use in drilling a wellbore through a subterranean
formation, the rotary steerable tool including a drive shaft, a pressure sleeve assembly, and a
gamma detection sensor. The drive shaft is extending through the rotary steerable tool for
turning a drill bit. The pressure sleeve assembly is disposed proximate the drill bit and coupled
to the drive shaft and rotatable in response to rotation of the drive shaft. The gamma detection
sensor is arranged within the pressure sleeve assembly for sensing gamma radiation emitted from
the subterranean formation.
B. A rotatable gamma sensing section for use in a rotary steerable tool, wherein the
rotatable gamma sensing section includes a plurality of gamma detection sensors, a connector
component, and a pressure sleeve assembly. The plurality of gamma detection sensors are used
for detecting gamma radiation emitted from a subterranean formation. The connector component
is coupled to the plurality of gamma detection sensors for holding the plurality of gamma
detection sensors in a fixed position relative to each other and for coupling the rotatable gamma
sensing section to a rotatable component of the rotary steerable tool. The connector component
includes a bore formed therethrough to accommodate a drive shaft extending through the rotary
steerable tool. The pressure sleeve assembly includes a plurality of pressure sleeves coupled to
each other via the connector component, wherein each of the plurality of gamma detection
sensors are disposed in a corresponding one of the plurality of pressure sleeves. The plurality of
gamma detection sensors, the pressure sleeve assembly, and the connector component are
rotatable about an axis in response to rotation of the drive shaft.
C. A method for operating a rotary steerable tool includes maintaining a plurality of
sensors in fixed positions relative to each other and coupled to a rotatable component of the
rotary steerable tool. The method also includes rotating the electronics insert and the plurality of
sensors in response to a drive shaft turning a drill bit of the rotary steerable tool. In addition, the
method includes detecting gamma radiation emitted from a subterranean formation via the
plurality of sensors. Further, the method includes providing a signal indicative of the detected
gamma radiation from the plurality of sensors to electronics disposed in an electronics insert of
the rotary steerable tool.
Each of the embodiments A, B, and C may have one or more of the following additional
elements in combination: Element 1: wherein the pressure sleeve includes a sonde. Element 2:
wherein the gamma detection sensor includes a photomultiplier tube, a Geiger Muller (GM) tube,
or another gamma detection sensor that can fit in the sonde. Element 3 : wherein the pressure
sleeve assembly includes a pressure sleeve for holding the gamma detection sensor at
atmospheric pressure. Element 4 : further including a plurality of gamma detection sensors
arranged within the pressure sleeve assembly. Element 5: wherein the pressure sleeve assembly
includes a plurality of pressure sleeves arranged circumferentially around the drive shaft,
wherein each of the plurality of pressure sleeves holds a corresponding one of the plurality of
gamma detection sensors, and wherein the pressure sleeves are arranged in a longitudinal
orientation relative to the drive shaft. Element 6 : further including a connector component
disposed at a distal end of the pressure sleeve assembly for holding each of the plurality of
gamma detection sensors in a fixed position relative to each other and enabling rotation of the
sleeve assembly in response to a rotation of the drive shaft. Element 7 : further including an
insert assembly comprising a first housing disposed around electronics, wherein the insert
assembly is rotatable in response to rotation of the drive shaft, wherein the sleeve assembly is
coupled between the insert assembly and the drill bit. Element 8: further including a second
housing disposed around the sleeve assembly, wherein a thickness of the first housing is greater
than a thickness of the second housing. Element 9 : further including an electrical connector
coupled between the sleeve assembly and the insert assembly to provide electrical
communication between a hydraulic actuating unit and the electronics of the insert assembly.
Element 10: further including a removable shielding component disposed proximate the gamma
detection sensor to narrow an azimuthal detection range of the gamma detection sensor.
Element 11: wherein a wall of each of the plurality of pressure sleeves has a thickness
less than a housing thickness of the rotatable component. Element 12: wherein the plurality of
gamma detection sensors are arranged circumferentially about the axis. Element 13: further
including one or more shielding components disposed between the plurality of gamma detection
sensors to narrow an azimuthal detection range of at least one of the plurality of gamma
detection sensors. Element 14: further including one or more electrical connectors formed in the
connector component. Element 15: further including one or more fluid lines extending from the
connector component.
Element 16: further including determining a bulk gamma measurement based on the
signal indicative of the gamma radiation emitted from the subterranean formation in all
directions relative to the rotary steerable tool, detected via the plurality of sensors over a period
of time. Element 17: further including actuating one or more shielding components into
positions between the plurality of sensors, and determining a directional gamma measurement
based on the signal indicative of the gamma radiation emitted from the subterranean formation in
a given direction relative to the rotary steerable tool.
Although the present disclosure and its advantages have been described in detail, it
should be understood that various changes, substitutions and alterations can be made herein
without departing from the spirit and scope of the disclosure as defined by the claims.

WHAT IS CLAIMED IS:
1. A rotary steerable tool for use in drilling a wellbore through a subterranean formation,
comprising:
a drive shaft extending through the rotary steerable tool for turning a drill bit;
a pressure sleeve assembly disposed proximate the drill bit and coupled to the drive shaft
and rotatable in response to rotation of the drive shaft; and
a gamma detection sensor arranged within the pressure sleeve assembly for sensing
gamma radiation emitted from the subterranean formation.
2. The rotary steerable tool of claim 1, wherein the pressure sleeve comprises a sonde.
3. The rotary steerable tool of claim 2, wherein the gamma detection sensor comprises a
photomultiplier tube, a Geiger Mu er (GM) tube, or another gamma detection sensor that can fit
in the sonde.
4. The rotary steerable tool of claim 1, wherein the pressure sleeve assembly comprises a
pressure sleeve for holding the gamma detection sensor at atmospheric pressure.
5. The rotary steerable tool of claim 1, further comprising a plurality of gamma detection
sensors arranged within the pressure sleeve assembly.
6. The rotary steerable tool of claim 5, wherein the pressure sleeve assembly comprises a
plurality of pressure sleeves arranged circumferentially around the drive shaft, wherein each of
the plurality of pressure sleeves holds a corresponding one of the plurality of gamma detection
sensors, and wherein the pressure sleeves are arranged in a longitudinal orientation relative to the
drive shaft.
7. The rotary steerable tool of claim 5, further comprising a connector component disposed
at a distal end of the pressure sleeve assembly for holding each of the plurality of gamma
detection sensors in a fixed position relative to each other and enabling rotation of the sleeve
assembly in response to a rotation of the drive shaft.
8. The rotary steerable tool of claim 1, further comprising an insert assembly comprising a
first housing disposed around electronics, wherein the insert assembly is rotatable in response to
rotation of the drive shaft, wherein the sleeve assembly is coupled between the insert assembly
and the drill bit.
9. The rotary steerable tool of claim 8, further comprising a second housing disposed
around the sleeve assembly, wherein a thickness of the first housing is greater than a thickness of
the second housing.
10. The rotary steerable tool of claim 8, further comprising an electrical connector coupled
between the sleeve assembly and the insert assembly to provide electrical communication
between a hydraulic actuating unit and the electronics of the insert assembly.
11. The rotary steerable tool of claim 1, further comprising a removable shielding component
disposed proximate the gamma detection sensor to narrow an azimuthal detection range of the
gamma detection sensor.
12. A rotatable gamma sensing section for use in a rotary steerable tool, wherein the rotatable
gamma sensing section comprises:
a plurality of gamma detection sensors for detecting gamma radiation emitted from a
subterranean formation;
a connector component coupled to the plurality of gamma detection sensors for holding
the plurality of gamma detection sensors in a fixed position relative to each other and for
coupling the rotatable gamma sensing section to a rotatable component of the rotary steerable
tool, wherein the connector component comprises a bore formed therethrough to accommodate a
drive shaft extending through the rotary steerable tool; and
a pressure sleeve assembly comprising a plurality of pressure sleeves coupled to each
other via the connector component, wherein each of the plurality of gamma detection sensors are
disposed in a corresponding one of the plurality of pressure sleeves;
wherein the plurality of gamma detection sensors, the pressure sleeve assembly, and the
connector component are rotatable about an axis in response to rotation of the drive shaft.
13. The rotatable gamma sensing section of claim 1 , wherein a wall of each of the plurality
of pressure sleeves has a thickness less than a housing thickness of the rotatable component.
14. The rotatable gamma sensing section of claim 12, wherein the plurality of gamma
detection sensors are arranged circumferentially about the axis.
15. The rotatable gamma sensing section of claim 12, further comprising one or more
shielding components disposed between the plurality of gamma detection sensors to narrow an
azimuthal detection range of at least one of the plurality of gamma detection sensors.
16. The rotatable gamma sensing section of claim 12, further comprising one or more
electrical connectors formed in the connector component.
17. The rotatable gamma sensing section of claim 12, further comprising one or more fluid
lines extending from the connector component.
18. A method for operating a rotary steerable tool, comprising:
maintaining a plurality of sensors in fixed positions relative to each other and coupled to
a rotatable component of the rotary steerable tool;
rotating the electronics insert and the plurality of sensors in response to a drive shaft
turning a drill bit of the rotary steerable tool;
detecting gamma radiation emitted from a subterranean formation via the plurality of
sensors; and
providing a signal indicative of the detected gamma radiation from the plurality of
sensors to electronics disposed in an electronics insert of the rotary steerable tool.
19. The method of claim 18, further comprising determining a bulk gamma measurement
based on the signal indicative of the gamma radiation emitted from the subterranean formation in
all directions relative to the rotary steerable tool, detected via the plurality of sensors over a
period of time.
20. The method of claim 18, further comprising actuating one or more shielding components
into positions between the plurality of sensors, and determining a directional gamma
measurement based on the signal indicative of the gamma radiation emitted from the
subterranean formation in a given direction relative to the rotary steerable tool.