U.S. patent application number 12/127881 was filed with the patent office on 2009-12-03 for downhole sensor system.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Lee F. Dolman, Richard Harmer.
Application Number | 20090294174 12/127881 |
Document ID | / |
Family ID | 41228595 |
Filed Date | 2009-12-03 |
United States Patent
Application |
20090294174 |
Kind Code |
A1 |
Harmer; Richard ; et
al. |
December 3, 2009 |
DOWNHOLE SENSOR SYSTEM
Abstract
A method includes sensing a parameter in a well using a sensor
disposed on a drillstring, determining a position of the sensor in
a wellbore based on a position of the sensor in the drillstring and
a position of the drillstring in the wellbore.
Inventors: |
Harmer; Richard; (Cheam,
GB) ; Dolman; Lee F.; (NAUCALPAN DE JUAREZ,
MX) |
Correspondence
Address: |
SCHLUMBERGER OILFIELD SERVICES
200 GILLINGHAM LANE, MD 200-9
SUGAR LAND
TX
77478
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
41228595 |
Appl. No.: |
12/127881 |
Filed: |
May 28, 2008 |
Current U.S.
Class: |
175/45 ; 175/40;
175/48 |
Current CPC
Class: |
E21B 47/06 20130101;
E21B 47/09 20130101; E21B 47/12 20130101 |
Class at
Publication: |
175/45 ; 175/48;
175/40 |
International
Class: |
E21B 47/024 20060101
E21B047/024 |
Claims
1. A system for use in a well, comprising: a drillstring; a
plurality of sensors deployed along the drillstring to provide data
from multiple locations along the drillstring during a drilling
operation; and a surface processor operatively coupled with the
plurality of sensors and adapted to determine the position of the
plurality of sensors based on the position of each sensor in the
drillstring and a position of the drillstring in the well.
2. The system as recited in claim 1, wherein the plurality of
sensors comprises at least one pressure sensor.
3. The system as recited in claim 1, wherein the plurality of
sensors comprises at least one temperature sensor.
4. The system as recited in claim 1, wherein the plurality of
sensors comprises sensors located external to the drillstring.
5. The system as recited in claim 1, wherein the plurality of
sensors comprises sensors located internal to the drillstring.
6. The system as recited in claim 1, wherein the plurality of
sensors output data to the control system in real-time.
7. The system as recited in claim 1, wherein the plurality of
sensors comprises at least one sensor disposed in a drill bit of
the drillstring.
8. The system as recited in claim 1, further comprising a wired
drill pipe connecting the plurality of sensors with the control
system.
9. The system as recited in claim 1, wherein the drillstring
comprises wired drill pipe.
10. The system in claim 1, further comprising: a clock operatively
coupled to the plurality of sensors and configured to provide a
time stamp to measured data.
11. A method, comprising: sensing a parameter in a well using a
sensor disposed on a drillstring; determining a position of the
sensor in a wellbore based on a position of the sensor in the
drillstring and a position of the drillstring in the wellbore.
12. The method as recited in claim 11, further comprising
transmitting data related to the sensed parameter to a surface
processor.
13. The method as recited in claim 12, wherein transmitting data
related to the sensed parameter to the surface processor is done
substantially in real-time.
14. The method as recited in claim 11, further comprising applying
a time stamp to data related to the sensed parameter, and wherein
determining the position of the sensor is based on the position of
the drillstring in the wellbore at the time the data was
collected.
15. The method as recited in claim 14, wherein applying the time
stamp is performed downhole, using a clock operatively coupled to
the sensor.
16. The method as recited in claim 14, wherein applying the time
stamp is performed by the surface processor, using a clock
operatively coupled to the surface processor.
17. The method as recited in claim 11, further comprising
determining a well condition selected from a cuttings bed, a swab
or surge pressure, and a thief zone.
18. A method, comprising: step for measuring a parameter with a
sensor deploying a drillstring; step for outputting data from the
sensor; and step for determining a sensor position and a value of
the sensed parameter.
19. The method as recited in claim 18, further comprising a step
for determining a well condition.
Description
BACKGROUND
[0001] Drilling operations are used to drill wellbores that provide
access to underground reservoirs, such as hydrocarbon bearing
reservoirs. Typically, the drilling process is monitored by sensors
at the surface, which may monitor such things as hookload, torque,
RPM, among others. The drilling process is also typically monitored
by sensors in the bottom hole assembly. Such sensors may monitor
temperature, pressure, direction and inclination, loads such as
torque on bit and weight on bit, among others. In one example, data
obtained from the downhole pressure sensor can be used to determine
equivalent drilling fluid density at that point in the wellbore or
drillstring.
[0002] Data from the downhole pressure sensor may be transmitted to
the surface using conventional pressure-pulse telemetry, or similar
telemetry, that has relatively low update rates. Furthermore, the
pressure sensor only measures the average equivalent density of the
drilling fluid from the sensor true vertical depth to the surface
and is not able to identify density and pressure loss differences
along the wellbore. As a result, the downhole pressure measurement
provides very little detail as to specific events occurring in the
wellbore either within the drillstring or in the surrounding
annulus. In some applications, a temperature sensor also has been
utilized in the bottom hole assembly for monitoring tool
performance. However, the temperature sensor is not able to provide
data related to the monitoring of spatial variations versus
depth.
SUMMARY
[0003] In one aspect, the invention relates to a system for use in
a well that includes a drillstring, a plurality of sensors deployed
along the drillstring to provide data from multiple locations along
the drillstring during a drilling operation, and a control system
operatively coupled with the plurality of sensors and adapted to
determine the position of the plurality of sensors based on the
position of each sensor in the drillstring and a position of the
drillstring in the well.
[0004] In another aspect, the invention relates to a method that
includes sensing a parameter in a well using a sensor disposed on a
drillstring, determining a position of the sensor in a wellbore
based on a position of the sensor in the drillstring and a position
of the drillstring in the wellbore.
[0005] In another aspect, the invention relates to a method that
inclues a step for measuring a parameter with a sensor deploying a
drillstring, a step for outputting data from the sensor, and astep
for determining a sensor position and a value of the sensed
parameter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] Certain examples of the invention will hereafter be
described with reference to the accompanying drawings, wherein like
reference numerals denote like elements, and:
[0007] FIG. 1 is a front elevation view of an example well system
having a plurality of sensors deployed in a wellbore;
[0008] FIG. 2 is an alternate example of a well system having a
plurality of sensors deployed in a wellbore;
[0009] FIG. 3 is an alternate example of a well system having a
plurality of sensors deployed in a wellbore;
[0010] FIG. 4 is a schematic representation of an example processor
system or control system used in the well system;
[0011] FIG. 5 is an example graphical representation of a parameter
profile based on data obtained from a plurality of sensor
locations;
[0012] FIG. 6 is an example graphical representation of data
related to sensed parameters and output to an operator;
[0013] FIG. 7 is a flowchart illustrating an example operational
method; and
[0014] FIG. 8 is a flowchart illustrating an example process of
data evaluation.
[0015] FIG. 9 is a flowchart illustrating an example process for
determining the time and position of a measurement.
[0016] FIG. 10 is a schematic illustrating an example of a system
for determining the time and location of a measurement.
[0017] FIG. 11 is a schematic illustrating an example of a system
for determining the time and location of a measurement.
DETAILED DESCRIPTION
[0018] In the following description, numerous details are set forth
to provide an understanding of the various disclosed examples.
However, it will be understood by those of ordinary skill in the
art that numerous variations or modifications from the described
examples may be possible.
[0019] The following examples relate to a methodology and a system
for using multiple downhole sensors that are connected to the
surface and/or to each other via a data transmission medium
incorporated into or extending along oilfield tubulars, such as a
drill string. For example, multiple sensors, e.g. pressure and/or
temperature sensors, may be deployed along the downhole well string
and connected to the surface by wire, optical fiber, or other
suitable media for transferring data. Such systems are often called
"wired drill pipe." In addition, signals may be transmitted using
other telemetry methods, such a mud-pulse telemetry,
electromagnetic telemetry, and other methods known in the art. In
another example, telemetry may be accomplished using two or more
telemetry methods in combination. A system may include mud-pulse
telemetry from the BHA to an intermediate point in the drill
string, where pressure sensors demodulate the signal and
re-transmit the uplink data over a wired drill pipe to the
surface.
[0020] In drilling applications, the downhole sensors may be
distributed along the drillstring internal to and/or external of
the drillstring, and used to sense one or more desired parameters.
By way of example, the multiple sensors and an associated data
processor system have the ability to perform real-time, near
real-time, or retrospective assessments of static and/or dynamic
pressure and/or temperature distributions within the wellbore
annulus and/or drillstring.
[0021] Accurate downhole information, e.g. downhole pressure
information, obtained from multiple sensors positioned at different
points along the drillstring facilitates an understanding of the
nature and location of potential problems downhole. For example,
use of multiple sensors positioned at different points within a
drillstring enable an operator to gain an understanding of the
nature and location of downhole pressure losses and
pressure/temperature changes that improve key operational
decision-making and operational performance. For example, the
multipoint data can facilitate drilling optimization, casing seat
selection, rheological modeling, well control, wellbore stability
management, and other improvements.
[0022] As a drilling operation takes place, for example, the
sensors can be either static or moving in an up or down direction
inside the wellbore, as well as rotating with the drill string. The
location of each sensor can be calculated via either a surface or a
downhole system that monitors the drillstring movement. In one
example, drillstring movement may be monitored through periodic
wellbore surveys and/or survey calculations. Each sensor maybe
provided with a unique identifier that identifies its position in
the drillstring and is added to the data obtained by the sensor and
transmitted to a suitable control/processor system. Accordingly,
the actual sensor position in the wellbore, at the time specific
data is recorded by the sensor, is calculated by the
control/processor system which references the real-time wellbore
survey calculation. Alternatively, the positional information can
be sent to each sensor and included in the data output and sent
back uphole to the control/processor system located, for example,
at the surface.
[0023] In one example, a processor at the surface may identify the
position of a particular measurement by using the unique identifier
for the sensor that made the measurement, coupled with the known
location of the sensor on the drill string and the know position of
the drill string. For measurements that are transmitted to the
surface in real-time or near real-time, the position of the drill
string may be the current position of the drill string. In another
example, the measurement may be time-stamped by the sensor based on
an internal clock. The processor may then determine the position of
the measurement by the known position of the sensor in the drill
string and the known position of the drill string at the time the
measurement was taken.
[0024] In another example, a sensor may collect and store data for
later retrieval. The data may be analyzed based on the known
position of the sensor in the drill string and the position of the
drill string at the time the measurement was made. In one example,
the data may be stored with a time stamp to indicate the time when
the measurement was taken. In some examples, a clock coupled to a
sensor for time-stamping may be set before the sensor is deployed
into the borehole. In other examples, the clock may be later
compared to a reference clock to determine the time of each
measurement based on a time stamp. In another example, a clock may
be synchronized in situ, during the drilling process.
[0025] In other examples, the knowledge of the position of the
drillstring in the wellbore is obtained from a database that
includes the trajectory of the wellbore and the depth of the BHA in
the wellbore. In some examples, the database also includes a time
stamp so that the position of the drillstring in the wellbore may
be correlated to a specific time and a location may be obtained for
time-stamped data from a sensor in the drillstring.
[0026] In another example, the position or depth of the BHA may be
determined using what is called "driller's depth," which is
determined at the surface. In other examples, the depth of the BHA
may be determined using the techniques such as those described in
U.S. patent application Ser. No. 10/573,236, incorporated herein by
reference, for accounting for pipe stretch in the depth
calculation.
[0027] The profile or position of the wellbore may be determined
using numerous techniques. For example, static surveys for
determining the direction and inclination of the wellbore at or
near the drill bit are common practice in the industry. Further,
continuous measurements of the direction and inclination, while
drilling, may improve the estimation of the position of the
wellbore. In still other examples, the position of a wellbore may
be measured using a gyro survey on a wireline tool or on a sub
deployed in the wellbore to measure the trajectory of the
wellbore.
[0028] The mapping of parameter distributions, e.g. pressure and
temperature distributions, to determine profiles along the wellbore
may yield many benefits in a variety of applications. For example,
the present system and methodology enables the monitoring of
cuttings transport up the annulus while highlighting areas of high
solids loading and identifying the possible buildup of cuttings
beds or potential "pack-offs" that have a negative impact on the
drilling operation. The influence of the cuttings load on the
bottom hole pressure also can be calculated. Monitoring of the
transport of cuttings also can be used for parameter optimization
in a manner that positively influences hole cleaning and maximizes
penetration rate. The system may also provide accurate data for
bottom hole pressure determination that is particularly useful in
high-pressure, high temperature environments where temperature
effects on mud density are difficult to verify with available
modeling techniques. The multiple sensor points also allow
management of "swab and surge" while tripping to assess optimum
safe tripping speed given the wellbore stability factors. One or
more pressure sensors also can be positioned on or near the drill
bit to further facilitate this analysis.
[0029] Example systems and methodologies may be used to identify
"thief" zones responsible for lost circulation where loss of flow
into the formation reduces the parasitic pressure loss evident
above the loss zone as the flow rate is reduced past the sensors.
Additionally, hole-gauge changes can be inferred by a reduction or
increase in parasitic pressure loss caused by reduced or increased
annular velocity while maintaining the same flow rate. Pills,
slugs, and sweeps can be monitored both in the drillstring and the
annulus. Also, the progress of cement during cementing operations,
as well as the displacement of wellbore fluids of different
densities, can be monitored. Similarly, the evaluation of uniform
fluid density in the wellbore prior to pressure tests or fracturing
operations can be monitored along with the actual pressure tests
and fracturing operations.
[0030] In some applications, the system and methodology provide the
ability to identify the location of and to measure the pressure
below bridges in the wellbore during drilling, workover, and/or
completion operations (including locations below pack-offs, below
completion packers, below liner hangars and test packers, as well
as enabling measurements during casing or tubing integrity tests).
The multipoint sensing also enables assessment of the effects of
pressure, and potentially temperature, on fluid density in
high-pressure, high-temperature wells. The operation of downhole
tools also can be analyzed in detail by measuring pressure
differentials across their hydraulically activated components.
System sensors may also be used to receive pressure pulses from
other downhole tools and to transmit those signals uphole at an
increased telemetry rate. This may also enable pressure pulse
telemetry at higher data rates over shorter distances rather than
sending the pulses over substantial distances for decoding at a
surface location.
[0031] In other applications, specific and focused analysis of
pressure and temperature distributions across the face of a
drilling bit and/or mill can be transmitted to the surface in
real-time or near real-time to be used for drilling operation
optimization or post operational analysis. The performance of
downhole tools requiring pressure drops to function also can be
monitored and optimized. The sensor system can further provide
information useful during component connections. Data obtained from
the sensors can assist with well control operations by providing
wellbore pressures and temperatures in real time that aid in "kill
operations" and/or in identifying the position and type of influx
into a wellbore.
[0032] Referring generally to FIG. 1, an example of a well system
20 for carrying out the sensing and monitoring functions, such as
those described above, is illustrated. The well system 20 can be
used for the benefit of a variety of well related procedures. In
the example illustrated, well system 20 comprises a well string 22
that extends down into a wellbore 24. The wellbore 24 may be
drilled into a reservoir or formation 26 holding desirable fluids,
such as hydrocarbon based fluids.
[0033] In the example illustrated, well string 22 comprises a
tubing 28 and a bottom hole assembly 30 deployed at a lower end of
tubing 28. In many applications, well string 22 is a drillstring,
and bottom hole assembly 30 is designed for drilling operations.
For example, bottom hole assembly 30 may include or be coupled to a
drill bit 32 used to form wellbore 24. During a drilling operation,
drilling mud is pumped down through an interior 34 of drillstring
22, as represented by arrow 36. The drilling mud is pumped down
through the interior 34 and out through drill bit 32 before being
routed upwardly along a surrounding annulus 38, as represented by
arrows 40.
[0034] The well system 20 further comprises multiple sensors 42
deployed along the well string, e.g. drillstring, 22. The sensors
42 are designed to detect a desired parameter and to output data to
a processor system 44 that may be a control system or other surface
processor positioned at a surface location 46. Data from the
sensors 42 is sent uphole via an appropriate communication line or
communication lines 48. By way of example, communication lines 48
may comprise wires, optical fibers, wireless communication systems,
and other suitable communication lines. The communication lines 48
also can be used to connect the sensors 42 to each other, thereby
enabling the communication of data between sensors as well as
between the processor system 44 and the sensors 42.
[0035] The communication lines 48 enable the communication of
measurement data from multiple points along the well string 22 and
the transmission of that data to processor system 44 in real-time.
This, in turn, enables ongoing monitoring and evaluation of the
operation, e.g. drilling operation, as the operation progresses.
The sensors 42 may be used to provide multipoint data while the
sensors are static or while the sensors are moving inside a
wellbore 24. Processor system 44 is used to calculate or otherwise
determine the position of each sensor 42 at the time the given
parameter is measured by each sensor. By way of example, processor
system 44 can be used to monitor movement of the drillstring 22
relative to a wellbore survey calculation. Each sensor is provided
with a unique identifier that is added to the parameter data being
detected and recorded by the sensor 42. This enables determination
of the actual position of each sensor 42 in the wellbore at the
time data is recorded. As previously discussed, the position can be
tracked by the processor system 44 which tracks and references a
real-time wellbore survey calculation or, alternatively, the
positional information of each sensor can be sent downhole to the
sensor and included with the parameter data output to processor
system 44.
[0036] In some applications where real-time data analysis is not
required, the measurement data detected by each sensor 42 can be
time-stamped and stored downhole either at each individual sensor
or at a downhole storage device. The stored data can then be
uploaded to processor system 44 as "batches" of data when needed.
The stored data approach facilitates management of bandwidth
utilization and allows later analysis or post operation analysis of
multipoint sensor data. Processor system 44 simply cross-references
the time-stamped data with a time-based depth record to calculate
each sensor's position in the wellbore at the time the desired
parameter data was recorded.
[0037] The sensors 42 are spaced along well string 22 according to
the desired parameter profile that is to be acquired along a
desired region of wellbore 24. For example, if sensors 42 comprise
pressure sensors, the pressure sensors 42 are selected and located
to provide a sufficient quantity of sensors at multiple points and
with sufficient accuracy to enable meaningful data interpretation.
The frequency or spacing of the individual sensors 42 affects the
resolution of the parameter profile derived from the data collected
along the wellbore. Sensors 42 can comprise pressure sensors and/or
temperature sensors to create desired pressure/temperature profiles
taken along the desired region of wellbore 24, or the entire
wellbore 24, either inside well string 22 or along the surrounding
annulus. The profile or profiles obtained from the data collected
at multiple points along the well string, e.g. drillstring, 22
provides valuable information on events that occur downhole. For
example, if a blockage 50 builds up in annulus 38, a substantial
pressure drop is created across the blockage 50 which affects the
pressure profile, as discussed in greater detail below.
[0038] In some applications, sensors 42 comprise both pressure
sensors 52 and temperature sensors 54, as illustrated in FIG. 2. In
this example, each pressure sensor 52 has an associated temperature
sensor 54 at the same data collection point, however the disparate
types of sensors can be located at distinct locations relative to
each other. The combination of pressure sensors and temperature
sensors can aid in the modeling and interpretation of events that
occur downhole. The sensing of both pressure and temperature is
useful, for example, in high-pressure, high-temperature downhole
environments. By co-locating temperature sensors 54 with pressure
sensors 52, improvements can be made in mapping static and dynamic
pressure-temperature profiles along the well, at least in some
applications. The pressure-temperature profiles also can provide
valuable information for modeling purposes. It should be noted,
however, that temperature sensors 54 can be used independently
and/or in isolation to the pressure sensors. Furthermore, sensors
42 may comprise other types of sensors that can be co-located, or
used in combination, with pressure or temperature sensors. For
example, sensors can be provided for making caliper measurements,
sonic or otherwise, to facilitate the deduction or inference of
other wellbore properties used in improving an operators
understanding of the downhole environment.
[0039] Depending on the application, the sensors 42 are deployed
along interior 34 of the well string 22 and/or external to well
string 22 in the annulus 38 surrounding the well string 22, as best
illustrated in FIG. 3. By way of example, pressure sensors located
internal to a drillstring 22 enable the analysis of internal
pressure losses and the monitoring for drillstring failures, e.g.
drillstring restrictions, plugging, and faulty downhole tools. The
internal sensors also can be used to receive and transmit pressure
pulses from a downhole tool to, for example, increase data
transmission rates relative to conventional mud-pulse telemetry.
The internal sensors are able to detect any number of discrete
pressure drops across downhole tools, e.g. mud motors, submersible
pumps, measurement while drilling systems, drill bits, and other
components to gain valuable engineering and performance monitoring
benefits. The internal sensors also enable the monitoring and
analysis of temperature gradients as well as their comparison to
multipoint annulus measurements taken by sensors deployed in
annulus 38.
[0040] Pressure, temperature, and other sensors deployed in annulus
38 further enable the creation of profiles indicative of a variety
of events/characteristics of a given well. In some applications,
additional sensors 56 are deployed at or on specific components of
bottom hole assembly 30. As illustrated in FIG. 3, for example, one
or more additional sensors 56 can be positioned on drill bit 32 to
obtain temperature data or other data able to provide valuable
information relative to a given operation, e.g. a drilling
operation.
[0041] Data from sensors 42 deployed internally or externally
relative to well string 22 may be transmitted via communication
lines 48 to processor system 44 which may be a control system. In
the example illustrated in FIG. 4, system 44 is a computer or
processor based system that is readily programmed to receive,
process and analyze a variety of time-based data detected at
sensors 42 and uploaded to the processor system 44. As illustrated,
system 44 is a computer-based system having a central processing
unit (CPU) 58. CPU is operatively coupled to a memory 60, as well
as to an input device and 62 and an output device 64. Input device
62 may comprise a variety of devices, such as a keyboard, mouse,
voice-recognition unit, touchscreen, other input devices, or
combinations of such devices. Output device 64 may comprise a
visual and/or audio output device, such as a monitor having a
graphical user interface. This enables the display of a variety of
sensed data, profiles, calculated well characteristics, and other
information to an operator. Additionally, the processing of
multipoint data may be done on a single device or multiple devices
at the well location, away from the well location, or with some
devices located at the well and other devices located remotely.
[0042] The processor system 44 may be used to automatically
process, calculate and analyze a variety of time-based data
obtained at multiple points along the well string 22 from sensors
44. In a drilling application, for example, the relative change
between any two given sensors between a pumps-off period and a
pumps-on period can be measured and processed to calculate the
annular pressure loss and density of the fluid between the two
sensors. The annular pressure loss differences between sensors
enables real-time pressure distributions to be viewed and
interpreted at the surface on, for example, output device 64.
[0043] Data and analyses may be presented to an operator via the
output device 64 in a variety of display formats selected according
to the parameters sensed and the well characteristic being analyzed
over a region of the wellbore. By way of example, a pressure
profile 66 can be displayed in which the pressure at each sensor 42
is displayed versus time, as illustrated in FIG. 5. Annular
pressure is displayed versus time for each sensor via a
corresponding graph line 68. In this particular example, the
pressure profile 66 indicates a significant drop in pressure
between the lower two graph lines 66 which corresponds to the drop
in pressure across annular obstruction 50 that occurs between the
upper two sensors 42 as illustrated in FIGS. 1-3.
[0044] A great variety of information can be displayed, as further
illustrated by the graphical output example of FIG. 6. In this
example, an annular equivalent mud weight is displayed versus
measured depth as calculated from the data provided by sensors 42.
In this display, the graphical output is constructed based on data
provided by six sensors deployed at unique locations along the well
string 22. Data is provided to processor system 44 during a static
stage, as indicated by equivalent static density lines 70, and
during a circulating stage, as indicated by equivalent circulating
density lines 72. The examples provided in FIGS. 5 and 6 are for
purposes of explanation only, and the types of displays provided as
well as the actual parameter data and use of that data can vary
substantially. The multiple sensors 42 positioned at multiple
locations along the drillstring 22, or along other well strings,
enables the detection and construction of a wide variety of
profiles across substantial wellbore regions, which greatly
improves on the ability to evaluate activity in the wellbore during
a drilling operation or other operation.
[0045] One example of how well system 20 can be utilized is
illustrated in the flowchart of FIG. 7. In this application,
pressure sensors 42 are positioned along the drillstring 22, as
indicated by block 74 of the flowchart. The sensors are spaced to
enable accurate creation of a desired parameter profile, as
indicated by block 76. The drillstring 22 and sensors 42 are then
deployed into wellbore 24, as illustrated by block 78. Deployment
of the drillstring and sensors into the wellbore can occur while a
drilling operation is conducted, as illustrated by block 80. The
sensors 42 output data to processor system 44 on a real-time or
near real-time basis for analysis and evaluation, as illustrated by
block 82.
[0046] The data provided to processor system 44 can be processed,
evaluated, and otherwise used in a variety of ways to obtain the
desired information and profiles that will help an operator
analyzed events and characteristics of a given well operation. One
example of the use of this data is illustrated by the flowchart of
FIG. 8. As illustrated, the output parameter data is initially
obtained by processor system 44, as indicated by block 84. The
processor system 44 then determines the position of each sensor 42
at a given point in time during the operation, e.g. drilling
operation, as illustrated by block 86. The data is further
processed to create one or more parameter profiles, as illustrated
by block 88. The parameter profiles and other data can be processed
according to desired algorithms, models, lookup tables, or other
process programs to determine desired operational characteristics,
e.g. mud density, as illustrated by block 90. The data/information
is then presented to an operator via, for example, output device
64, as illustrated by block 92. The displayed or otherwise
presented information can then be used to make operational
adjustments to improve the specific operation, e.g. drilling
operation, as illustrated by block 94.
[0047] The well system 20 and its use of multiple sensors 42
deployed along a well string, e.g. drillstring, provides
substantial data with respect to static and/or dynamic events
occurring in a well. The parameter profiles and other information
allow an operator to make better informed decisions regarding
specific well operations.
[0048] FIG. 9 shows an example method for determining the time and
position of a measurement made in a wellbore. The parameter of
interest, for example pressure or temperature, among others, may be
measured using one or more sensors positioned on a drill string, at
step 96. The decision to make a measurement may be based on a
periodic measurement schedule, in response to a detected condition,
or in response to a query from a control system. In one example,
sensing a parameter includes generating data that relates to the
parameter. For example, temperature data may be collected by a
sensor that comprises a resistive temperature detector. The data
may be the resistance or voltage across the detector, and the date
may be related to the temperature. Similarly, a strain gauge may
generate a voltage that is representative of the strain experienced
by the gauge.
[0049] Next, the method may include applying a time stamp to the
data, at step 98. This may include using a clock associated with or
operatively coupled to the sensor to provide the time at which the
data was recorded. The time may transmitted or stored with the data
to that later analysis may include the time data. In some examples,
the data may be transmitted to the surface in real-time or near
real-time, and in those cases, a time stamp may be applied at the
surface. In other examples, a time stamp may not be applied because
the time of the measurement is otherwise known.
[0050] Next, the method may include storing or transmitting the
data, at step 100. In one example, the data may be transmitted to a
surface location, where it may be received by appropriate equipment
at the surface, such as a control system. The data may be
transmitted by any telemetry means, such as mud-pulse telemetry,
electromagnetic telemetry, acoustic telemetry, and wired drill
pipe. In another example, the data may be stored in a data storage
device associated with the sensor. Stored data may be stored with a
time stamp to identify the time at which the data was acquired.
[0051] Next the method may include reading the data an determining
the time and position where the data was acquired, at step 104. In
one example, the time may be determined by reading a time stamp
associated with the data. In another example, the data may be sent
in real-time or near real-time, and the time at which the data was
acquired may be taken to be the time at which it was received at
the surface. In another example, the date may be transmitted via a
slower telemetry method, and the time the data was collected may be
the time at which is was received, minus an estimate of the transit
time of the signal.
[0052] Determining the position at which the data is collected may
include using the position of the drillstring in the wellbore and
the position of the sensor in the drill string. The position of the
drillstring may be derived from information about the wellbore that
is obtained through surveys and other methods. Surveys are
conducted when the drilling has stopped using accelerometers and
magnetometers in the BHA. In addition, surveys may also be
conducted continuously, during drilling. Further, surveys may be
conducted using a wireline tool or with a deployable tool that may
be deployed in the wellbore.
[0053] Knowing the position of the wellbore may lead to the
position of the drillstring, when it is coupled with the depth of
the drillstring. In some examples, the depth of the drillstring may
be the drillers depth. In other examples, methods may be applied to
account for the elastic deformations of the drillstring under
tension and compression.
[0054] The position of the sensor when the data was acquired may be
determined with reference to the position of the drillstring in the
wellbore and the position of the sensor in the drillstring. In some
examples, methods that account for the compression and stretching
of the drillstring may be used to more accurately locate the sensor
in the drillstring.
[0055] An schematic of an example system is shown in FIG. 10. The
system includes a first sensor 1011 and a second sensor 1012 in a
downhole location. The sensors 1011, 1012 may be part of a system
of distributed sensors in a drillstring. FIG. 10 also shows MWD
sensors 1013, which may be used to make direction and inclination
measurements, called "surveys," to determine the direction and
inclination of the BHA.
[0056] A surface processor 1010 may be located at the surface and
configured to receive data from the sensors 1011, 1012 and the MWD
sensors 1013. A depth encoder 1016 may also be positioned at the
surface for providing data related to the depth of the drillstring
in the borehole. The depth encoder 1016 may collect data from the
surface, such as the length of drillstring that has been lowered
into the borehole. In other examples, the depth encoder may account
for stretching and compression of the drillstring, and it may
acquired data related to the hookload, mud flow rates, mud density,
and weight on bit. In one example, the weight on bit may be
measured by a downhole sensor and transmitted to the surface for
use by the depth encoder.
[0057] The sensors 1011, 1012 and the MWD sensors 1013 may be
connected for communications with each other and with the surface
processor 1010. For example, the sensors 1011, 1012, 1013 may be
connected via a downhole bus or a wired drill pipe telemetry
system. In other examples, each sensor may be connected to a
telemetry device (not shown) that may communicate with the surface
processor 1010.
[0058] In the example shown in FIG. 10, the surface processor 1010
is operatively coupled with a clock 1015 for providing a time stamp
to recorded data. In one example, data collected by the downhole
sensors 1011, 1012 and the MWD sensors 1013 may be transmitted to
the surface processor 1010 in real-time or near real-time, and the
surface processor 1010 may encode a time stamp with data at the
time it is received.
[0059] In one example, the data from the MWD sensors 1013 may be
used in conjunction with the data from the depth encoder 1016 to
determine the position of the drillstring in the wellbore. This,
along with the position of a sensor in the drillstring, may enable
the determination of the position of the sensor when the data was
acquired.
[0060] FIG. 11 shows a schematic of another example system. In FIG.
11, the first sensor 1011, the second sensor 1012, and the MWD
sensors 1013 are each shown with a downhole clock. The first sensor
1011 is operatively coupled to clock 1021, the second sensor is
operatively coupled with clock 1022, and the MWD sensors 1013 are
operatively coupled with clock 1023. The clocks 1021, 1022, 1023
may be used to provide a time stamp to data that are collected by
the sensors 1011, 1012, 1013. In one example, there may be fewer
clocks than sensors. For example, clock 1021 may not be provided,
and the first sensor 1011 may be operatively coupled to the clock
1022, such as through a downhole bus or a wired drill pipe
telemetry system, for example. In this case, the data from the
first sensor 1011 may be time stamped using the clock 1022.
[0061] The depth encoder 1016 may be operatively coupled to a clock
1024 for providing a time stamp to data from the depth encoder
1016. The surface processor 1010 may then use the time stamped data
from the sensors and from the depth encoder to determine the
position of the drillstring in the wellbore and the position of a
sensor in the drillstring to determine the position of the sensor
when particular data was acquired.
[0062] In other example, various other arrangements of sensors and
clocks may be used. For example, there may be a clock associated
with the downhole sensors, as shown in FIG. 11, and a clock
associated with the surface processor, as shown in FIG. 10. Data
from the depth encoder may be time stamped by the surface
processor, while downhole sensor data may be time stamped by a
clock associated with the downhole sensors. Other arrangements will
be apparent to those having skill in the art.
[0063] With a system of multiple, distributed sensors in a
drillstring, this method may be applied to all measurements to
determine the time and position of each measurement. The plurality
of measurements may then be used to create a parameter profile, as
described.
[0064] Accordingly, although only a few examples of the present
invention have been described in detail above, those of ordinary
skill in the art will readily appreciate that many modifications
are possible without materially departing from the teachings of
this invention. Accordingly, such modifications are intended to be
included within the scope of this invention as defined in the
claims.
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