U.S. patent application number 17/019104 was filed with the patent office on 2022-03-17 for well sensors.
This patent application is currently assigned to Patriot Research Center, LLC. The applicant listed for this patent is Patriot Research Center, LLC. Invention is credited to Manish Agarwal, Brandon Cain.
Application Number | 20220082015 17/019104 |
Document ID | / |
Family ID | 1000005091316 |
Filed Date | 2022-03-17 |
United States Patent
Application |
20220082015 |
Kind Code |
A1 |
Cain; Brandon ; et
al. |
March 17, 2022 |
WELL SENSORS
Abstract
A wellhead is provided having a port or ports about the external
periphery of the wellhead. The center bore of each port is
generally directed at a point within the wellhead having a location
where a portion of a tool or an object is expected. Each port does
not provide fluid access from the exterior to the interior of the
wellhead and preferably has a flat bottom. Each port is fitted with
a sensor and preferably the sensor contacts the bottom of the port.
And ultrasonic a sensor emits an ultrasonic waveform which proceeds
through the bottom of the port and a portion of the ultrasonic
waveform is reflected back to the ultrasonic receiver. A comparison
is then performed to compare the predicted value versus the
received value to determine whether or not the expected tool or
object is in place or partially in place within the wellhead.
Inventors: |
Cain; Brandon; (Houston,
TX) ; Agarwal; Manish; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Patriot Research Center, LLC |
Houston |
TX |
US |
|
|
Assignee: |
Patriot Research Center,
LLC
Houston
TX
|
Family ID: |
1000005091316 |
Appl. No.: |
17/019104 |
Filed: |
September 11, 2020 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/007 20200501;
E21B 47/085 20200501; E21B 19/24 20130101; E21B 49/006
20130101 |
International
Class: |
E21B 49/00 20060101
E21B049/00; E21B 47/007 20060101 E21B047/007; E21B 47/085 20060101
E21B047/085; E21B 19/24 20060101 E21B019/24 |
Claims
1. A well sensor system comprising: a first tubular having a
throughbore, wherein the throughbore has a first landing shoulder,
a second tubular having a second landing shoulder, wherein the
first landing shoulder and the second landing shoulder cooperate to
support the second tubular within the throughbore, a bore within
the first tubular and adjacent to the first landing shoulder,
wherein the bore does not penetrate to the throughbore, and a
sensor within the bore capable of detecting the second landing
shoulder.
2. The well sensor system of claim 1 wherein, the sensor transmits
and receives an ultrasonic pulse.
3. The well sensor system of claim 1 wherein, the sensor is
magnetic.
4. The well sensor system of claim 1 wherein, the sensor is a
strain gage.
5. A well sensor system comprising: a first tubular having a
throughbore, wherein the throughbore has a first landing shoulder,
a second tubular having a second landing shoulder, wherein the
first landing shoulder and the second landing shoulder cooperate to
support the second tubular within the throughbore, at least two
bores within the first tubular and adjacent to the first landing
shoulder, wherein the at least two bores do not penetrate to the
throughbore, and a sensor within each of the at least two bores are
capable of detecting the second landing shoulder.
6. The well sensor system of claim 5 wherein, the sensor transmits
and receives an ultrasonic pulse.
7. The well sensor system of claim 5 wherein, each sensor within a
bore is either a magnetic, ultrasonic, or strain gage sensor.
8. The well sensor system of claim 5 wherein, the sensors is
magnetic.
9. The well sensor system of claim 5 wherein, the sensor is a
strain gage
10. The well sensor system of claim 5 wherein, the sensor within
each of the at least two bores are capable of detecting the
distance between the first shoulder and the second shoulder.
11. A well sensor system comprising: a first tubular having a
throughbore, wherein the throughbore has a first landing shoulder,
a second tubular having a second landing shoulder, wherein the
first landing shoulder and the second landing shoulder cooperate to
support the second tubular within the throughbore, at least two
bores within the first tubular and adjacent to the first landing
shoulder, wherein the at least two bores do not penetrate to the
throughbore, and a sensor within each of the at least two bores are
capable of detecting the second landing shoulder; wherein, the
sensor within each of the at least two bores are capable of
detecting the distance between the first shoulder and the second
shoulder; further wherein the signals from the sensors are provided
to a logic controller.
12. The well sensor system of claim 11 wherein, the sensor
transmits and receives an ultrasonic pulse.
13. The well sensor system of claim 11 wherein, each sensor within
a bore is either a magnetic, ultrasonic, or strain gage sensor.
14. The well sensor system of claim 11 wherein, the sensors is
magnetic.
15. The well sensor system of claim 11 wherein, the sensor is a
strain gage
16. The well sensor system of claim 11 wherein, the logic
controller determines the orientation of the second tubular within
the throughbore.
Description
BACKGROUND
[0001] When drilling an oil or gas well, initially a large diameter
borehole is drilled. At some point it becomes necessary to case the
initial large diameter borehole. A length of appropriately sized
pipe is positioned in this vertical hole and cement is forced
downward into the interior of the pipe and thereafter to flow
upwardly in the annular area exterior of the pipe. Anchoring the
pipe solidly in the earth. Thereafter, successively smaller
boreholes are drilled, cased and cemented until the formation or
formations are reached. In order to prepare the cased well for
production, a production tubing string is run into the cased
borehole. Other tubulars may be placed within the casing and not
cemented.
[0002] In general, each successively smaller borehole requires a
smaller diameter tubing. In order to firmly anchor a smaller
diameter tubing within a larger diameter tubing a tubing hanger is
installed. The tubing hanger will have a larger diameter portion to
act as a shoulder that cooperates with a decreased diameter portion
within the larger diameter tubular within which the tubing hanger
is being fitted to act as a stop or landing for the tubing
hanger.
[0003] Generally a precise fitting of the tubing hanger shoulder
within the larger diameter shoulder is required due to subsequent
tubulars, seals, tools, other tubing hangers, etc. that will later
be landed on or fit to the current tubing hanger. Unfortunately,
misalignment or improper landing of the tubing hanger onto the
shoulder is an all too common occurrence. In some instances the
misalignment is due to the initial preparation of the well site
where the well pad is not particularly level resulting in a
drilling rig that may not be normal to the surface when it begins
to drill therefore the wellbore is angled as it penetrates the
surface. In other instances the landing shoulder of the previous
tubular may be contaminated with rock, steel shavings, or other
debris so that when the subsequent tubing hanger is lowered into
place the tubing hanger cannot land precisely on the shoulder. In
such an event the tubing hanger may be cocked or may be high. In
other instances the location of the landing shoulder may not be
precisely known or the measuring instruments are imprecise. For
instance some operators may use a 5 foot tally stick to tally the
drill pipe over 30 or 40 feet where the intent is to locate a
shoulder within half of an inch. In such a case the tubing hanger
may be lowered onto what is thought to be the landing shoulder and
the locking ring set but is later found to be improperly landed. In
the past, tubing hangers may have had a port that penetrated the
pressure vessel of the previously installed tubulars that would
allow a rig worker to crawl down into the cellar underneath the
wellhead and physically look into the pressure vessel as the tubing
hanger was landed in order to get a visual indication of the tubing
hanger being landed. However, placing a person in the cellar as
tubing is being landed is precarious at best and having a
penetration from the exterior into the interior of the pressure
vessel is no longer desired.
[0004] Today, the only way that an operator may be certain that a
tubing hanger is latched into place is to do an over pull on the
tubing hanger. Unfortunately, even in over pull is not precise in
that it largely depends upon the operator performing the over pull
added to the possibility of damaging the rig, the wellhead or other
equipment in the bore during an over pull.
SUMMARY
[0005] In an embodiment of the current invention a sensor port is
formed, usually by drilling, in the bowl of the wellhead or
previously placed tubular or other tool. The port is usually formed
so that it has a flat bottom and does not penetrate the bowl or
other pressure vessel. Generally the port is aligned such that the
centerline of the port points to the landing shoulder, preferably
with no occlusions or intervening spaces. Additionally, it is
preferred that the bottom of the port is flat and that the
ultrasonic receiver or transmitter is placed against the flat
bottom port. In certain instances a second material may be placed
between the bottom of the whole and the ultrasonic receiver or
transmitter the second material may be a liquid or solid. It is
envisioned that the sensor consists of an ultrasonic transmitter
and receiver although in some instances one port may have an
ultrasonic transmitter while another port has an ultrasonic
receiver. The ultrasonic transmitter will transmit an ultrasonic
waveform in the direction of the bowl shoulder. A portion of the
ultrasonic waveform will be reflected by the interruption in the
material at the edge of the bowl shoulder. The reflected ultrasonic
waveform is then picked up by the ultrasonic receiver. The
remainder of the ultrasonic waveform will travel on through
whatever medium may be present. In some cases, in particular where
the tubing hanger is improperly landed, the initial media may be
air. In this case the ultrasonic waveform travels through the air
and then a portion of the ultrasonic waveform will be reflected
back to the ultrasonic receiver. In other instances, for instance
when the tubing hanger is properly landed, immediately at the
interruption in the bowl is the metal or other material of the
tubing hanger. In such an instance the ultrasonic waveform enters
the material of the tubing hanger and continues on until it is
reflected off of the next surface. A processor having a memory and
power source will then analyze the ultrasonic waveforms and compare
the ultrasonic waveform returns to returns in the memory to
determine whether or not the tubing hanger was landed or at least
the tubing hanger shoulder was adjacent to the bowl shoulder at the
point being measured.
[0006] In certain instances the ultrasonic sensor may simply give
an indication, such as a light or flag, as to whether or not the
tubing hanger is landed at the location being tested. In other
instances multiple ultrasonic sensors may be arranged around the
periphery of the wellhead. In such an instance it may be the
amalgamation of all sensors to give an indication as to whether or
not the tubing hanger is landed or is cocked within the wellhead.
For instance in a case where you may have four sensors around the
periphery of the wellhead where a 1.sup.st sensor is located at
0.degree., a 2.sup.nd sensor is located at 90.degree., a 3.sup.rd
sensor is located at 180.degree., and a 4.sup.th sensor is located
at 270.degree. the 1.sup.st sensor may indicate that the tubing
hanger is on the landing shoulder within the wellhead at the
0.degree. location. The 2.sup.nd sensor may indicate that the
tubing hanger is off of the landing shoulder within the wellhead by
some distance X. The 3.sup.rd sensor may indicate that the tubing
hanger is off of the landing shoulder within the wellhead by some
distance Y. The 4.sup.th sensor may indicate that the tubing hanger
is off of the landing shoulder within the wellhead by some distance
Z. Each of the indications may then be used to determine how much
and in which direction is the tubing hanger off of the
shoulder.
[0007] In other instances other types of sensors may be utilized
for instance strain gauges may be utilized in place of or with
ultrasonic sensors. A strain gauge may be placed in the sensor port
to determine whether or not a predicted load is present. If the
load is either not present or differs from the predicted amount the
tubing hanger may not be landed or may be set at an angle within
the wellhead. If multiple strain gauges are utilized such as
multiple strain gauges around the periphery of the wellhead to
predicted load can be measured against the measured load to
determine whether or not the tubing hanger is landed or whether the
tubing hanger is set in an angle within the wellhead and at what
angle it may be set.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIG. 1 depicts a side cutaway view of a wellhead having a
hanger landed and seated.
[0009] FIG. 2 depicts inset A from FIG. 1.
[0010] FIG. 3 is a top down view of the wellhead having sensor
ports and sensors with a landed tubing hanger of FIG. 1.
[0011] FIG. 4 is a side cutaway view of a wellhead, with ultrasonic
sensors, having a tubing hanger improperly landed within the
wellhead.
[0012] FIG. 5 depicts inset B from FIG. 4.
[0013] FIG. 6 depicts a flowchart showing at least some of the
steps that the sensor and a logic controller step through.
[0014] FIG. 7 depicts a flowchart showing at least some of the
steps that the sensor and a logic controller step through in
instances where multiple sensors may be used around the
wellhead.
DETAILED DESCRIPTION
[0015] The description that follows includes exemplary apparatus,
methods, techniques, or instruction sequences that embody
techniques of the inventive subject matter. However, it is
understood that the described embodiments may be practiced without
these specific details. When referring to the top of the device or
component top is towards the surface of the well. Side is radially
offset from a component but minimally longitudinally offset.
[0016] FIGS. 1-3 depict the various pieces and assemblies of a
wellhead having sensor ports and sensors with a landed tubing
hanger. FIG. 1 is a side cutaway view of a wellhead 102 with
ultrasonic sensors 104 and 106 having a tubing hanger 112 landed
within the wellhead 102. The wellhead 102 has a 1.sup.st bore 108
and a 2.sup.nd bore 110. Other bores and sensors may exist around
the periphery of the wellhead 102 but are not shown in FIG. 1. In
some embodiments the sensors may include inductive, capacitive,
magnetic, accelerometers, strain gauges, or other sensors. In the
embodiment shown in FIG. 1 all the preferred embodiment uses
ultrasonic sensors sensor 104 may be an ultrasonic sensor while
sensor 106 could be a strain gauge. When placing a sensor such as
sensor 104 within wellhead 102 a bore 108 is formed within the
wellhead. Preferably a bore such as bore 108 has a bottom 114 that
is flat. The bottom 114 of bore 108 is generally formed to be
close, preferably within one quarter of an inch, to the element
that is being observed by the sensor. As shown in FIG. 1 the bottom
114 of bore 108 is placed near circumferential shoulder 116 of
wellhead 102. Tubing hanger 112 includes a matching circumferential
shoulder 118 that lands on shoulder 116 in cooperates with shoulder
116 to suspend the tubing hanger 112 within the wellhead 102. As
depicted in FIG. 1 the tubing hanger 112 is properly landed within
wellhead 102 so that shoulders 118 of the tubing hanger 112 are
flush against shoulders 116.
[0017] FIG. 2 depicts inset A from FIG. 1. As can be seen bore 108
includes a flat bottom 114 so that the matching flat bottom 116 of
sensor 104 can be placed flush against the flat bottom 114. Sensor
104 may be an ultrasonic emitter or a receiver or in this case is
both an ultrasonic emitter and receiver. Sensor 104 will emit an
ultrasonic pulse 120 towards shoulder 116. The ultrasonic pulse 120
is then reflected back towards sensor 104 as a reflection 122. In
the event that tubing hanger 112 is properly landed such that
tubing hanger shoulder 118 abuts wellhead shoulder 116 then sensor
104 will see a single reflection.
[0018] FIG. 3 is a top down view of the wellhead having sensor
ports and sensors with a landed tubing hanger of FIG. 1. The
wellhead 102 has landed within it the tubing hanger 112. As can be
seen in this view the wellhead 102 has bore 108 with sensor 104
therein and bore 110 with sensor 106 therein. Additionally, we can
now see bore 109 having sensor 105 therein and bore 111 having
sensor 107 therein. Each sensor will, in this instance, emit an
ultrasonic pulse and will receive the echo of the emitted
ultrasonic pulse. Generally, with the tubing hanger 112 landed on
the shoulder 116 a single echo will be returned. In certain
instances each of the sensors may be different types of sensors in
that one bore may have an ultrasonic sensor placed within the bore
while another bore may have a magnetic or strain gage sensor within
the bore.
[0019] FIG. 4 is a side cutaway view of a wellhead 502, with
ultrasonic sensors 504 and 606, having a tubing hanger 512
improperly landed within the wellhead 502. The improper landing of
the tubing hanger 512 within the wellbore may be caused by debris
within the wellhead 502, improper alignment of the wellhead,
improper alignment of the tubing hanger, or other causes. The
wellhead 502 has a 1.sup.st bore 508 and a 2.sup.nd bore 510. Other
bores and sensors may exist around the periphery of the wellhead
502 but are not shown in FIG. 4. In some embodiments the sensors
may include inductive, capacitive, magnetic, accelerometers, strain
gauges, or other sensors. In the preferred embodiment in FIG. 4 the
sensors are ultrasonic sensors. In other embodiments sensor 504 may
be an ultrasonic sensor while sensor 506 could be a strain gauge.
When placing a sensor such as sensor 504 within wellhead 502 a
bore, such as bore 508 is formed within the wellhead. Preferably
the bore 508 has a bottom 514 that is flat. The bottom 514 of bore
508 is generally formed to be near, preferably within one quarter
of an inch, to the element that is being observed by the sensor
504. As shown in FIG. 4 the bottom 514 of bore 508 is placed near
circumferential shoulder 516 of wellhead 502. Tubing hanger 512
includes a matching circumferential shoulder 518 that lands on
circumferential shoulder 516 in cooperation with shoulder 516 to
suspend the tubing hanger 512 within the wellhead 502.
[0020] As depicted in FIG. 4 the tubing hanger 512 is improperly
landed within wellhead 502. Tubing hanger shoulder 518 is
relatively flush to wellhead shoulder 517. The adjacent sensor 506
emits an ultrasonic signal 521 and receives reflection or echo 523.
The single reflection 523 indicates that tubing hanger shoulder 518
is relatively flush to wellhead shoulder 517. However, due to
tubing hanger 512 being improperly landed, tubing hanger shoulder
518 is held above wellhead shoulder 516. The adjacent sensor 504
emits an ultrasonic signal 525 and receives a first reflection 527
from wellhead shoulder 516 and also receives a second reflection
529. The two reflections 527 and 529 indicates that tubing hanger
shoulder 518 is some distance away from wellhead shoulder 516 and
the tubing hanger 512 is therefore not properly landed within
wellhead 502.
[0021] FIG. 5 depicts inset B from FIG. 4. Ultrasonic sensor 504 is
in place within bore 508 within wellhead 502. Wellhead 502 has a
shoulder 516 near the flat bottom 514 of bore 508. The tubing
hanger 512 has been improperly landed within wellhead 502 such that
tubing hanger shoulder 518 is not landed on wellhead shoulder 516
leaving a void 517 between the tubing hanger 512 and the shoulder
518. Ultrasonic sensor 504 emits a pulse 525 through flat bottom
514 of bore 508 in the direction of shoulder 516. A portion of
pulse 525 is reflected back towards ultrasonic sensor 504 from
shoulder 516. Another portion of pulse 525 continues to travel on
past shoulder 516 through void 517 where a portion of the pulse 525
is reflected by tubing hanger 512, shown here as reflection 529. In
some instances pulse 525 may be reflected by shoulder 518 or may be
partially reflected by debris in void 517 while another portion is
reflected by the next solid object in pulse 525's path.
[0022] FIG. 6 depicts a flowchart showing at least some of the
steps that the sensor and onboard logic controller and/or the
sensor and a separate logic controller would go through in order to
make a determination whether or not a device is landed on the
shoulder or not. As depicted the sensor will emit a signal 602 and
a determination will be made as to whether or not the signal was
reflected back to the sensor 604. If no signal reflection is
detected in the sensor repeats until a signal is detected 606. If
the signal is detected then a determination is made is there a
single reflection or multiple reflections 608. If only a single
signal reflection is detected then the shoulder is landed and an
indication will be provided to signal an operator that the shoulder
is landed 610. The indication may be a light or other physical
indicator on the sensor. In other instances, the indication may be
given on a screen that is connected to the logic controller. If 2
or more signals are received then a determination is made as to the
time delta between the 1.sup.st 2 signals. If the time delta is
less than the preset time delta then the 2 signals may be
considered as a single signal and the tubing hanger may be
considered landed with an appropriate indication given to the
operator 614. If the time delta is greater than a preset then the 2
signals may be compared to a signal library 616. Provided that a
comparison is found within the signal library and indication is
given to the operator regarding the improper landing. 618 In some
instances if there is no signal library then the logic controller
is instructed to calculate the size of the void, i.e. how far off
of the wellhead shoulder is the tubing hanger, by utilizing the
time delta between the 2 signal reflections and the speed of the
signal 620. If the calculated distance is greater than a preset
value than a not landed message as well as the distance is provided
on the display 622. If the calculated distance is less than the
preset value than the landed indication is provided 655.
[0023] In certain instances, as depicted in FIG. 7 multiple sensors
may be used around the circumference of the wellhead, such as the
wellhead shown in FIG. 3. Reference points for each sensor location
will be input into the logic controller 710. The logic controller
may then proceed through each of the steps as indicated in FIG. 6
to provide an output, such as output 655 for each sensor location
712. If the distance as calculated for output 655 is 0.00, or at
least less than a preset value, then a landed indication will be
provided 714. If the distance is greater than the preset value or
0.00 then the logic controller uses the size of the wellhead and
the position of each sensor around the wellhead along with the
distance that the tubing hanger or other device being positioned
within the head is above the respective shoulder as provided in
output 655 to calculate the distance and direction of the
misalignment between the tubing hanger and the wellhead 720.
[0024] While a wellhead and tubing were referenced in the
description above it is understood that wellhead and tubing hanger
were used only as examples and any device landing in a second
device may utilize this method.
[0025] The nomenclature of leading, trailing, forward, rear,
clockwise, counterclockwise, right hand, left hand, upwards, and
downwards are meant only to help describe aspects of the tool that
interact with other portions of the tool.
[0026] Plural instances may be provided for components, operations
or structures described herein as a single instance. In general,
structures and functionality presented as separate components in
the exemplary configurations may be implemented as a combined
structure or component. Similarly, structures and functionality
presented as a single component may be implemented as separate
components. These and other variations, modifications, additions,
and improvements may fall within the scope of the inventive subject
matter.
* * * * *