U.S. patent application number 14/910271 was filed with the patent office on 2016-06-23 for realtime downhole sample volume collection.
This patent application is currently assigned to Halliburton Energy Services, Inc.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Scott L. Miller, Gregory T. Werkheiser.
Application Number | 20160177713 14/910271 |
Document ID | / |
Family ID | 52666059 |
Filed Date | 2016-06-23 |
United States Patent
Application |
20160177713 |
Kind Code |
A1 |
Miller; Scott L. ; et
al. |
June 23, 2016 |
REALTIME DOWNHOLE SAMPLE VOLUME COLLECTION
Abstract
A method and apparatus for realtime downhole sample volume
collection is described. The sampler apparatus includes a sample
chamber and a sensor for real-time measurement disposed proximate
to the sample chamber. In one embodiment, the sample chamber may
include a piston, and the sensor may be mounted on the piston. The
sensor may comprise a flow meter, a light sensor, a capacitive
sensor, a resistive sensor, a movement sensor, an acceleration
sensor, a continuity sensor, or other sensor types known to those
of skill in the art, and it may measure fluid volume, pressure,
composition, or other properties. Optionally, a telemetry system
may be included to transmit the real-time sensor measurements to
the surface.
Inventors: |
Miller; Scott L.; (Highland
Village, TX) ; Werkheiser; Gregory T.; (Dallas,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
52666059 |
Appl. No.: |
14/910271 |
Filed: |
September 10, 2013 |
PCT Filed: |
September 10, 2013 |
PCT NO: |
PCT/US2013/059026 |
371 Date: |
February 5, 2016 |
Current U.S.
Class: |
73/152.28 |
Current CPC
Class: |
E21B 49/08 20130101;
E21B 49/081 20130101 |
International
Class: |
E21B 49/08 20060101
E21B049/08 |
Claims
1. A sampler carrier, comprising: a sample chamber; and a sensor
for real-time measurement disposed proximate to said sample
chamber.
2. The sampler carrier of claim 1, wherein said sensor is a flow
meter.
3. The sampler carrier of claim 2, wherein said flow meter is an
impeller flow meter.
4. The sampler carrier of claim 1, further comprising a piston
disposed within said sampler chamber, wherein said sensor is
coupled to said piston.
5. The sampler carrier of claim 4, wherein said sensor comprises at
least one of a flow meter, a light sensor, a capacitive sensor, a
resistive sensor, a movement sensor, an acceleration sensor, or a
continuity sensor.
6. The sampler carrier of claim 4, wherein said piston is a sampler
entry piston.
7. The sampler carrier of claim 4, wherein said piston is a junk
piston.
8. The sampler carrier of claim 1, further comprising a telemetry
system communicatively coupled to said sensor.
9. The sampler carrier of claim 8, wherein said telemetry system
communicates directly with a surface receiver.
10. The sampler carrier of claim 8, wherein said telemetry system
communicates indirectly with a surface receiver via a second
downhole telemetry system.
11. A method for sampling, comprising: deploying a sample chamber
downhole; filling said sample chamber with a downhole fluid; and
performing at least one measurement of said fluid with a sensor
proximate to said sample chamber while said sample chamber is
downhole.
12. The method of claim 11, wherein said sensor is a flow
meter.
13. The method of claim 12, wherein said flow meter is an impeller
flow meter.
14. The method of claim 11, wherein said sensor is coupled to a
piston.
15. The method of claim 14, wherein said piston is a sampler entry
piston.
16. The method of claim 14, wherein said piston is a junk
piston.
17. The method of claim 11, wherein said sensor comprises at least
one of a flow meter, a light sensor, a capacitive sensor, a
resistive sensor, a movement sensor, an acceleration sensor, or a
continuity sensor.
18. The method of claim 17, wherein said at least one measurement
includes at least one of said fluid's volume, pressure, or
composition.
19. The method of claim 11, further comprising transmitting said at
least one measurement using a telemetry system.
20. The method of claim 19, wherein said telemetry system transmits
said at least one measurement to a second downhole telemetry
system.
Description
BACKGROUND
[0001] The present disclosure relates generally to oil field
exploration and, more particularly, to a system and method for
realtime downhole sample volume collection via telemetry.
[0002] It is well known in the subterranean well drilling and
completion art to perform tests on formations intersected by a
wellbore. Such tests are typically performed in order to determine
geological or other physical properties of the formation and fluids
contained therein. For example, parameters such as permeability,
porosity, fluid resistivity, temperature, pressure and bubble point
may be determined. These and other characteristics of the formation
and fluid contained therein may be determined by performing tests
on the formation before the well is completed.
[0003] One type of testing procedure that is commonly performed is
to obtain a fluid sample from the formation to, among other things,
determine the composition of the formation fluids. In this
procedure, it is important to obtain a sample of the formation
fluid that is representative of the fluids as they exist in the
formation. In a typical sampling procedure, a sample of the
formation fluids may be obtained by lowering a sampling tool having
a sampling chamber into the wellbore on a conveyance such as a
wireline, slick line, coiled tubing, jointed tubing or the like.
When the sampling tool reaches the desired depth, one or more ports
are opened to allow collection of the formation fluids. The ports
may be actuated in variety of ways such as by electrical, hydraulic
or mechanical methods. Once the ports are opened, formation fluids
travel through the ports and a sample of the formation fluids is
collected within the sampling chamber of the sampling tool. After
the sample has been collected, the sampling tool may be withdrawn
from the wellbore so that the formation fluid sample may be
analyzed.
[0004] Under that traditional approach, the integrity of the sample
may not be verified until the sampling tool is withdrawn from the
wellbore. If a sampling error has occurred, such as a failure to
retain a sample, then the sampling tool must be redeployed and the
sampling process restarted. This may result in unnecessary and
costly tripping of the sampling tool. Further, even if a sample is
successfully captured, any analysis of that sample similarly must
be deferred until after the sampling tool is withdrawn.
FIGURES
[0005] Some specific exemplary embodiments of the disclosure may be
understood by referring, in part, to the following description and
the accompanying drawings.
[0006] FIG. 1 illustrates an example drilling system.
[0007] FIG. 2 illustrates a representative fluid sampler
system.
[0008] FIG. 3 shows an exemplary embodiment of a sampler according
to the present disclosure using a flow meter for real-time
measurement.
[0009] FIG. 4 shows an exemplary embodiment of a sampler according
to the present disclosure that uses a piston-mounted sensor for
real-time measurement.
[0010] FIGS. 5A-B illustrate exemplary piston and sensor
configurations.
[0011] While embodiments of this disclosure have been depicted and
described and are defined by reference to exemplary embodiments of
the disclosure, such references do not imply a limitation on the
disclosure, and no such limitation is to be inferred. The subject
matter disclosed is capable of considerable modification,
alteration, and equivalents in form and function, as will occur to
those skilled in the pertinent art and having the benefit of this
disclosure. The depicted and described embodiments of this
disclosure are examples only, and not exhaustive of the scope of
the disclosure.
DETAILED DESCRIPTION
[0012] The present disclosure relates generally to oil field
exploration and, more particularly, to a system and method for
realtime downhole sample volume collection via telemetry.
[0013] Illustrative embodiments of the present disclosure are
described in detail herein.
[0014] In the interest of clarity, not all features of an actual
implementation may be 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 the specific implementation goals, 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.
[0015] To facilitate a better understanding of the present
disclosure, the following examples of certain embodiments are
given. In no way should the following examples be read to limit, or
define, the scope of the disclosure. Embodiments of the present
disclosure may be applicable to horizontal, vertical, deviated,
multilateral, u-tube connection, intersection, bypass (drill around
a mid-depth stuck fish and back into the well below), or otherwise
nonlinear wellbores in any type of subterranean formation.
Embodiments may be applicable to injection wells, and production
wells, including natural resource production wells such as hydrogen
sulfide, hydrocarbons or geothermal wells; as well as borehole
construction for river crossing tunneling and other such tunneling
boreholes for near surface construction purposes or borehole u-tube
pipelines used for the transportation of fluids such as
hydrocarbons. Devices and methods in accordance with embodiments
described herein may be used in one or more of
measurement-while-drilling ("MWD") and logging-while-drilling
("LWD") operations. Embodiments described below with respect to one
implementation are not intended to be limiting.
[0016] FIG. 1 is a diagram illustrating an example drilling system
100, according to aspects of the present disclosure. The drilling
system 100 includes rig 101 at the surface 111 and positioned above
borehole 103 within a subterranean formation 102. Rig 101 may be
coupled to a drilling assembly 104, comprising drill string 105 and
bottom hole assembly 106. The bottom hole assembly 106 may comprise
a drill bit 109, steering assembly 108, and a LWD/MWD apparatus
107. A control unit 114 at the surface may comprise a processor and
memory device, and may communicate with elements of the bottom hole
assembly 106, including LWD/MWD apparatus 107 and steering assembly
108. The control unit 114 may receive data from and send control
signals to the bottom hole assembly 106. Additionally, at least one
processor and memory device may be located downhole within the
bottom hole assembly 106 for the same purposes. The LWD/MWD
apparatus 107 may comprise at least one fluid sampler system as
well as various other measuring or logging assemblies that would be
appreciated by one of ordinary skill in the art in view of this
disclosure.
[0017] FIG. 2 illustrates an example fluid sampler system 200 and
associated methods that embody aspects of the present disclosure. A
tubular string 212, such as a drill stem test string, is positioned
in a wellbore 214. An internal flow passage 216 extends
longitudinally through tubular string 212.
[0018] In the embodiment shown, a fluid sampler 218 is coupled to
the tubular string 212. In other embodiments, the fluid sampler 218
may be deployed downhole using a wireline, slickline, coiled
tubing, downhole robot, etc., rather than tubular string 212. A
circulating valve 220, a tester valve 222 and a choke 224 also may
be coupled to the tubular string 212. Circulating valve 220, tester
valve 222 and choke 224 may be of conventional design. As would be
appreciated by one of ordinary skill in the art in view of this
disclosure, it is not necessary for tubular string 212 to include
any specific combination or arrangement of equipment described
herein. Additionally, although wellbore 214 is depicted as being
cased and cemented, it could alternatively be uncased or open
hole.
[0019] In an example formation testing operation, tester valve 222
is used to selectively permit and prevent flow through passage 216.
Circulating valve 220 is used to selectively permit and prevent
flow between passage 216 and an annulus 226 formed radially between
tubular string 212 and wellbore 214. Choke 224 is used to
selectively restrict flow through tubular string 212. Each of
valves 220, 222 and choke 224 may be operated by manipulating
pressure in annulus 226 from the surface, or any of them could be
operated by other methods if desired.
[0020] Choke 224 may be actuated to restrict flow through passage
216 to minimize wellbore storage effects due to the large volume in
tubular string 212 above sampler 218. When choke 224 restricts flow
through passage 216, a pressure differential is created in passage
216, thereby maintaining pressure in passage 216 at sampler 218 and
reducing the drawdown effect of opening tester valve 222. In this
manner, by restricting flow through choke 224 at the time a fluid
sample is taken in sampler 218, the fluid sample may be prevented
from going below its bubble point, i.e., the pressure below which a
gas phase begins to form in a fluid phase.
[0021] Circulating valve 220 permits hydrocarbons in tubular string
212 to be circulated out prior to retrieving tubular string 212.
Circulating valve 220 also allows increased weight fluid to be
circulated into wellbore 214.
[0022] Although FIGS. 1-2 depict a vertical well, it should be
noted by one skilled in the art that the fluid sampler of the
present disclosure is equally well-suited for use in deviated
wells, inclined wells or horizontal wells. As such, the use of
directional terms such as above, below, upper, lower, upward,
downward and the like are used in relation to the illustrative
embodiments as they are depicted in the figures, the upward
direction being toward the top of the corresponding figure and the
downward direction being toward the bottom of the corresponding
figure.
[0023] FIG. 3 shows an exemplary embodiment of a sampler 300
according to the present disclosure. The sampler may include a
sampler carrier 360 with a sample chamber 340 and an inlet 320
coupled to the sample chamber 340. A sensor for real-time
measurement 330 may be disposed proximate to the sample chamber
340. Real-time measurement may comprise taking of measurements at
the time the sample is acquired or after the sample is acquired but
while the sampler remains downhole. Measurements may include, for
example, the volume, pressure, position, and composition of a
sample, and/or may include any of the other measurements made by
sensors found in production logging tools. In the embodiment shown,
the sensor for real-time measurement comprises a flow meter 330. As
shown in FIG. 3, the oil or other fluid to be sampled moves through
a passage 310. It may be taken into sampler 340 via inlet 320.
[0024] Flow meter 330 is disposed within inlet 320 such that as oil
or other fluids flow from passage 310 to sampler 340, they pass
through flow meter 330. In the embodiment of FIG. 3, flow meter 330
is shown as an impeller-type flow meter. An impeller-type flow
meter may contain rotatable blades that are rotated by the passage
of liquid. The blades may be configured so that the inflow of
liquid causes rotational movement of the blades in one direction,
while the outflow of liquid causes rotational movement of the
blades in the opposite direction. In the embodiment shown, for
example, the movement of liquid into sampler 340 from passage 310
via inlet 320 may cause the blades of flow meter 330 to rotate in a
clockwise direction; by comparison, the movement of liquid out of
sampler 340 back into passage 310 via inlet 320 may cause the
blades of flow meter 330 to rotate in a counter-clockwise
direction. In this way, a person of ordinary skill in the art will
appreciate that the amount of fluid entering our exiting sampler
340 may be determined by measuring the direction and magnitude of
blade rotation.
[0025] Although the embodiment of FIG. 3 shows the sensor as an
impeller-type flow meter, other types of sensors known to those of
skill in the art may be used consistent with the present
disclosure. For example, other types of flow-meters may be used,
such as an infrared sensor or a light sensor that detects the
movement of fluid. In addition, the sensor may take other types of
measurements of the sample, for example measurements regarding the
volume, pressure, position, and composition of the sample. The
sensor 330 may therefore include a light sensor that determines the
type of gas or capacitive sensors, resistive sensors, movement
sensors, acceleration sensors, or continuity sensors. As one of
skill in the art will appreciate, the sensor 330 may include any of
the sensors commonly found in production logging tools.
[0026] Regardless of the type of flow meter employed, flow meter
330 may be used to measure the inflow and outflow of fluid from
sampler 340. The measurements may, for example, verify that fluid
has begun flowing into sampler 340 at the beginning of a sample
collection cycle, determine the amount of fluid that has flowed
into sampler 340 during a sample collection cycle, or identify
whether any fluid has flowed out of sampler 340.
[0027] The measurements performed by flow meter 330 may be
communicated to a surface operator by means of telemetry
communications 355, for example by using telemetry device 350. One
of skill in the art will appreciate that many kinds of telemetry
may be used consistent with the present disclosure, such as wired
telemetry, wireless telemetry, or mud-pulse telemetry. In an
alternative embodiment, discussed in more detail below with
reference to the embodiment of FIG. 4, sampler 300 may have a
simple telemetry system for sending short, low-power
communications, and the information from sampler 300 may be relayed
to the surface by a more robust telemetry system located elsewhere
in the downhole tool.
[0028] Using such telemetry, a surface operator may monitor the
sampler in realtime and send appropriate instructions based on the
received measurements. For example, if flow meter 330 communicates
a measurement showing that fluid has leaked out of sampler 340, the
surface operator may initiate the collection of a replacement
sample.
[0029] As one of skill in the art will appreciate, although the
embodiment of FIG. 3 shows only one flow meter 330, sampler 340,
and telemetry system 350 in sampler carrier 360, a sampler carrier
360 may include a plurality of flow meters, samplers, and/or
telemetry systems.
[0030] FIG. 4 shows an exemplary embodiment of a sampler 400
according to the present disclosure that uses a piston-mounted
sensor for real-time measurement. As in the embodiment of FIG. 3,
the oil or other fluid to be sampled moves through a passage 410
and may be taken into a sampler 440 via an inlet 420. In the
embodiment of FIG. 4 a piston 430 and a sensor 435 may be included
in sampler 440. Various exemplary configurations for the piston and
sensor are shown in FIGS. 5A-B and discussed below.
[0031] Similar to the sensor 330 of FIG. 3, the sensor 435 may take
measurements of the sample, such as measurements regarding the
volume, pressure, position, and composition of the sample. Sensor
435 may include a light sensor that determines the type of gas or
capacitive sensors, resistive sensors, movement sensors,
acceleration sensors, or continuity sensors. As one of skill in the
art will appreciate, sensor 435 may include any of the sensors
commonly found in production logging tools.
[0032] The measurements captured by sensor 435 may be communicated
to a surface operator by means of telemetry. This may be
accomplished by directly sending telemetry signals from sampler 400
to the surface, as in the embodiment shown in FIG. 3.
Alternatively, as shown in the embodiment of FIG. 4, the piston 430
or sensor 435 may include a simple telemetry system for sending
short, low-power communications 445. Those short low-power
communications 445 may be received by a more sophisticated
telemetry system 450 that is configured to send telemetry
communications 455 to the surface. The simple telemetry system of
piston 430 or sensor 435 may be, for example, an acoustic telemetry
system. The more sophisticated telemetry system 450 may be, for
example, a wired telemetry, wireless telemetry, or mud-pulse
telemetry system used by other tools in a LWD/MWD apparatus.
[0033] As with FIG. 3, although FIG. 4 shows only one piston 430,
sensor, 435, sampler 440, and telemetry system 450 in sampler
carrier 460, a sampler carrier may include a plurality of pistons,
sensors, samplers, and/or telemetry systems.
[0034] FIGS. 5A-B illustrate exemplary configurations for the
piston and sensor of FIG. 4. In particular, the exemplary
configurations shown include two pistons, a sample entry piston 516
and a junk piston 518. The operation of the pistons is similar in
both configurations. A fluid to be sampled, for example oil, is
received from an inlet (such as inlet 420 in FIG. 4) into sample
fluid chamber 514. The flow between the inlet and sample fluid
chamber 514 may be controlled by sample entry piston 516, for
example by means of a check valve or restrictor.
[0035] A junk piston 518 may separate sample fluid chamber 514 from
a displacement fluid chamber 524. In the illustrated embodiment, as
fluid flows into sample chamber 514, fluid may be permitted to flow
into junk chamber 526. The flow of fluid into junk chamber 526 may
be controlled, for example, by a check valve on junk piston 518. As
a result of fluid flowing into the junk chamber, junk chamber 526
may expand. The fluid received in junk chamber 526 is prevented
from escaping back into sample chamber 514 by the junk piston, for
example by means of a check valve. In this manner, the fluid
initially received into sample chamber 514 is trapped in junk
chamber 526. This initially received fluid is typically laden with
debris, or is a type of fluid (such as mud) which it is not desired
to sample. Junk chamber 526 thus permits this initially received
fluid to be isolated from the fluid sample later received in sample
chamber 514.
[0036] Once fluid is no longer permitted to flow from sample
chamber 514 into junk chamber 526, fluid may begin to fill sample
chamber 514. As the fluid sample is received in sample chamber 514,
the sample chamber 514 expands and junk piston 518 is displaced
downwardly. Downward displacement of the junk piston 518 may be
slowed by displacement fluid in a displacement chamber 524.
Displacement fluid chamber 524 may initially contain a displacement
fluid, such as a hydraulic fluid, silicone oil, or the like, and
the flow of displacement fluid out of displacement fluid chamber
524 may be regulated by a check valve or other flow restrictor.
This may prevent pressure in the fluid sample received in the
sample chamber 514 from dropping below its bubble point.
[0037] In the configuration shown in FIG. 5A, sensor 535 is
disposed proximate to the sample entry piston 516. Sample
measurements may be taken as the fluid passes through sample entry
piston 516. By comparison, in the configuration shown in FIG. 5B,
sensor 535 is disposed proximate to the junk piston 518. Sample
measurements may be taken as the fluid enters sample chamber 514 or
junk chamber 526. In both configurations, electronics with a
transceiver for telemetry 543 may be disposed proximate to sensor
535 and may communicate the results of the measurements.
[0038] As discussed with respect to FIG. 4, the sensor 535 may
measure volume, pressure, position, and composition of a sample,
and/or may include any of the sensor types found in production
logging tools. Similarly, electronics with a transceiver for
telemetry 543 may communicate directly with a surface operator or
may communicate indirectly by sending short-range transmissions to
a more sophisticated telemetry system. A bulkhead 547 is shown,
which may protect electronics 543 from debris, fluids, or other
materials contained within junk chamber 526.
[0039] By using a system such as the embodiment shown in FIG. 4, or
either of the piston/sensor configurations shown in FIGS. 5A-B, a
surface operator may measure the results of a sampling in realtime.
For example, if a surface operator determines that the reported
sensor measurements do not reflect the desired sample, the operator
may initiate further sampling.
[0040] Thus, a person of ordinary skill in light of the present
disclosure will understand that an embodiment is a sample carrier
including a sample chamber and a sensor for real-time measurement
positioned proximate to the sample chamber.
[0041] The sensor may optionally be a flow meter, such as an
impeller-type flow meter. Additional types of sensors may include a
light sensor, capacitive sensor, a movement sensor, an acceleration
sensor, or a continuity sensor. The sample chamber may optionally
contain one or more pistons, and the sensor may be coupled to a
piston. The one or more pistons may be sampler entry pistons and/or
junk pistons.
[0042] The sampler carrier may optionally include a telemetry
system coupled to the sensor. The telemetry system may
communication directly with a surface receiver or may communicate
indirectly via a second telemetry system located downhole.
[0043] As a person of ordinary skill in light of the present
disclosure will understand, an embodiment is a method for sampling,
including the steps of deploying a sample chamber downhole, filling
the sample chamber with fluid, and performing at least one
measurement of the fluid with a sensor while the sampler is
downhole.
[0044] The sensor may optionally be a flow meter, such as an
impeller-type flow meter. Additional types of sensors may include a
light sensor, capacitive sensor, a movement sensor, an acceleration
sensor, or a continuity sensor. The sample chamber may optionally
contain one or more pistons, and the sensor may be coupled to a
piston. The one or more pistons may be sampler entry pistons and/or
junk pistons.
[0045] The at least one measurement may include the fluid's volume,
pressure, or composition. The method for sampling may optionally
include transmitting the measurement using a telemetry system,
including optionally transmitting the measurement to a second
downhole telemetry system.
[0046] Therefore, the present disclosure is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present disclosure may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present disclosure. Also, the terms in the claims have their
plain, ordinary meaning unless otherwise explicitly and clearly
defined by the patentee. The indefinite articles "a" or "an," as
used in the claims, are defined herein to mean one or more than one
of the element that it introduces. Additionally, the terms
"couple", "coupled", or "coupling" include direct or indirect
coupling through intermediary structures or devices.
* * * * *