U.S. patent application number 13/832655 was filed with the patent office on 2013-12-05 for downhole tools and oil field tubulars having internal sensors for wireless external communication.
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 Paul I. Herman, Paul David Ringgenberg.
Application Number | 20130319102 13/832655 |
Document ID | / |
Family ID | 49668630 |
Filed Date | 2013-12-05 |
United States Patent
Application |
20130319102 |
Kind Code |
A1 |
Ringgenberg; Paul David ; et
al. |
December 5, 2013 |
Downhole Tools and Oil Field Tubulars having Internal Sensors for
Wireless External Communication
Abstract
A downhole tool has a housing assembly with an interior and an
exterior. A sensor is disposed to the interior of the housing
assembly. The sensor is operable to obtain data relative to a fluid
parameter of a fluid disposed within the interior of the housing
assembly and operable to wirelessly transmit the data to a data
acquisition device disposed to the exterior of the housing assembly
responsive to interrogation by the data acquisition device.
Inventors: |
Ringgenberg; Paul David;
(Frisco, TX) ; Herman; Paul I.; (Plano,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
49668630 |
Appl. No.: |
13/832655 |
Filed: |
March 15, 2013 |
Current U.S.
Class: |
73/152.28 |
Current CPC
Class: |
E21B 49/088 20130101;
E21B 49/008 20130101; E21B 49/10 20130101 |
Class at
Publication: |
73/152.28 |
International
Class: |
E21B 49/10 20060101
E21B049/10 |
Foreign Application Data
Date |
Code |
Application Number |
Jun 5, 2012 |
US |
PCT/US2012/040846 |
Claims
1. A downhole tool comprising: a housing assembly having an
interior and an exterior; and a sensor disposed to the interior of
the housing assembly, the sensor operable to obtain data relative
to a fluid parameter of a fluid disposed within the interior of the
housing assembly and operable to wirelessly transmit the data to a
data acquisition device disposed to the exterior of the housing
assembly responsive to interrogation by the data acquisition
device.
2. The downhole tool as recited in claim 1 wherein the interior of
the housing assembly further comprises a fluid chamber of a
downhole tester valve and wherein the sensor is disposed within the
fluid chamber.
3. The downhole tool as recited in claim 2 wherein the downhole
tester valve further comprises: a mandrel assembly disposed within
the housing assembly defining therebetween an operating fluid
chamber, a biasing fluid chamber and a power fluid chamber; a valve
assembly disposed within the housing assembly operable between open
and closed positions; and a piston assembly operably associated
with the valve assembly; wherein, the sensor is disposed within at
least one of the operating fluid chamber, the biasing fluid chamber
and the power fluid chamber.
4. The downhole tool as recited in claim 1 wherein the interior of
the housing assembly further comprises a sampling chamber of a
fluid sampler and wherein the sensor is disposed relative to the
sampling chamber.
5. The downhole tool as recited in claim 4 wherein the fluid
sampler further comprises: an actuator operable to establish a
fluid communication path between the exterior and the interior of
the fluid sampler; a plurality of sampling chambers operable to
receive fluid samples; and a self-contained pressure source in
fluid communication with the sampling chambers operable to
pressurize the fluid samples obtained in the sampling chambers to a
pressure above saturation pressure.
6. The downhole tool as recited in claim 1 wherein the sensor
wirelessly communicates with the data acquisition device by one of
radio frequency transmission and acoustic transmission.
7. The downhole tool as recited in claim 1 wherein the sensor is
powered by at least one of electromagnetic field energy, acoustic
energy, thermal energy and radioactive energy.
8. The downhole tool as recited in claim 1 wherein the fluid
parameter is at least one of pressure and temperature.
9. A downhole tester valve comprising: a housing assembly; a
mandrel assembly disposed within the housing assembly defining
therebetween an operating fluid chamber, a biasing fluid chamber
and a power fluid chamber; a valve assembly disposed within the
housing assembly operable between open and closed positions; a
piston assembly operably associated with the valve assembly; and a
sensor disposed within at least one of the operating fluid chamber,
the biasing fluid chamber and the power fluid chamber, the sensor
operable to obtain data relative to a fluid parameter and operable
to wirelessly transmit the data to a data acquisition device
disposed to the exterior of the housing assembly responsive to
interrogation by the data acquisition device.
10. The downhole tester valve as recited in claim 9 wherein the
sensor wirelessly communicates with the data acquisition device by
one of radio frequency transmission and acoustic transmission.
11. The downhole tester valve as recited in claim 9 wherein the
sensor is powered by at least one of electromagnetic field energy,
acoustic energy, thermal energy and radioactive energy.
12. The downhole tester valve as recited in claim 9 wherein the
fluid parameter is at least one of pressure and temperature.
13. A fluid sampler comprising: a sampling chamber having an
interior and an exterior, the sampling chamber operable to receive
a fluid sample; an actuator operable to establish a fluid
communication path between the exterior and the interior of the
sampling chamber; a self-contained pressure source in fluid
communication with the sampling chamber, the pressure source
operable to pressurize the fluid sample to a pressure above
saturation pressure; and a sensor disposed to the interior of the
sampling chamber, the sensor operable to obtain data relative to a
fluid parameter of the fluid sample and operable to wirelessly
transmit the data to a data acquisition device disposed to the
exterior of the sampling chamber responsive to interrogation by the
data acquisition device.
14. The fluid sampler as recited in claim 13 wherein the sensor
wirelessly communicates with the data acquisition device by one of
radio frequency transmission and acoustic transmission.
15. The fluid sampler as recited in claim 13 wherein the sensor is
powered by at least one of electromagnetic field energy, acoustic
energy, thermal energy and radioactive energy.
16. The fluid sampler as recited in claim 13 wherein the fluid
parameter is at least one of pressure and temperature.
17. An oil field tubular system comprising: a plurality of oil
field tubulars operably coupled together, the oil field tubulars
having an interior and an exterior; and a sensor disposed to the
interior of the oil field tubulars, the sensor operable to obtain
data relative to a fluid parameter of a fluid disposed within the
interior of the oil field tubulars and operable to wirelessly
transmit the data to a data acquisition device disposed to the
exterior of the oil field tubulars responsive to interrogation by
the data acquisition device.
18. The oil field tubular system as recited in claim 17 wherein the
oil field tubulars further comprise a surface flowline.
19. The oil field tubular system as recited in claim 17 wherein the
oil field tubulars further comprise downhole tubulars.
20. The oil field tubular system as recited in claim 17 wherein the
sensor wirelessly communicates with the data acquisition device by
one of radio frequency transmission and acoustic transmission.
21. The oil field tubular system as recited in claim 17 wherein the
sensor is powered by at least one of electromagnetic field energy,
acoustic energy, thermal energy and radioactive energy.
22. The oil field tubular system as recited in claim 17 wherein the
fluid parameter is at least one of pressure and temperature.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit under 35 U.S.C.
.sctn.119 of the filing date of International Application No.
PCT/US2012/040846, filed May 6, 2012. The entire disclosure of this
prior application is incorporated herein by this reference.
TECHNICAL FIELD OF THE INVENTION
[0002] This invention relates, in general, to equipment utilized in
conjunction with operations performed in subterranean wells and, in
particular, to downhole tools and oil field tubulars having
internal sensors that are operable for wireless communication with
an external data acquisition device.
BACKGROUND OF THE INVENTION
[0003] Without limiting the scope of the present invention, its
background will be described with reference to downhole testing
operations, as an example. 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 the fluid contained therein. For example, parameters
such as permeability, porosity, fluid resistivity, temperature,
pressure and saturation pressure 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.
[0004] One type of testing procedure that is commonly performed is
obtaining fluid samples from the formation to, among other things,
determine the composition of the formation fluid. In this
procedure, it is important to obtain samples of the formation fluid
that are representative of the fluid, as it exists in the
formation. In a typical sampling procedure, samples of the
formation fluid may be obtained by lowering a sampling tool having
one or more sampling chambers 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 fluid.
The ports may be actuated in variety of ways such as by electrical,
hydraulic or mechanical methods. Once the ports are opened,
formation fluid enters the sampling tool such that samples of the
formation fluid may be obtained within the sampling chambers. After
the samples have been collected, the sampling tool may be withdrawn
from the wellbore and the formation fluid samples may be
analyzed.
[0005] It has been found, however, that as the fluid samples are
retrieved to the surface, the temperature of the fluid samples may
decrease causing shrinkage of the fluid samples and a reduction in
the pressure of the fluid samples. These changes can cause the
fluid samples to reach or drop below saturation pressure creating
the possibility of asphaltene deposition and flashing of entrained
gasses present in the fluid samples. Once such a process occurs,
the resulting fluid samples are no longer representative of the
fluid present in the formation. Therefore, after a fluid sample has
been retrieved to the surface, it would be desirable to determine
if the integrity of the fluid sample has been maintained. In
addition, it would be desirable to make such a determination
without disturbing the fluid sample.
SUMMARY OF THE INVENTION
[0006] The present invention disclosed herein is directed to
downhole tools and oil field tubulars having internal sensors that
are operable for wireless communication with an external data
acquisition device. For example, a sensor may be disposed in or
relative to a sampling chamber of a sampling tool to obtain
pressure, temperature and/or timing data associated with a fluid
sample. The sensor may then be interrogated on the surface with a
data acquisition device that is external to the sampling tool to
retrieve the data from the sensor without disturbing the fluid
sample.
[0007] In one aspect, the present invention is directed to a
downhole tool. The downhole tool includes a housing assembly having
an interior and an exterior. A sensor is disposed to the interior
of the housing assembly. The sensor is operable to obtain data
relative to a fluid parameter of a fluid disposed within the
interior of the housing assembly and is operable to wirelessly
transmit the data to a data acquisition device disposed to the
exterior of the housing assembly responsive to interrogation by the
data acquisition device.
[0008] In one embodiment, the interior of the housing assembly may
be a fluid chamber of a downhole tester valve and the sensor may be
disposed within the fluid chamber. In this embodiment, the downhole
tester valve may include a mandrel assembly disposed within the
housing assembly defining therebetween an operating fluid chamber,
a biasing fluid chamber and a power fluid chamber. A valve assembly
may be disposed within the housing assembly and may be operable
between open and closed positions. A piston assembly may be
operably associated with the valve assembly. The sensor may be
disposed within at least one of the operating fluid chamber, the
biasing fluid chamber and the power fluid chamber.
[0009] In another embodiment, the interior of the housing assembly
may be a sampling chamber of a fluid sampler and the sensor may be
disposed relative to the sampling chamber. In this embodiment, the
fluid sampler may include an actuator operable to establish a fluid
communication path between the exterior and the interior of the
fluid sampler. A plurality of sampling chambers may be operable to
receive fluid samples. A self-contained pressure source in fluid
communication with the sampling chambers may be operable to
pressurize the fluid samples obtained in the sampling chambers to a
pressure above saturation pressure.
[0010] In certain embodiments, the sensor may wirelessly
communicate with the data acquisition device by one of radio
frequency transmission and acoustic transmission. In some
embodiments, the sensor may be powered by at least one of
electromagnetic field energy, acoustic energy, thermal energy and
radioactive energy. In other embodiments, the fluid parameter may
be at least one of pressure and temperature.
[0011] In another aspect, the present invention is directed to a
downhole tester valve. The downhole tester valve includes a housing
assembly and a mandrel assembly disposed within the housing
assembly defining therebetween an operating fluid chamber, a
biasing fluid chamber and a power fluid chamber. A valve assembly
is disposed within the housing assembly and is operable between
open and closed positions. A piston assembly is operably associated
with the valve assembly. A sensor is disposed within at least one
of the operating fluid chamber, the biasing fluid chamber and the
power fluid chamber. The sensor is operable to obtain data relative
to a fluid parameter and is operable to wirelessly transmit the
data to a data acquisition device disposed to the exterior of the
housing assembly responsive to interrogation by the data
acquisition device.
[0012] In a further aspect, the present invention is directed to a
fluid sampler. The fluid sampler includes a sampling chamber having
an interior and an exterior. The sampling chamber is operable to
receive a fluid sample. An actuator is operable to establish a
fluid communication path between the exterior and the interior of
the sampling chamber. A self-contained pressure source is in fluid
communication with the sampling chamber. The pressure source is
operable to pressurize the fluid sample to a pressure above
saturation pressure. A sensor is disposed to the interior of the
sampling chamber. The sensor is operable to obtain data relative to
a fluid parameter of the fluid sample and is operable to wirelessly
transmit the data to a data acquisition device disposed to the
exterior of the sampling chamber responsive to interrogation by the
data acquisition device.
[0013] In an additional aspect, the present invention is directed
to an oil field tubular system. The oil field tubular system
includes a plurality of oil field tubulars operably coupled
together. The oil field tubulars have an interior and an exterior.
A sensor is disposed to the interior of the oil field tubulars. The
sensor is operable to obtain data relative to a fluid parameter of
a fluid disposed within the interior of the oil field tubulars and
is operable to wirelessly transmit the data to a data acquisition
device disposed to the exterior of the oil field tubulars
responsive to interrogation by the data acquisition device.
[0014] In one embodiment, the oil field tubulars may be a surface
flowline. In another embodiment, the oil field tubulars may be
downhole tubulars.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For a more complete understanding of the features and
advantages of the present invention, reference is now made to the
detailed description of the invention along with the accompanying
figures in which corresponding numerals in the different figures
refer to corresponding parts and in which:
[0016] FIG. 1 is a schematic illustration of an offshore oil and
gas platform during downhole testing and operating a plurality of
internal sensors according to an embodiment of the present
invention;
[0017] FIGS. 2A-G are quarter sectional views of a downhole tester
valve including a plurality of internal sensors according to an
embodiment of the present invention;
[0018] FIGS. 3A-C are block diagrams of internal sensors according
to an embodiment of the present invention;
[0019] FIG. 3D is a block diagram of a data acquisition device
according to an embodiment of the present invention;
[0020] FIG. 4 is a schematic illustration of a fluid sampler system
including a plurality of internal sensors according to an
embodiment of the present invention;
[0021] FIGS. 5A-5F are cross-sectional views of successive axial
sections of a sampling chamber including a plurality of internal
sensors according to an embodiment of the present invention;
[0022] FIG. 6 is a schematic illustration of a surface well testing
facility including a plurality of internal sensors according to an
embodiment of the present invention; and
[0023] FIG. 7 is a schematic illustration of a subsea well
installation including a plurality of internal sensors according to
an embodiment of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0024] While the making and using of various embodiments of the
present invention are discussed in detail below, it should be
appreciated that the present invention provides many applicable
inventive concepts, which can be embodied in a wide variety of
specific contexts. The specific embodiments discussed herein are
merely illustrative of specific ways to make and use the invention
and do not delimit the scope of the invention.
[0025] Referring initially to FIG. 1, an offshore oil and gas
platform operating internal sensors of the present invention during
a well testing operation is schematically illustrated and generally
designated 10. A semi-submersible platform 12 is centered over a
submerged oil and gas formation 14 located below sea floor 16. A
subsea conduit 18 extends from deck 20 of platform 12 to wellhead
installation 22, including blowout preventers 24. Platform 12 has a
hoisting apparatus 26 and a derrick 28 for raising and lowering
pipe strings such as drill string 30. A wellbore 32 has been
drilled through the various earth strata including formation 14.
Wellbore 32 has a casing string 34 installed therein.
[0026] In the illustrated embodiment, a testing string 36 is shown
disposed in wellbore 32, with blowout preventers 24 closed
thereabout. Testing string 36 includes upper drill pipe string 30,
which extends downward from platform 12 to wellhead 22. A
hydraulically operated test tree 38 is positioned between upper
drill pipe string 30 and intermediate pipe string 40. A slip joint
42 may be included in string 40 for enabling proper positioning of
downhole equipment and to compensate for tubing length changes due
to pressure and temperature changes. Below slip joint 42,
intermediate string 40 extends downwardly to a downhole tester
valve 44 including internal sensors of the present invention.
Therebelow, is a lower pipe string 46 that extends to tubing seal
assembly 48, which stabs into packer 50. When set, packer 50
isolates a wellbore annulus 52 from the lower portion of wellbore
54. Packer 50 may be any suitable packer well known to those
skilled in the art. Tubing seal assembly 48 permits testing string
36 to communicate with lower wellbore 54 through a perforated
tailpipe 56. In this manner, formation fluid from formation 14 may
enter lower wellbore 54 through perforations 58 in casing 34 and be
routed into testing string 36.
[0027] After packer 50 is set in wellbore 32, a formation test
controlling the flow of fluid from formation 14 through testing
string 36 may be conducted using variations in pressure affected in
upper annulus 52 by pump 60 and control conduit 62, with associated
relief valves (not shown). Formation pressure, temperature and
recovery time may be measured during the flow test through the use
of the internal sensors of the present invention positioned in
downhole tester valve 44. In addition, internal sensors of the
present invention positioned in intermediate string 40 may be used
to identify the formation of any hydrates during flow testing. In
the illustrated embodiment, real time information about hydrate
formation may be obtained by interrogating the internal sensors
with data acquisition devices 64 that are operably associated with
an umbilical assembly 66 that extends downhole from platform 12.
Preferably, each data acquisition device 64 is located in
communicable proximity to one or more of the internal sensors.
[0028] Even though FIG. 1 depicts the present invention in a
vertical wellbore, it should be understood by those skilled in the
art that the present invention is equally well suited for use in
wellbores having other directional configurations including
horizontal wellbores, deviated wellbores, slanted wells, lateral
wells, multilateral wells and the like. Accordingly, it should be
understood by those skilled in the art that the use of directional
terms such as above, below, upper, lower, upward, downward, uphole,
downhole 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, the uphole direction being toward the surface of the well
and the downhole direction being toward the toe of the well.
[0029] Referring now to FIGS. 2A-2G, therein is depicted an
exemplary embodiment of a downhole tester valve 100 in accordance
with an embodiment of the present invention. Downhole tester valve
100 includes an upper adaptor 102 having threads 104 at its upper
end, whereby downhole tester valve 100 may be secured to drill pipe
or other components within the testing string. Downhole tester
valve 100 has a housing assembly 106 that is secured to upper
adaptor 102 at its upper end. Housing assembly 106 is formed from a
plurality of housing members that are threadedly, sealingly,
weldably or otherwise secured together. Housing assembly 106
includes upper housing member 108, an upper housing connector 110,
an upper intermediate housing member 112, an intermediate housing
connector 114, a lower intermediate housing member 116, a lower
housing connector 118 and a lower housing member 120. At its lower
end, lower housing member 120 is secured to a lower adaptor 122
having threads 124 at its lower end, whereby downhole tester valve
100 may be secured to drill pipe or other components within the
testing string. Even though a particular arrangement of tubulars
has been described and depicted as forming housing assembly 106, it
is understood by those skilled in the art that other arrangements
of tubular components and the like could alternatively be used to
form a housing assembly without departing from the principles of
the present invention.
[0030] Generally positioned within upper housing member 108 is a
valve assembly 126. Valve assembly 126 includes an upper cage
support 128, a ball cage 130, an upper annular seat 132 that is
downwardly biased by one or more springs 134, a pair of operating
pins 136 (only one being visible in FIG. 2B), a rotating ball
member 138, a lower annular seat 140 and a lower cage support 142.
Together, the components of valve assembly 126 cooperate to open
and close the central pathway 144 of downhole tester valve 100 to
selectively allow and prevent fluid flow therethrough.
[0031] Generally positioned within upper intermediate housing
member 112 is a piston assembly 146. Piston assembly 146 includes a
valve operating member 148 that is coupled at its upper end (see
FIG. 2B) to operating pins 136 of valve assembly 126. Piston
assembly 146 also includes a check valve assembly 150, a snap
sleeve 152, a split ring 154 and a collet assembly 156 that is
securably coupled at its lower end to intermediate housing
connector 114. In the illustrated embodiment, check valve assembly
150 is slidably and sealingly positioned between valve operating
member 148 and upper intermediate housing member 112. Check valve
assembly 150 includes a pair of oppositely disposed check valves
158, 160, having a fluid passageway 162 therebetween that may be
referred to as a bypass passageway. Check valves 158, 160 each have
a stem that is extendable outwardly from check valve assembly 150.
In the illustrated embodiment, split ring 154 is received in a
radially reduced section of valve operating member 148. A gap
exists between split ring 154 and the lower surface of check valve
assembly 150 and likewise, gap exists between split ring 154 and an
upper shoulder of a snap sleeve 152. Collet assembly 156 includes a
plurality of collet fingers 164, only one being visible in the FIG.
2D. Each collet finger 164 has a detent 166. Snap sleeve 152
includes a pair of annular grooves 168, 170 that are designed to
selectively and releasably cooperate with detents 166 of collet
fingers 164.
[0032] Generally positioned within lower intermediate housing
member 116 is an upper mandrel 172. In the illustrated embodiment,
upper mandrel 172 is threadedly and sealably coupled to
intermediate housing connector 114 at its upper end and sealably
coupled to lower housing connector 118 at its lower end. Generally
positioned within lower housing member 120 is a lower mandrel 174.
In the illustrated embodiment, lower mandrel 174 is sealably
coupled to lower housing connector 118 at its upper end and
threadedly and sealably coupled to lower adaptor 122 at its lower
end. Together, upper mandrel 172 and lower mandrel 174 may be
referred to herein as a mandrel assembly. Even though a particular
arrangement of tubulars has been described and depicted as forming
the mandrel assembly, it is understood by those skilled in the art
that other arrangements of tubular components and the like could
alternatively be used to form a mandrel assembly without departing
from the principles of the present invention.
[0033] Together, lower intermediate housing member 116 and upper
mandrel 172 define a generally annular operating fluid chamber 176,
which extends between a lower surface of intermediate housing
connector 114 and an upper surface of a floating piston 178 that is
disposed between lower intermediate housing member 116 and upper
mandrel 172. Preferably, operating fluid chamber 176 contains an
operating fluid in the form of a substantially incompressible fluid
such as an oil including hydraulic fluid. Lower intermediate
housing member 116 and upper mandrel 172 also define a generally
annular power fluid chamber 180, which extends between a lower
surface of floating piston 178 and an upper surface of lower
housing connector 118. Power fluid chamber 180 is aligned with one
or more housing ports 182 that extend through lower intermediate
housing member 116 to provide fluid communication with annulus
fluid pressure. In the illustrated embodiment, a housing port 182
is depicted in dashed lines as it is not actually located in the
illustrated cross section but instead is circumferentially offset
from the illustrated view. Together, lower housing member 120 and
lower mandrel 174 define a generally annular biasing fluid chamber
184, which extends between a lower surface of floating piston 186
that is disposed between lower housing member 120 and lower mandrel
174 and an upper surface of lower adaptor 122. Preferably, biasing
fluid chamber 184 contains a biasing fluid in the form of a
compressible fluid such as a gas and more preferably, biasing fluid
chamber 184 contains an inert gas such as nitrogen.
[0034] Downhole tester valve 100 includes an operating fluid
communication network. In valve 100, operating fluid is used not
only to actuate the valve assembly between open and closed
positions but also for rapid charging of the biasing fluid after
shifting the valve assembly from the closed position to the open
position. The operating fluid communication network includes a
plurality of fluid passageways that are formed in various section
of housing assembly 106. In the illustrated embodiment, operating
fluid used to downwardly shift piston assembly 146 and open valve
assembly 126 has a communication path from operating fluid chamber
176 through fluid passageway 188 in intermediate housing connector
114 and fluid passageway 190 in upper intermediate housing member
112. The operating fluid is then operable to act on an upper
surface of check valve assembly 150 of piston assembly 146.
[0035] After the operating fluid has downwardly shifted piston
assembly 146 causing valve assembly 126 to open, the operating
fluid has a communication path through fluid passageway 162 in
check valve assembly 150, through the annular region between upper
intermediate housing member 112 and valve operating member 148,
through fluid passageway 192 in intermediate housing connector 114
(a portion of which is depicted in dashed lines in FIGS. 2D and
2E), through fluid passageway 194 in lower intermediate housing
member 116 (a portion of which is depicted in dashed lines in FIGS.
2E and 2F) and through fluid passageway 196 in lower housing
connector 118 (a portion of which is depicted in dashed lines in
FIG. 2F). The operating fluid is then operable to act on an upper
surface of floating piston 186.
[0036] After the operating fluid has charged the biasing fluid and
annulus pressure is reduced, the operating fluid has a
communication path through fluid passageway 196 in lower housing
connector 118 (a portion of which is depicted in dashed lines in
FIG. 2F), through fluid passageway 194 in lower intermediate
housing member 116 (a portion of which is depicted in dashed lines
in FIGS. 2F and 2E), through fluid passageway 192 in intermediate
housing connector 114 (a portion of which is depicted in dashed
lines in FIGS. 2E and 2D) and through the annular region between
upper intermediate housing member 112 and valve operating member
148. The operating fluid is then operable to act on a lower surface
of check valve assembly 150.
[0037] In addition, the operating fluid communication network of
downhole tester valve 100 includes a metered fluid pathway between
operating fluid chamber 176 and the upper side of floating piston
186. In the illustrated embodiment, a fluid pathway 198 in
intermediate housing connector 114 includes a metering section 200
having a fluid resistance assembly such as an orifice disposed
therein to limit the rate at which operating fluid can pass
therethrough. Fluid pathway 198 is in fluid communication with
fluid pathway 202 in lower intermediate housing member 116 (as best
seen in FIGS. 2E and 2F), which is in fluid communication with
fluid passageway 204 in lower housing connector 118 (as best seen
in FIGS. 2F and 2G). The operating fluid is then operable to act on
an upper surface of floating piston 186.
[0038] In the illustrated embodiment, downhole tester valve 100
includes a plurality of internal sensors 210, 212, 214, 216, 218.
Specifically, internal sensor 210 is positioned in the annular
region between upper intermediate housing member 112 and valve
operating member 148. Internal sensor 212 is positioned in
operation fluid chamber 176. Internal sensor 214 is positioned in
power fluid chamber 180. Internal sensor 216 is positioned in the
metered fluid pathway between metering section 200 and the upper
surface of floating piston 186. Internal sensor 218 is positioned
in biasing fluid chamber 184. As illustrated, internal sensors 210,
212, 214, 216, 218 are positioned in the various pressure regions
of downhole tester valve 100. This configuration can be
particularly beneficial following redressing of downhole tester
valve 100 between downhole testing operations. For example, prior
to using downhole tester valve 100 in a testing operation, it is
desirable to cycle downhole tester valve 100 through its various
positions to determine if downhole tester valve 100 is functioning
properly. One way to determine whether downhole tester valve 100 is
functioning properly is to monitor the pressure transitions in the
various pressure regions and the timing of such pressure
transitions as downhole tester valve 100 is operated through its
various positions. By placing a data acquisition device in
communicable proximity to each of the internal sensors 210, 212,
214, 216, 218 during this functional testing procedure, the
pressure in each of the pressure regions of downhole tester valve
100 can be monitor. Importantly, this pressure analysis does not
impact the operation of downhole tester valve 100 nor does it
require physically attaching gauges or monitors to downhole tester
valve 100 as internal sensors 210, 212, 214, 216, 218 are operable
to wirelessly communicate with the data acquisition device or
devices.
[0039] Referring next to FIGS. 3A-3C, therein are depicted block
diagrams of sensor assemblies that may be used as the internal
sensors described above and the internal sensors described below.
Sensor assembly 300, of FIG. 3A, includes a sensor 302 and a
transceiver 304. For example, sensor 302 may be a temperature
gauge, a pressure gauge or other fluid parameter gauge. In the
illustrated embodiment, transceiver 304 using a wireless,
noncontact means, such as radio frequency electromagnetic fields,
to transfer data obtained by sensor 302 to a data acquisition
device that interrogates sensor assembly 300. In this embodiment,
sensor assembly 300 does not require a battery as sensor 302 and
transceiver 304 are powered by the electromagnetic fields generated
by the data acquisition device that is reading the data. In this
configuration, the data relative to the fluid parameter being
measured is preferably obtained at the time the data acquisition
device interrogates sensor assembly 300. In other words, the data
acquisition device generates an electromagnetic field that is
received by a radio frequency electromagnetic field coil of sensor
302, transceiver 304 or both. This prompts sensor 302 to obtain the
desired data, which is returned to the data acquisition device by
transceiver 304.
[0040] Sensor assembly 310, of FIG. 3B, includes a sensor 312, a
transceiver 314 and a charger 316. For example, sensor 312 may be a
temperature gauge, a pressure gauge or other fluid parameter gauge.
Transceiver 314 may generate acoustic signals that are read by the
data acquisition device. In this embodiment, sensor assembly 310
does not require a battery as power for sensor 312 and transceiver
314 is provided by charger 316. Charger 316 is powered by the data
acquisition device. For example, charger 316 may be charged
responsive to energy generated by the data acquisition device in
the form of acoustic energy, thermal energy, radioactive energy or
the like. Charger 316 converts the energy to electrical energy to
operate sensor 312 and transceiver 314. In this configuration, the
data relative to the fluid parameter being measured is preferably
obtained at the time the data acquisition device interrogates
sensor assembly 310. In other words, the data acquisition device
generates energy that is received by charger 316 and converted to
electricity. This prompts sensor 312 to obtain the desired data,
which is returned to the data acquisition device by transceiver
314.
[0041] Sensor assembly 320, of FIG. 3C, includes a sensor 322 and a
transceiver 324. Sensor 322 may be a temperature gauge, a pressure
gauge or other fluid parameter gauge. Transceiver 324 may
communicate with a data acquisition device via radio frequency
electromagnetic fields, acoustic signals or the like. In this
embodiment, sensor assembly 320 is powered by a battery 326. In
addition, sensor assembly 320 has a microprocessor 328 associated
therewith providing command and control over sensor assembly 320.
Likewise, sensor assembly 320 includes a memory 330, which provides
for storing information for later transmission, if desired. In the
illustrated embodiment, sensor assembly 320 is operable to obtain
data regarding fluid parameters when sensor assembly 320 is remote
from the data acquisition device. For example, sensor assembly 320
may be installed in a downhole testing tool, such as the downhole
tester valve described above, and used to obtain fluid parameter
data during a downhole testing operation. Upon retrieval to the
surface, sensor assembly 320 may be interrogated with a data
acquisition device to receive the stored data via a wireless
communication means. For example, pressure, temperature and time
data may be stored throughout a testing operation and during
retrieval of the testing tools such that pressure and temperature
profiles for an entire testing operation may be analyzed.
[0042] Referring next to FIG. 3D, therein is depicted a block
diagram of a data acquisition device that is generally designated
340. Data acquisition device 340 includes a microprocessor 342 that
provides command and control for data acquisition device 340. Data
acquisition device 340 also has a transceiver 344 for wireless
communication with a transceiver of a sensor assembly. For example,
transceiver 344 may communicate with sensor assembly 300 discussed
above, using radio frequency electromagnetic fields. Alternatively,
transceiver 344 may communicate with sensor assembly 310 discussed
above, using acoustic signals. In the illustrated embodiment, data
acquisition device 340 includes an energy generator 346. For
example, energy generator 346 may generate energy in the form of
acoustic energy, thermal energy, radioactive energy or the like
which may harnessed by a sensor assembly including charger 316.
Preferably, data acquisition device 340 is a hand held device that
has an internal power source such as a battery 348. Data
acquisition device 340 further includes memory 350 for storing data
received from a sensor assembly.
[0043] Referring next to FIG. 4, therein is representatively
illustrated a fluid sampler system 400 operating internal sensors
of the present invention. A fluid sampler 402 is being run in a
wellbore 404 that is depicted as having a casing string 406 secured
therein with cement 408. Although wellbore 404 is depicted as being
cased and cemented, it could alternatively be uncased or open hole.
Fluid sampler 402 includes a cable connector 410 that enables fluid
sampler 402 to be coupled to or operably associated with a wireline
conveyance 412 that is used to run, retrieve and position fluid
sampler 402 in wellbore 404. Wireline conveyance 412 may be a
single strand or multistrand wire, cable or braided line, which may
be referred to as a slickline or may include one or more electric
conductors, which may be referred to as an e-line or electric line.
Even though fluid sampler 402 is depicted as being connected
directly to cable connector 410, those skilled in the art the
understand that fluid sampler 402 could alternatively be coupled
within a larger tool string that is being positioned within
wellbore 404 via wireline conveyance 412 or could be convey via
coiled tubing, jointed tubing or the like.
[0044] In the illustrated embodiment, fluid sampler 402 includes an
actuator assembly 414, a sampler assembly 416 and a self-contained
pressure source assembly 418. Preferably, sampler assembly 416
includes multiple sampling chambers, such as two, three or four
sampling chambers. In coiled tubing or jointed tubing conveyed
embodiments, sampler assembly 416 may include nine or more sampling
chambers. In order to route the fluid samples into the desired
sampling chamber, fluid sampler 402 includes a manifold assembly
420 positioned between actuator assembly 414 and sampler assembly
416. Valving or other fluid flow control circuitry within manifold
assembly 420 may be used to enable fluid samples to be taken in all
of the sampling chambers simultaneously or to allow fluid samples
to be sequentially taken into the various sampling chambers. In
slickline conveyed embodiments, actuator assembly 414 preferably
includes timing circuitry such as a mechanical or electrical clock,
which is used to determine when the fluid sample or samples will be
taken. Alternatively, a pressure signal or other wireless input
signal could be used to initiate operation of actuator assembly
414. In electric line conveyed embodiments, actuator assembly 414
preferably includes electrical circuitry operable to communicate
with surface systems via the electric line to initiate operation of
actuator assembly 414.
[0045] After the fluid samples are taken, in order to route
pressure into the desired sampling chamber, fluid sampler 402
includes a manifold assembly 422 positioned between sampler
assembly 416 and self-contained pressure source 418. Self-contained
pressure source 418 may include one or more pressure chambers that
initially contain a pressurized fluid, such as a compressed gas or
liquid, and preferably contain compressed nitrogen at between about
10,000 psi and 20,000 psi. Those skilled in the art will understand
that other fluids or combinations of fluids and/or other pressures
both higher and lower could be used, if desired. Depending on the
number of sampling chambers and the number of pressure chambers,
valving or other fluid flow control circuitry within manifold
assembly 422 may be operated such that self-contained pressure
source 418 serves as a common pressure source to simultaneously
pressurize all sampling chambers or may be operated such that
self-contained pressure source 418 independently pressurizes
certain sampling chambers sequentially. In the case of multiple
sampling chambers and multiple pressure chambers, manifold assembly
422 may be operated such that pressure from certain pressure
chambers of self-contained pressure source 418 is routed to certain
sampling chambers. As described below, internal sensors of the
present invention positioned in the sampling chambers may be used
to quickly determine whether sample integrity has been maintained
during the testing and retrieval of the fluid samples. For example,
pressure and temperature data for the fluid samples may be obtained
upon retrieval to the surface from the internal sensors using a
data acquisition device placed in communicable proximity to the
internal sensors.
[0046] Referring now to FIGS. 5A-5F a fluid sampling chamber for
use in a fluid sampler that embodies principles of the present
invention is representatively illustrated and generally designated
500. Preferably, one or more of sampling chambers 500 are
positioned in a sampler assembly 416 that is coupled to an actuator
assembly 420 and a self-contained pressure source assembly 418 as
described above.
[0047] As described more fully below, a passage 510 in an upper
portion of sampling chamber 500 (see FIG. 5A) is placed in
communication with the exterior of fluid sampler 402 when the fluid
sampling operation is initiated. Passage 510 is in communication
with a sample chamber 514 via a check valve 516. Check valve 516
permits fluid to flow from passage 510 into sample chamber 514, but
prevents fluid from escaping from sample chamber 514 to passage
510.
[0048] A debris trap piston 518 is disposed within housing assembly
502 and separates sample chamber 514 from a meter fluid chamber
520. When a fluid sample is received in sample chamber 514, debris
trap piston 518 is displaced downwardly relative to housing
assembly 502 to expand sample chamber 514. Prior to such downward
displacement of debris trap piston 518, however, fluid flows
through sample chamber 514 and passageway 522 of piston 518 into
debris chamber 526 of debris trap piston 518. The fluid received in
debris chamber 526 is prevented from escaping back into sample
chamber 514 due to the relative cross sectional areas of passageway
522 and debris chamber 526 as well as the pressure maintained on
debris chamber 526 from sample chamber 514 via passageway 522. An
optional check valve (not pictured) may be disposed within
passageway 522 if desired. In this manner, the fluid initially
received into sample chamber 514 is trapped in debris chamber 526.
Debris chamber 526 thus permits this initially received fluid to be
isolated from the fluid sample later received in sample chamber
514. Debris trap piston 518 includes a magnetic locator 524 used as
a reference to determine the level of displacement of debris trap
piston 518 and thus the volume within sample chamber 514 after a
sample has been obtained.
[0049] Meter fluid chamber 520 initially contains a metering fluid,
such as a hydraulic fluid, silicone oil or the like. A flow
restrictor 534 and a check valve 536 control flow between chamber
520 and an atmospheric chamber 538 that initially contains a gas at
a relatively low pressure such as air at atmospheric pressure. A
collapsible piston assembly 540 includes a prong 542, which
initially maintains check valve 544 off seat, so that flow in both
directions is permitted through check valve 544 between chambers
520, 538. When elevated pressure is applied to chamber 538,
however, as described more fully below, piston assembly 540
collapses axially, and prong 542 will no longer maintain check
valve 544 off seat, thereby preventing flow from chamber 520 to
chamber 538.
[0050] A piston 546 disposed within housing 502 separates chamber
538 from a longitudinally extending atmospheric chamber 548 that
initially contains a gas at a relatively low pressure such as air
at atmospheric pressure. Piston 546 includes a magnetic locator 547
used as a reference to determine the level of displacement of
piston 546 and thus the volume within chamber 538 after a sample
has been obtained. Piston 546 included a piercing assembly 550 at
its lower end. In the illustrated embodiment, piercing assembly 550
is spring mounted within piston 546 and includes a needle 554.
Needle 554 has a sharp point at its lower end and may have a smooth
outer surface or may have an outer surface that is fluted,
channeled, knurled or otherwise irregular. As discussed more fully
below, needle 554 is used to actuate the pressure delivery
subsystem of the fluid sampler when piston 546 is sufficiently
displaced relative to housing assembly 502.
[0051] Below atmospheric chamber 548 and disposed within the
longitudinal passageway of housing assembly 502 is a valving
assembly 556. Valving assembly 556 includes a pressure disk holder
558 that receives a pressure disk therein that is depicted as
rupture disk 560, however, other types of pressure disks that
provide a seal, such as a metal-to-metal seal, with pressure disk
holder 558 could also be used including a pressure membrane or
other piercable member. Rupture disk 560 is held within pressure
disk holder 558 by hold down ring 562 and gland 564 that is
threadably coupled to pressure disk holder 558. Valving assembly
556 also includes a check valve 566. Valving assembly 556 initially
prevents communication between chamber 548 and a passage 580 in a
lower portion of sampling chamber 500. After actuation of the
pressure delivery subsystem by needle 554, check valve 566 permits
fluid flow from passage 580 to chamber 548, but prevents fluid flow
from chamber 548 to passage 580. Preferably, passageway 580 is
placed in fluid communication with pressure from the self-contained
pressure source via the manifold therebetween.
[0052] In the illustrated embodiment, sampling chamber 500 includes
a plurality of internal sensors 582, 584, 586, 588. Specifically,
internal sensor 582 is positioned in sample chamber 514. Internal
sensor 584 is positioned in metering fluid chamber 520. Internal
sensor 586 is positioned in atmospheric chamber 538. Internal
sensor 588 is positioned in atmospheric chamber 548. As
illustrated, internal sensors 582, 584, 586, 588 are positioned in
the various pressure regions of sampling chamber 500.
[0053] In operation, once the fluid sampler has been run downhole
via the wireline conveyance to the desired location and is in its
operable configuration, a fluid sample can be obtained into one or
more of the sample chambers 514 by operating the actuator. Fluid
enters passage 510 in the upper portion of each of the desired
sampling chambers 500. For clarity, the operation of only one of
the sampling chambers 500 after receipt of a fluid sample therein
is described below. The fluid sample flows from passage 510 through
check valve 516 to sample chamber 514. It is noted that check valve
516 may include a restrictor pin 568 to prevent excessive travel of
ball member 570 and over compression or recoil of spiral wound
compression spring 572. An initial volume of the fluid sample is
trapped in debris chamber 526 of piston 518 as described above.
Downward displacement of piston 518 is slowed by the metering fluid
in chamber 520 flowing through restrictor 534. This prevents
pressure in the fluid sample received in sample chamber 514 from
dropping below its saturation pressure.
[0054] As piston 518 displaces downward, the metering fluid in
chamber 520 flows through restrictor 534 into chamber 538. At this
point, prong 542 maintains check valve 544 off seat. The metering
fluid received in chamber 538 causes piston 546 to displace
downwardly. Eventually, needle 554 pierces rupture disk 560, which
actuates valving assembly 556. Actuation of valving assembly 556
permits pressure from the self-contained pressure source to be
applied to chamber 548. Specifically, once rupture disk 560 is
pierced, the pressure from the self-contained pressure source
passes through passage 580 and valving assembly 556 including
moving check valve 566 off seat. In the illustrated embodiment, a
restrictor pin 574 prevents excessive travel of check valve 566 and
over compression or recoil of spiral wound compression spring 576.
Pressurization of chamber 548 also results in pressure being
applied to chambers 538, 520 and thus to sample chamber 514.
[0055] When the pressure from the self-contained pressure source is
applied to chamber 538, pins 578 are sheared allowing piston
assembly 540 to collapse such that prong 542 no longer maintains
check valve 544 off seat. Check valve 544 then prevents pressure
from escaping from chamber 520 and sample chamber 514. Check valve
516 also prevents escape of pressure from sample chamber 514. In
this manner, the fluid sample received in sample chamber 514 is
pressurized such that the fluid sample may be retrieved to the
surface without degradation by maintaining the pressure of the
fluid sample above its saturation pressure, thereby obtaining a
fluid sample that is representative of the fluids present in the
formation. Upon retrieval to the surface, the internal sensors 582,
584, 586, 588 may be interrogated by a data acquisition device to
determine the current pressures in the various pressure regions. If
suitable pressure data is provided from internal sensors 582, 584,
586, 588, the sample integrity has likely been maintained. If the
pressure data provided from internal sensors 582, 584, 586, 588 is
not suitable, another sampling run may immediately be made into the
wellbore. Alternatively or additionally, in certain embodiments,
pressure and/or temperature profile data may be obtained from
internal sensors 582, 584, 586, 588.
[0056] Referring next to FIG. 6, therein is depicted a surface well
testing facility operating internal sensors of the present
invention that is schematically illustrated and generally
designated 600. Surface well testing facility 600 includes a
wellhead 602 and a surface test tree 604 connected to wellhead 602.
Surface test tree 604 includes a plurality of valves for
controlling fluid flow into or out of the well. A flow line 606
extends from surface test tree 604 to transport a multiphase well
fluid produced from the well for processing. In the illustrated
embodiment, flow line 606 includes a heater 608. In addition, flow
line 606 includes a choke manifold 610 which includes one or more
valves that are used to accurately throttle the flow from the well
so that the fluid pressure downstream from choke manifold 610 is
reduced to a desired pressure.
[0057] Downstream from choke manifold 610 is a separator 612 in
which the various constituents of the well fluid are separated. In
the illustrated embodiment, separator 612 is depicted as a system
for handling a three-phase fluid; namely, a fluid having a gas
constituent, an oil constituent and a water constituent. Separator
612 includes a gas line 614 discharging from the top of separator
612, an oil line 616 discharging from an intermediate portion of
separator 612 and a water line 618 discharging near the bottom of
separator 612. An orifice-type gas flow meter 620 is disposed in
gas line 614, a volumetric oil flow meter 622 is disposed in oil
line 616 and a volumetric water flow meter 624 is disposed in water
line 618. Preferably, water line 618 is directed to a tank or other
facility in which the water may be treated for later disposal.
[0058] In the illustrated embodiment, the oil constituent in oil
line 616 is directed to an oil burner 626. Preferably, oil burner
626 is positioned at a distal end of a boom. One or more flow
control component such as pumps, valves, regulators and the like
(not pictured), may be positioned in oil line 616. In the
illustrated embodiment, the gas constituent in gas line 614 is
directed to a flare 628 through which the gas constituent is flared
to the atmosphere. Preferably, gas line 616 includes flow control
components such as one or more valves, regulators and the like (not
pictured).
[0059] Typically, the surface well testing facility is a temporary
facility that is used only during the well testing phase. As such,
the tubulars used to transport the formation fluid throughout the
facility are commonly assembled, disassembled and reassembled
numerous times resulting in the tubular system having a potentially
irregular flow path which may tend to get plugged by the dirty
fluid that is initially produced in a well testing operation. Use
of internal sensors (not visible in FIG. 6) and one or more data
acquisition devices makes locating a blockage in the tubular system
safer and more efficient. In the illustrated embodiment, a
plurality of data acquisition devices 630 have been positioned in
communicative proximity to internal sensors disposed within flow
line 606. As discussed above, the internal sensors may be
interrogated by data acquisition devices 630 to obtain data
gathered by the internal sensors. In the illustrated example, if
the flow rate into separator 612 declines, the various internal
sensors location along flow line 606 may be interrogated to
determine the location of a pressure drop and therefore the
blockage in flow line 606.
[0060] Referring next to FIG. 7, therein is depicted a subsea well
installation operating internal sensors of the present invention
that is schematically illustrated and generally designated 700.
Subsea well installation 700 includes a subsea test tree 702 that
is positioned within a blowout preventer (BOP) stack 704 installed
on the ocean floor. BOP stack 704 includes two pipe rams 706 and
two shear rams 708 that are configured and controlled according to
conventional practice. Subsea test tree 702 has been lowered into
BOP stack 704 through a tubular riser 710 extending upwardly
therefrom. A fluted wedge 712 attached below subsea test tree 702
permits accurate positioned of subsea test tree 702 within BOP
stack 704. In the illustrated embodiment, a retainer valve 714 is
attached above subsea test tree 702 and remains within riser 710
when subsea test tree 702 is positioned within BOP stack 704.
[0061] Subsea test tree 702 includes a latch head assembly 716, a
ramlock assembly 718 and a valve assembly 720. Ramlock assembly 718
is interconnected axially between latch head assembly 716 and valve
assembly 720 to axially separate these components from one another.
As used herein, the term ramlock assembly is used to indicate one
or more members, which are configured in such a way as to permit
sealing engagement with conventional pipe rams. For example, as
shown in FIG. 7, ramlock assembly 718 is shown in sealing
engagement with both of the pipe rams 706 as pipe rams 706 have
been previously actuated to extend inwardly to engage ramlock
assembly 718. As illustrated, latch head assembly 716 and valve
assembly 720 have diameters which are greater than that which may
be sealingly engaged by conventional pipe rams, therefore, ramlock
assembly 718 provides for sealing engagement of the pipe rams 706
between latch head assembly 716 and valve assembly 720.
[0062] Valve assembly 720 is positioned between pipe rams 706 and
wedge 712 such that when pipe rams 706 are closed about ramlock
assembly 718, valve assembly 720 is isolated from an annulus 722
above pipe rams 706. Pipe rams 706 isolate annulus 722 from an
annulus 724 below pipe rams 706 and surrounding valve assembly 720.
As used herein, the term valve assembly is used to indicate an
assembly including one or more valves, which are operative to
selectively permit and prevent fluid flow through a flow passage
formed through the valve assembly. For example, valve assembly 720
of FIG. 7 includes two safety valves (not visible), which are
operative to control fluid flow through a tubular string 726.
Retainer valve 714, latch head assembly 716, ramlock assembly 718
and valve assembly 720 are all interconnected within and are part
of tubular string 726. Tubular string 726 has a flow passage formed
therethrough and the valves in valve assembly 720 may be actuated
to permit or prevent fluid flow therethrough.
[0063] As used herein, the term latch head assembly is used to
indicate one or more members which permit decoupling of one portion
of tubular string 726 from another portion thereof. For example, in
the representatively illustrated subsea test tree 702, latch head
assembly 716 may be actuated to decouple an upper portion 728 of
tubular string 726 from a lower portion 730 of tubular string 726.
Thus, in the event of an emergency, pipe rams 706 may be closed on
ramlock assembly 718, the valves in valve assembly 720 may be
closed, and upper portion 728 of tubular string 726 may be
retrieved, or otherwise displaced away from lower portion 730.
Closure of pipe rams 706 on ramlock assembly 718 and closure of the
valves in valve assembly 720 isolates the well therebelow from
fluid communication with riser 710. Actuation of retainer valve
714, latch head assembly 716 and valve assembly 720 is controlled
via an umbilical assembly 732 that may include one or more
hydraulic lines, electric lines, fiber optic lines and the
like.
[0064] A lower portion of tubular string 726 extends into well 734.
Internal sensors (not pictured) of the present invention positioned
in tubular string 726 may be used to identify the formation of any
hydrates during flow testing. In the illustrated embodiment, real
time information about hydrate formation may be obtained by
interrogating the internal sensors with data acquisition devices
736 that are operably associated with umbilical assembly 732.
Preferably, each data acquisition devices 736 is located in
communicable proximity to one or more of the internal sensors. In
the illustrated embodiment, data acquisition device 736 are
depicted as being positioned proximate the connection between
joints of tubular string 726 as the internal sensors have been
positioned in the interior of the connections.
[0065] While this invention has been described with reference to
illustrative embodiments, this description is not intended to be
construed in a limiting sense. Various modifications and
combinations of the illustrative embodiments as well as other
embodiments of the invention will be apparent to persons skilled in
the art upon reference to the description. It is therefore,
intended that the appended claims encompass any such modifications
or embodiments.
* * * * *