U.S. patent application number 13/559133 was filed with the patent office on 2014-01-30 for systems and methods for reducing pvt effects during pressure testing of a wellbore fluid containment system.
This patent application is currently assigned to INTELLISERV, LLC. The applicant listed for this patent is Daniel Marco VEENINGEN. Invention is credited to Daniel Marco VEENINGEN.
Application Number | 20140027113 13/559133 |
Document ID | / |
Family ID | 49993740 |
Filed Date | 2014-01-30 |
United States Patent
Application |
20140027113 |
Kind Code |
A1 |
VEENINGEN; Daniel Marco |
January 30, 2014 |
SYSTEMS AND METHODS FOR REDUCING PVT EFFECTS DURING PRESSURE
TESTING OF A WELLBORE FLUID CONTAINMENT SYSTEM
Abstract
A system for pressure testing a component of a well system
includes a tubular member extending into a wellbore. The tubular
member has a fluid passageway and one or more nodes that are
configured to measure fluid pressure. The system also includes a
heat exchanger configured to cool a fluid passing therethrough.
Inventors: |
VEENINGEN; Daniel Marco;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
VEENINGEN; Daniel Marco |
Houston |
TX |
US |
|
|
Assignee: |
INTELLISERV, LLC
Houston
TX
|
Family ID: |
49993740 |
Appl. No.: |
13/559133 |
Filed: |
July 26, 2012 |
Current U.S.
Class: |
166/250.08 ;
166/250.01; 166/57 |
Current CPC
Class: |
E21B 47/117 20200501;
E21B 47/06 20130101; E21B 33/06 20130101; E21B 36/001 20130101 |
Class at
Publication: |
166/250.08 ;
166/57; 166/250.01 |
International
Class: |
E21B 47/06 20120101
E21B047/06; E21B 47/117 20120101 E21B047/117; E21B 47/001 20120101
E21B047/001 |
Claims
1. A system for pressure testing a component of a well system
comprising: a wellbore penetrating a subterranean formation; a
tubular member extending into the wellbore having a first fluid
passageway; one or more nodes that are configured to measure fluid
pressure and are coupled to the tubular member; a heat exchanger
having a second fluid passageway and is configured to cool a fluid
passing through the second fluid passageway; and a fluid flowpath
that comprises at least a portion of the first fluid passageway and
at least a portion of the second fluid passageway.
2. The system of claim 1, wherein the tubular member comprises a
drillstring.
3. The system of claim 1, wherein the tubular member comprises a
production riser.
4. The system of claim 1, wherein the heat exchanger is a shell and
tube heat exchanger.
5. The system of claim 1, further comprising a first volume of
fluid in the fluid flowpath having a first pressure.
6. The system of claim 1, wherein the fluid flowpath further
comprises an annulus surrounding the tubular member.
7. The system of claim 1, wherein the fluid flowpath further
comprises the wellbore of the system.
8. The system of claim 5, further comprising a pump in fluid
communication with the fluid flowpath and configured to pressurize
fluid in the fluid flowpath to produce a pressurized fluid having a
second pressure that is greater than the first pressure of the
first of fluid.
9. The system of claim 8, wherein the temperature of the first
volume of fluid is substantially equal to the temperature of the
pressurized fluid.
10. The system of claim 8, wherein the temperature of the
pressurized fluid is less than the temperature of the first volume
of fluid.
11. The system of claim 1, further comprising: a test plug disposed
within the tubular member; a ram of a blowout preventer disposed at
least partially within the tubular member; and a sealed chamber
formed by the tubular member, the ram and the test plug; wherein
one of the one or more nodes is disposed within the sealed
chamber.
12. The system of claim 8, wherein the pressurized fluid comprises
a first portion and a second portion, and wherein the first portion
of the pressurized fluid is cooled to a first temperature and the
second portion of the pressurized fluid is cooled to a second
temperature.
13. The system of claim 12, wherein the first temperature is
different than the second temperature.
14. A method for pressure testing a well system comprising: cooling
a first volume of fluid having a first pressure to produce a cooled
fluid; flowing the cooled fluid into a closeable chamber of the
well system; shutting in the chamber; and measuring a pressure in
the chamber using nodes distributed within the chamber.
15. The method of claim 14, wherein flowing the cooled fluid into
the chamber comprises pressurizing the cooled fluid to produce a
pressurized fluid having a second pressure that is greater than the
first pressure of the first volume of fluid.
16. The method of claim 14, transmitting the pressure measurement
to a remote location.
17. The method of claim 15, wherein pressurizing the cooled fluid
to produce a pressurized fluid comprises pressurizing the cooled
fluid to a temperature that is substantially equal to the
temperature of the first volume of fluid.
18. The method of claim 15, wherein pressurizing the cooled fluid
to produce a pressurized fluid comprises pressurizing the cooled
fluid to a temperature that is less than the temperature of the
first volume of fluid.
19. The method of claim 14, further comprising determining the
presence of a leak within the closeable chamber by monitoring the
pressure measurement.
20. The method of claim 14, further comprising filling the
closeable chamber with the cooled fluid.
21. The method of claim 14 further comprising transmitting the
measured pressure to a remote location.
22. The method of claim 14 wherein the measured pressure is
transmitted via a network comprising wired drill pipe.
23. The method of claim 14, wherein cooling the fluid to produce
the cooled fluid comprises flowing the fluid through a heat
exchanger.
24. The method of claim 14, wherein the closeable chamber comprises
an annulus surrounding a tubular body.
25. The method of claim 14, wherein the closeable chamber comprises
a wellbore.
26. The method of claim 14, wherein cooling the fluid to produce a
cooled fluid comprises cooling a first portion of the fluid to
produce a first cooled portion of fluid and cooling a second
portion of the fluid to produce a second cooled portion of
fluid.
27. The method of claim 26, wherein the first cooled portion of
fluid is cooled to a temperature that is higher than the
temperature of the second cooled portion of fluid.
28. The method of claim 14, wherein: flowing the cooled fluid into
the chamber comprises pressurizing the cooled fluid to produce a
pressurized fluid; wherein cooling the fluid to produce a cooled
fluid comprises cooling a first portion of the fluid to a first
temperature and cooling a second portion of the fluid to a second
temperature that is different than the first temperature.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
BACKGROUND
[0003] 1. Field of the Disclosure
[0004] The disclosure relates generally to systems and methods for
conducting a pressure test of wellbore system equipment. More
particularly, the disclosure relates to systems and methods for
mitigating pressure-volume-temperature (PVT) effects that take
place while pressure testing wellbore fluid containment system
equipment such as blowout preventers (BOPs), choke and kill lines,
wellhead hangers, casing, liner and liner hangers, tubing hangers,
completions and other equipment.
[0005] 2. Background of the Technology
[0006] In drilling for oil and gas from a hydrocarbon producing
well, a well or well system is provided that includes a drilling
rig with a riser section and a drill string used to convey drilling
fluid down the drill string and through a wellhead to a drill bit
disposed within a wellbore of a formation. The fluid recirculates
from the drill bit back to the drilling rig via an annulus formed
between the drill string and walls of the wellbore, and via the
annulus formed between the drill string and the riser section that
encircles it. A wellbore or formation fluid influx, also called a
"kick", can cause an unstable and unsafe condition at the drilling
rig. When a kick is detected, a fluid containment system of the
well system may be actuated and steps may be taken to "kill" the
well and regain control. The fluid containment system includes all
critical sealing points, including the BOP and its associated rams,
the choke and kill lines and their associated valves, the choke and
kill manifolds, an internal BOP (IBOP).
[0007] Due to the criticality of the functional operation of the
fluid containment system with regard to containing and managing
fluid pressurizations within the well system, periodic testing of
each component (e.g., BOP, choke and kill lines, etc.) and each
sealing element of the fluid containment system is important. Per
current U.S. federal regulations, pressure testing of the fluid
containment system must be conducted upon installation and before
14 days have elapsed since the last BOP pressure test. For
instance, each ram of the BOP and each valve of the choke and kill
lines must be individually pressure tested to properly comply with
current regulations. Low and high pressure tests must be conducted
for each individual component, and each component and sealing
element must demonstrate that it holds a reasonably stable
pressure. For instance, in practice a pressure decay rate of 4
pounds per square inch (psi) per minute or less is seen as
reasonably stable.
[0008] Even though a fluid containment system component need only
demonstrate pressure holding capability for five minutes to pass a
presently-required pressure test, conducting the individual tests
often take much longer due to PVT effects that take place due to
the pressurizing of the test fluid. Specifically, for fluids (e.g.,
drilling fluid, completion fluid, etc.), an increase in pressure of
the fluid will result in an increase of temperature of the fluid,
while a decrease in temperature of the fluid will correspondingly
result in a decrease in pressure of the fluid. The temperature of
the testing fluid increases during pressurization due to heat
generated by friction during the pumping of the fluid by a
cementing unit, mud pump, or either types of high pressure pumps.
For instance, heat generated by pistons of a triplex pump as they
reciprocate may be transferred to the pressurized testing fluid.
For this reason, testing fluid pumped into the fluid containment
system may feature a larger temperature increase than fluid already
disposed in the system, which is pressurized by the injection into
the system of the pumped-in testing fluid. Referring to FIG. 1,
graph 200 illustrates fluid pressures in relation to time at
different positions along a vertically-oriented subsea drill string
during a pressure test. Pressure curve 110 illustrates the fluid
pressure at a point within the drill string near the sea floor,
with curves 130, 120 and 110 illustrating fluid pressure at
progressively shallower points along the drill string, with curve
110 illustrating fluid pressure at the shallowest point, near the
surface of the water. Due to being located at different vertical
depths along the drill string, curve 110 is at the highest
pressure, while curve 140 is at the lowest pressure of the curves.
As shown in FIG. 1, the pressure test can be divided into three
phases: a pumping phase (112, 122, 132 and 142), a shut-in phase
(114, 124, 134 and 144) and a depressurization phase (116, 126, 136
and 146). The pumping phase takes places when testing fluid is
pumped into the well system in order to pressurize the fluid
containment system. Testing fluid may be pumped into the drill
string by a cementing unit or mud pump disposed at the drilling
rig. Once the well system has been pressurized to the testing
pressure, pumping ceases and the well system is shut-in, such that
a portion of the well system containing the system components to be
tested is isolated from the outside environment. Shut-in phases
114, 124, 134 and 144 have a beginning (114a, 124a, 134a and 144a)
and an ending (114b, 124b, 134b and 144b). As shown by FIG. 1, the
pressure at the beginning 114a, 124a, 134a and 144a exceeds the
pressure at the end 114b, 124b, 134b and 144 of the shut-in phase.
Further, the difference in pressure between beginning 144a and
ending 144b is greater than the difference in pressures between
114a and 114b, due to curve 140 being at a shallower point along
the drill string. Also, in this pressure test, shut-in phases
include a pressurization point (114c, 124c, 134c and 144c) where
additional testing fluid is pumped into the well system to slightly
increase the pressure within the system. Additional fluid may be
pumped in during the shut-in phase to raise the pressure within the
well system to a level similar to that existing near the beginning
of the tests, at points 114a, 124a, 134a and 144a.
[0009] Referring to FIG. 2, graph 200 illustrates fluid
temperatures in relation to time at different positions along the
vertically oriented subsea drill string during a pressure test.
Temperature curve 210 is generated by temperature sensors
positioned at the same vertical position along the drill string as
the pressure sensors generating pressure curve 110, curve 220 is
generated by temperature sensors positioned at the same position as
curve 120, etc. Temperature curve 240, at the shallowest position
along the drill string, displays the greatest downward slope of the
curves 210, 220, 230 and 240. The greater slope of temperature
curve 240 is due to being in closer proximity to the testing fluid
that has been pumped into the well system for the purpose of
pressurization. For instance, heat from the testing fluid pumped
into the well system during the pumping phase may transfer to
proximal fluid at the position of temperature curve 240, resulting
in a greater difference in temperature between testing fluid within
the drill string at the position of sensors generating curve 240
and ambient water surrounding the drill string at that point, which
cools the testing fluid within the drill string following
pressurization. Referring to FIGS. 1 and 2, the greater decrease in
temperature along curve 240 provides for the greater decrease in
pressure during shut-in phase 144 of pressure curve 140.
Specifically, the greater drop in temperature of fluid of curve 240
results in more PVT effect driven pressure decay during shut-in
phase 144.
[0010] During the performance of the pressure test, an analog and
low resolution circular chart reader may be used by drilling
personnel on the drilling rig to observe a continuous pressure
recording of the fluid containment system. Even in cases where the
fluid containment system component being tested is not leaking, the
pressure test often lasts over half an hour before the pressure
within the fluid containment system begins to stabilize enough such
that a five minute period of successful pressure stabilization may
be recorded. Further, due to pressure decay caused by PVT effects
and the low resolution of the chart recorder, pressure tests are
sometimes judged as successful before full stabilization (e.g.,
decay of 4 psi/min or less, as is a typical current standard in
certain jurisdictions), thus allowing for the risk that the
remaining pressure decay may be due to a leak, in addition to PVT
effects. In practice, this phenomenon is especially impactful at
higher testing pressures as are required in deeper wells and where
synthetic oil based mud (SOBM) is used as the testing fluid.
[0011] Accordingly, there remains a need in the art for systems and
methods that allow for quick and effective pressure testing of well
system equipment, such as a fluid containment system. Further, it
would be advantageous if such systems and methods would mitigate
the PVT effects that take place during a pressure test of well
system equipment. Still further, it would be advantageous to
provide a system that includes a means providing a continuous
pressure signal with a relatively high resolution.
BRIEF SUMMARY OF THE DISCLOSURE
[0012] Disclosed herein is a system for pressure testing a
component of a well system that includes a tubular member that
extends into a wellbore penetrating a subterranean formation. The
tubular member has a first fluid passageway and one or more nodes
that are configured to measure fluid pressure and are coupled to
the tubular member. The system also includes a heat exchanger
having a second fluid passageway and is configured to cool a fluid
passing through the second passageway. Further, the system includes
a fluid flowpath that includes at least a portion of the first
fluid passageway and at least a portion of the second fluid
passageway. In an embodiment, the tubular member comprises a drill
string. In another embodiment, the tubular member comprises a
production riser. In an embodiment, the system further includes a
pump in fluid communication with the fluid flowpath. In this
embodiment, the pump is configured to pressurize the cooled fluid
to produce a pressurized fluid. The pressurized fluid has a
temperature that is substantially equal to the temperature of the
first volume of fluid. In an embodiment, the system further
includes a test plug disposed within the tubular member.
[0013] Also disclosed herein is a method for pressure testing a
component of a well system that includes producing a cooled fluid
by cooling a first volume of fluid having a first pressure. The
cooled fluid is flowed into a closeable chamber of the well system
and shut in to the chamber. Pressure in the chamber is measured
using nodes distributed within the chamber. In an embodiment,
flowing the cooled fluid into the chamber comprises pressurizing
the cooled fluid to produce a pressurized fluid having a second
pressure that is greater than the first pressure of the first
volume of fluid. In an embodiment, pressurizing the cooled fluid to
produce a pressurized fluid includes pressurizing the cooled fluid
to a temperature that is substantially equal to the temperature of
the first volume of fluid. In an embodiment, pressurizing the
cooled fluid to produce a pressurized fluid includes pressurizing
the cooled fluid to a temperature that is less than the temperature
of the first volume of fluid. In an embodiment, the method further
includes determining the presence of a leak within the closeable
chamber by monitoring the pressure measurement. In an embodiment,
cooling the fluid to produce the cooled fluid comprises flowing the
first volume of fluid through a heat exchanger.
[0014] Embodiments described herein comprise a combination of
features and characteristics intended to address various
shortcomings associated with certain prior devices, systems, and
methods. The various features and characteristics described above,
as well as others, will be readily apparent to those skilled in the
art upon reading the following detailed description, and by
referring to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For a detailed description of the exemplary embodiments of
the invention disclosed herein, reference will now be made to the
accompanying drawings in which:
[0016] FIG. 1 is a graph illustrating pressure curves generated
during a pressure test of a drilling system;
[0017] FIG. 2 is a graph illustrating temperature curves generated
during a pressure test of a drilling system;
[0018] FIG. 3 is a schematic view of an embodiment of a drilling
system in accordance with principles described herein;
[0019] FIGS. 4A-4D are perspective views, some in cross-section,
showing components of the downhole electromagnetic network shown in
FIG. 3;
[0020] FIG. 5 is a schematic view of a heat exchanger employed in
the drilling system shown in FIG. 3;
[0021] FIG. 6 is a schematic of the testing fluid system shown in
FIG. 3;
[0022] FIG. 7 is a schematic showing the drilling system shown in
FIG. 3 configured to conduct a fluid containment system pressure
test;
[0023] FIG. 8A is a graph illustrating pressure curves generated
during a pressure test of the BOP pressure testing application
shown in FIG. 7;
[0024] FIG. 8B is a graph illustrating temperature curves generated
a pressure test of the BOP pressure testing application shown in
FIG. 7;
[0025] FIG. 9 is a schematic showing the drilling system shown in
FIG. 3 configured for conducting a pressure test of a completion
system; and
[0026] FIG. 10 is a schematic of a production system configured for
pressure testing in accordance with principles described
herein.
DETAILED DESCRIPTION
[0027] The following discussion is directed to various exemplary
embodiments. However, one skilled in the art will understand that
the examples disclosed herein have broad application, and that the
discussion of any embodiment is meant only to be exemplary of that
embodiment, and not intended to suggest that the scope of the
disclosure, including the claims, is limited to that embodiment.
The drawing figures are not necessarily to scale. Certain features
and components herein may be shown exaggerated in scale or in
somewhat schematic form and some details of conventional elements
may not be shown in interest of clarity and conciseness.
[0028] In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ." Also, the term "couple" or "couples" is intended to mean
either an indirect or direct connection. Thus, if a first device
couples to a second device, that connection may be through a direct
connection, or through an indirect connection via other devices,
components, and connections. In addition, as used herein, the terms
"axial" and "axially" generally mean along or parallel to a given
axis (e.g., given axis of a body or a port), while the terms
"radial" and "radially" generally mean perpendicular to the given
axis. For instance, an axial distance refers to a distance measured
along or parallel to the given axis, and a radial distance means a
distance measured perpendicular to the given axis. Still further,
as used herein, the phrase "communication coupler" refers to a
device or structure that communicates a signal across the
respective ends of two adjacent tubular members, such as the
threaded box/pin ends of adjacent pipe joints; and the phrase
"wired drill pipe" or "WDP" refers to one or more tubular members,
including drill pipe, drill collars, casing, tubing, subs, and
other conduits, that are configured for use in a drill string and
include a wired link. As used herein, the phrase "wired link"
refers to a pathway that is at least partially wired along or
through a WDP joint for conducting signals, and "communication
link" refers to a plurality of communicatively-connected tubular
members, such as interconnected WDP joints for conducting signals
over a distance.
[0029] A system and method for pressure testing a well system is
disclosed herein. Embodiments described herein may be employed in
various well system applications; however, it has particular
application as a system and method for mitigating PVT effects
during the pressure testing of various elements of the fluid
containment system, such as the BOPs, casing, Christmas tree,
tubing hangers, etc. Further, it has particular application with
regard to offshore well systems.
[0030] Referring now to FIG. 3, a well or drilling system 10
generally includes an offshore semi-submersible well system rig 20
at the water line 12 having a testing fluid system 21 disposed
thereon. In other embodiments, rig 20 may comprise other varying
types of offshore platforms, such as drilling ships, submerged
platforms, etc. System 10 further includes a marine riser 30 that
extends between the rig 20 and a wellhead 60 disposed at the sea
floor 14, a fluid containment system 40, a drill string 50 disposed
within riser 30 and having a central axis 55 and an internal fluid
passageway 50a, and a casing 70 supported by cement 72.
[0031] An annulus 35 is formed between drill string 50 and riser 30
and allows for the recirculation of drilling fluid to rig 20 from a
wellbore 62 formed in the subterranean formation 16. A fluid
containment system comprises several components configured to
retain and manage pressure within drill string 50 and annulus 35.
In the embodiment of drilling string 10, fluid containment system
40 includes BOP 41, choke line 44, kill line 46 and an internal BOP
(IBOP) 48. Rams 42 of BOP 41 are configured to provide an annular
seal 43 upon actuation, dividing annulus 35 into an upper section
35a extending between rig 20 and seal 43 and a lower section 35b
extending from seal 43 downward into the wellbore 62. During
drilling, a high pressure volume of fluid from the formation 16 may
flow into wellbore 62 and travel upward through annulus 35. This
formation "kick" may be isolated within lower section 35a of
annulus 35 via actuating one or more rams 42, providing the annular
seal 43. Choke line 44 and kill line 46 provide for alternate
routes of fluid communication between rig 20 and the portion of
annulus 35 disposed below BOP 41.
[0032] During a formation kick, high pressure fluid from the
formation may be circulated upward through choke line 44 to the rig
20, in order to reduce the pressure of the formation fluid within
the annulus 35. Choke line 44 comprises a lower valve 44a, a
manifold 44b and an upper valve 44c. Also, each valve (lower 44a
and upper 44b) may include an inner and outer valve, with each
valve being individually pressure tested. Fluid flow through choke
line 44 may be restricted by closing lower valve 44a or upper valve
44c. Further, choke manifold 44b comprises one or more valves and
chokes and is configured to manage and regulate flow through choke
line 44. Because successful control of a formation kick may depend
on the effective operation of choke line 44 and its components,
valves 44a, 44c and manifold 44b are pressure tested during the
pressure testing of fluid containment system 40. Kill line 46 is
also used to manage a formation kick by allowing for circulation
between annulus 35 and rig 20. Kill line 46 is used to pump high
density drilling mud or other fluid downward from rig 20 to the
annulus 35 to circulate the formation influx out of the wellbore
62. Thus, a kill line such as kill line 46 may be used to "kill"
the well by stopping or at least substantially restricting the flow
of fluid from the formation into the wellbore 62 by pumping heavy
fluid into annulus 35 from the rig 20. Kill line 46 comprises a
lower valve 46a, a kill manifold 46b and an upper valve 46c. As
with choke line 44, flow through kill line 46 may be substantially
restricted or controlled via valves 46a, 46c and manifold 46b.
Thus, during pressure testing of fluid containment system 40,
valves 46a, 46c and manifold 46b are pressure tested as well.
[0033] IBOP 48 is disposed at an upper end 50b of drill string 50
at the rig 20 and is configured to manage fluid pressure within
drill string 50. For instance, during a formation kick, high
pressure formation fluid may begin flowing upward through string 50
via an opening or port of the string 50 disposed within wellbore
62. IBOP 48 may restrict the flow of fluid out of drill string 50
at upper end 50b. Thus, because IBOP 48 may be used in effectively
controlling a formation kick, IBOP 48 is pressure tested during the
pressure testing of fluid containment system 40.
[0034] Referring now to FIGS. 3, 4A-4D, drill string 50 comprises a
plurality of nodes 51 having sensors 57 coupled between a plurality
of pipe joints 52. Wired or networked drill pipe incorporating
distributed sensors can transmit data from anywhere along the drill
string 50 to the rig 20 for analysis. Nodes 51 are provided at
desired intervals along the drill string 50. Network nodes 51
essentially function as signal repeaters to regenerate and/or boost
data signals and mitigate signal attenuation as data is transmitted
up and down the drill string. The nodes 51 may also include
measurement assemblies. The nodes 51 may be integrated into an
existing section of drill string or a downhole tool along the drill
string 50. For purposes of this disclosure, the term "sensors" is
understood to comprise sources (to emit/transmit energy/signals),
receivers (to receive/detect energy/signals), and transducers (to
operate as either source/receiver). Pipe joints 52 include a first
pipe end 53 having, for example, a first induction coil 53a and a
second pipe end 54 having, for example, a second induction coil
54a.
[0035] Nodes 51 comprise a portion of a downhole electromagnetic
network 56 that provides an electromagnetic signal path that is
used to transmit information along the drill string 50. The
downhole network 56, or broadband network telemetry, may thus
include multiple nodes 51 based along the drill string 50.
Communication links 52a may be used to connect the nodes 51 to one
another, and may comprise cables or other transmission media
integrated directly into sections of the drill string 50. The cable
may be routed through the central borehole of the drill string 50,
or routed externally to the drill string 50, or mounted within a
groove, slot or passageway in the drill string 50. Preferably
signals from the plurality of sensors along the drill string 50 are
transmitted to a remote location (e.g., rig 20) through a wire
conductor 52a along the drill string 50. Communication links 52a
between the nodes 51 may also use wireless connections. A plurality
of packets may be used to transmit information along the nodes 51.
Further detail with respect to suitable nodes, a network, and data
packets are disclosed in U.S. Pat. No. 7,207,396 (Hall et al.,
2007), hereby incorporated in its entirety by reference.
[0036] Various types of sensors 57 may be employed along the drill
string 50 in various embodiments, including without limitation,
axially spaced pressure sensors, temperature sensors, and others.
The sensors 57 may be disposed on the nodes 51 positioned along the
drill string, disposed on tools incorporated into the string of
drill string, or a combination thereof. The downhole network 56
transmits information from each of a plurality of sensors 57 to a
surface computer 58. In some embodiments, the sensors 57 are
annular pressure sensors.
[0037] Rig 20 includes a well site computer 58 that may display
information for the drilling operator. Information may also be
transmitted from computer 58 to another computer 59, located at a
site remote from the well, with this computer 59 allowing an
individual in the office remote from the well to review the data
output by the sensors 57. Although only a few sensors 57 are shown
in the figures, those skilled in the art will understand that a
larger number of sensors may be disposed along a drill string when
drilling, and that all sensors associated with any particular node
may be housed within or annexed to the node 51, so that a variety
of sensors rather than a single sensor will be associated with that
particular node.
[0038] Due to safety concerns and to minimize the impact of a
wellbore influx, it is important to detect and contain the influx
as soon as possible. In some circumstances, the BOPs are actuated
and isolate the well at the onset of a formation influx. In some
cases, for example in deepwater wells, the wellbore influx may
migrate above the BOP 41 at the time the BOP's rams are closed. In
the embodiments herein, downhole distributed measurements and the
high speed broadband telemetry system allow wellsite personnel to
identify potential remedial actions for the migrated wellbore
influx. In some embodiments, the measurements used are independent
from surface measurements.
[0039] Referring again to FIG. 3, booster assemblies and network
nodes 51 are disposed along the drill string 50. In some
embodiments, the booster assemblies are spaced at 1,500 ft. (500 m)
intervals to boost the data signal as it travels the length of the
drill string 50 to prevent signal degradation. Network nodes 51 are
also located at these intervals to allow measurements to be taken
along the length of the drill string 50. The distributed network
nodes 51 provide measurements that give the driller additional
insight into what is happening along the potentially miles-long
stretch of the drill string 50.
[0040] Well system rig 20 comprises a rig floor 22, a derrick 24
extending from the floor 22. Testing system 21 is disposed at rig
floor 22 and comprises a mud pit 25, one or more heat exchangers
26a, 26b, a cementing unit 27 and a fluid conduit 28. Conduit 28
provides a fluid flowpath for a testing fluid 29 from mud pit 25,
through heat exchangers 26a, 26b and cementing unit 27 to the
passageway 50a of drill string 50. Testing fluid 29 comprises a
high density and high weight fluid (e.g., drilling fluid, SOBM,
completion fluid, etc.) relative to ambient water 13 disposed below
water line 12. For instance, fluid 29 has a relatively higher
density than fluid from formation 16.
[0041] Referring to FIG. 5, a schematic of heat exchanger 26a is
shown. In the example shown in FIGS. 3, heat exchangers 26a, 26b
are shell and tube heat exchangers having a tube side fluid
passageway 26c and a shell side fluid passageway 26d with two tube
sheets 26e that create a seal between tube side 26c and shell side
26d. Testing fluid 29 enters shell side passageway 26c via port
26f, flows through a plurality of tubes 26g, and exits via port
26i. Also, heat exchanger 26b is substantially identical to heat
exchanger 26a in structure.
[0042] Chilled water 26i enters tube side 26d via port 26j, follows
a deviated flowpath around internal baffles 26k, and exits via port
26l. While water 26i flows through shell side 26d, water 26i
contacts the outer surfaces of the plurality of tubes 26g, allowing
for heat to transfer out of the testing fluid 29 disposed within
tubes 26g and into the chilled water 26i. Thus, due to this heat
transfer between testing fluid 29 and water 26i, the testing fluid
29 entering port 26f is at a higher temperature than the testing
fluid 29 exiting port 26fh, and the chilled water 26i entering port
26j is at a lower temperature than the water 26i exiting port 26l.
The amount of temperature drop between testing fluid 29 entering
port 26f and testing fluid 29 exiting port 26h is a function of the
temperature of the chilled water 26i as it enters port 26j, the
mass flow rate of water 26i, and the mass flow rate of the testing
fluid 29. For instance, increasing the mass flow rate of chilled
water 26i entering heat exchanger 26a will increase the temperature
drop of the testing fluid 29 as it flows through the heat
exchanger. Also, increasing the mass flow rate of the testing fluid
29 will decrease the temperature drop in the fluid 29 as it passes
through heat exchanger 26a.
[0043] In the embodiment illustrated in FIG. 5, chilled water 26i
enters port 26j at approximately 35.degree. F. and exits port 26l
at approximately 39.degree. F. Testing fluid 29 enters port 26f at
approximately 90.degree. F. and exits port 26h at approximately
68.degree. F., forming a cool fluid. In other embodiments, chilled
water 26i may enter port 26j at other temperatures, and testing
fluid 29 may enter port 26f at other temperatures. Further, in
other embodiments, water 26i may comprise other fluids suitable for
transferring heat out of testing fluid 29 as the two fluids flow
through heat exchanger 26a. In other embodiments, heat exchangers
26a. 26b may be another style of heat exchanger, such as a plate, a
plate and fin, a phase change, an air coil and other types of heat
exchangers.
[0044] Referring now to FIG. 6, a schematic of testing fluid system
21 is shown. In this embodiment of testing fluid system 21, a first
volume of testing fluid flows from mud pit 21 through heat
exchanger 26a to cementing unit 27. Testing fluid 29 may be
circulated to mud pit 25 from wellbore 62 via riser 30 (FIG. 3).
Testing fluid 29 has a temperature T.sub.1 as it flows from mud pit
25 to heat exchanger 26a. Fluid 29 at this point has yet to be
pressurized and thus temperature T.sub.1 is at an ambient level
with respect to the surrounding environment. A cooled fluid is
formed via passing testing fluid 29 through heat exchanger 26a,
cooling fluid 29 to a temperature T.sub.2, which is cooler than the
temperature T.sub.1. In this example, T.sub.1 is approximately
90.degree. F. while T.sub.2 is approximately 68.degree. F. After
passing through heat exchanger 26a, testing fluid 29 enters
cementing unit 27. Cementing unit 27 comprises a high pressure pump
suitable for forming a pressurized fluid via pressurizing test
fluid 29 from ambient pressure to pressures ranging from
5,000-12,000 pounds per square inch (psi). In this embodiment,
cementing unit 27 comprises a triplex reciprocating pump that
pressurizes fluid 29 between approximately 8,000-12,000 psi. Due to
PVT effects, the pressurization of fluid 29 by unit 27 increases
the temperature of fluid 29 from temperature T.sub.2 to a higher
temperature T.sub.3. In this embodiment, the pumping action of
cementing unit 27 increases the temperature of the testing fluid 29
by approximately 22.degree. F., and thus temperature T.sub.3 is
approximately 90.degree. F. or ambient with respect to the
surrounding air temperature. Also, the pressurized testing fluid at
temperature T.sub.3 is approximately equal in temperature as the
first volume of fluid at temperature T.sub.1. Thus, the
configuration of heat exchanger 26a and cementing unit 27 results
in a pressurized testing fluid 29 at approximately 10,000 psi at an
ambient temperature T.sub.3 of 90.degree. F.
[0045] Referring still to FIG. 6, in an embodiment, second heat
exchanger 26b is provided downstream of cementing unit 27. As test
fluid 29 passes through heat exchanger 26b, it decreases in
temperature from temperature T.sub.3 to a temperature T.sub.4 of
approximately 75.degree. F. Heat exchanger 26b is configured to
lower the temperature of the test fluid 29 to a temperature that is
substantially equal to the ambient water 13 surrounding riser 30
(FIG. 3) at shallow depths. For instance, as testing fluid 29 is
pumped into drill string 50, a portion of testing fluid 29 will be
disposed within a segment of the drill string 50 that is below the
water line 12. Because the temperature of the ambient water may 13
be cooler than the ambient air temperature, testing fluid 29
disposed below the water line 12 may be cooled to below ambient air
temperature (e.g., cooled to 80.degree. F.) in order to eliminate
any substantial difference in the temperatures of the testing fluid
29 and the surrounding ambient water 13 below water line 12. Each
temperature T.sub.6-T.sub.n, is measured at a corresponding depth
from the water line 12. T.sub.6 is measured at depth 13a, T.sub.7
is measured at depth 13b and T.sub.n is measured at depth 13n,
where the depth of 13n is greater than the depth of 13a, 13b and
13c. Because the temperature of water 13 disposed at depth 13b is
greater than the temperature of the water at 13a, the temperature
of fluid 29 disposed at depth 13a is cooled to a greater extent
than the fluid 29 disposed at depth 13b, etc. The amount of heat
transferred out of fluid 29, as fluid 29 flows through heat
exchangers 26a and 26b, is controlled via the pump rate of
cementing unit 27, the temperature of water 26i as it enters heat
exchangers 26a and 26b, and the flow rate of water 26i (FIG. 5) as
it enters heat exchangers 26a and 26b.
[0046] While the testing fluid system 21 is shown in FIG. 6 as
having two heat exchangers (26a and 26b), in other embodiments the
testing fluid system of a well system may only have one heat
exchanger disposed between a mud pit (e.g., mud pit 25) and a
cementing unit (e.g., cementing unit 27). In that arrangement, the
temperature of the testing fluid after pressurization by the
cementing unit is substantially equal to the temperature of the
fluid before it enters the heat exchanger. Thus, the temperature of
testing fluid 29 entering drillstring 50 is substantially equal to
the ambient air temperature. In other embodiments, two or more heat
exchangers may be included in the testing fluid, depending on the
amount of cooling required to have substantially equal temperatures
between the first volume of testing fluid entering the first heat
exchanger and the pressurized testing fluid entering the drill
string.
[0047] Referring now to FIG. 7, drilling system 10 previously
described with reference to FIG. 3, is shown configured for
pressure testing fluid containment system 40. As shown, drill
string 50 comprises a BOP test plug 49 that is coupled to an end of
two adjacent pipe joints 52 and is disposed axially below BOP 41,
proximal to wellhead 60. As shown in FIG. 7, test plug 49 is
configured to prevent fluid within drill string 50 from flowing
across plug 49. Test plug 49 also forms an annular seal 49a,
preventing fluid flow within annulus 35 across test plug 49. A
radial port or opening 45 is provided in the drillstring 50 to act
as a route of fluid communication between drillstring 50 and the
annulus 35 axially above testing plug 49. A ram 42 of BOP 41 may be
actuated to form an annular seal, preventing fluid passing through
port 45 from flowing upward through annulus 35 to the rig 20. Thus,
annular seals 49a and 43 form a closable annular chamber 35c within
riser 30. Pressure and temperature is continuously measured at
different locations of annulus 35 is detected via nodes 51. For
instance, pressure and temperature of fluid within chamber 35c is
continuously measured via node 51a. The measurements taken by
sensors 57 of nodes 51 are continuously transmitted to rig 20 via
electromagnetic downhole network 56.
[0048] In the example of FIG. 7, fluid containment system 40 is
filled with high density testing fluid 29 (e.g., mud, water based
drilling fluid, SOBM, completion brine, etc.) at a relatively low
pressure. Pressure within drillstring 50 and annular chamber 35c of
annulus 35 is increased to the required BOP testing pressure by
injecting a volume of testing fluid 29 into drillstring 50. Testing
fluid 29 is pumped via cementing unit 27 into drill string 50 via
fluid flowpath 29a that comprises mud pit 25, passageway 26c of
heat exchanger 26a, cementing unit 27, passageway 26c of heat
exchanger 26b and passageway 50a of string 50. Before entering
cementing unit 27, testing fluid 29 passes through the tube side of
heat exchanger 26a (FIG. 5), chilling the testing fluid 29 to a
temperature below the ambient air temperature at the rig 20.
Testing fluid 29 is pressurized to approximately between
5,000-12,000 psi, increasing the temperature of testing fluid 29 to
a temperature substantially equal to the ambient air temperature at
rig 20. Following pressurization by cementing unit 27, testing
fluid 29 flows through heat exchanger 26b, lowering the temperature
of testing fluid 29 to a temperature substantially equal to the
ambient water 13 temperature surrounding riser 30. A volume of
testing fluid 29 is then displaced into drill string 50,
pressurizing fluid within drill string 50 and the annular chamber
35c. In subsequent pressure tests of other elements of the fluid
containment system 40, testing fluid 29 is also disposed within
choke line 44 and kill line 46.
[0049] Referring now to FIGS. 8A and 8B, graphs of pressure and
temperature of testing fluid 29 measured during the BOP pressure
test of FIG. 7 are shown. Pressure graph 500 illustrates pressure
curve 510 as measured by and transmitted from node 51a during the
BOP pressure test illustrated in FIG. 7. As shown in FIG. 8A,
pressure curve 510 comprises a pumping phase 512, a shut-in phase
514 having a beginning 514a and an end 514, and a depressurization
phase 516. During pumping phase 512, testing fluid 29 is pumped
into drillstring 50 via cementing unit 27, which in turn displaces
a volume of fluid into chamber 35c, pressurizing the chamber 35c to
the BOP testing pressure. Once pressure within chamber 35c has
reached the BOP testing pressure, the beginning 514a of shut-in
phase 514 takes place with the cessation of pumping from cementing
unit 27, thus stopping the flow of testing fluid 29 into
drillstring 50 at rig 20. As part of a BOP pressure test shown in
FIG. 7, ram 42 must successfully hold the BOP test pressure for a
specified period of time. In one example, ram 42 must hold 15,000
psi for a period of five minutes. Because the testing fluid 29 that
is now disposed within drillstring 50 has been chilled via heat
exchangers 26a and 26b, shut-in phase 514 of pressure curve 510 is
stable with respect to time, varying to a lesser degree over time
than the pressure curves shown in FIG. 1 where the testing fluid is
not compensated for the temperature increase caused by heat being
transferred into the fluid via the pressurization performed by a
cementing unit or other pump type. Thus, shut-in phase 514 may have
a relatively shorter duration than the shut-in phases shown in FIG.
1, as the requirement of holding the BOP test pressure (e.g.,
10,000 psi) within chamber 35c for a specified amount of time
(e.g., five minutes) will be satisfied more quickly due to the
stability and continuity of the shut-in phase 514 of pressure curve
510 provided by mitigating and/or eliminating heat transfer out of
the fluid following the pumping phase, allowing for a faster BOP
pressure test.
[0050] Pressure within drillstring 50 and chamber 35c exhibits a
stable shut-in phase 514 due to the testing fluid 29 having a
stable temperature following pumping phase 512. For instance,
referring to FIG. 8B, a temperature curve 610 of the temperature of
fluid proximal to node 51a (FIG. 7) within chamber 35c is shown
during the shut-in phase of the BOP pressure test. Temperature
curve 610 exhibits a stable and near constant slope, thus
eliminating or at least substantially reducing PVT related effects
on the testing fluid 29 for the duration of the shut-in phase 514.
Thus, any substantial fluctuation of pressure during shut-in phase
514 may be properly attributed to a leak within the fluid
containment system 40, such as a leak within annular seal 43
provided by ram 42, rather than being caused by a decrease in
temperature of testing fluid 29.
[0051] Referring back to FIG. 7, in addition to 7 ram 42 of BOP 41
being pressure tested, other components of fluid containment system
40 may be pressure tested in a similar manner. For instance, other
individual rams of BOP 41 may be actuated to create an annular seal
within annulus 35, forming a cavity defined by the ram's annular
seal and the seal 49a produced by BOP test plug 49. Likewise,
(inner and outer) lower valves 44a, 46a, manifolds 44b, 46b, and
upper (inner and outer) valves 44c, 46c, of choke line 44 and kill
line 46, respectively, may be pressure tested by placing nodes
(e.g., nodes similar to nodes 51) within choke line 44 or kill line
46 in order to continuously measure and transmit pressure and
temperature readings from lines 44, 46. In order to test the
components of choke line 44 and kill line 46, high density testing
fluid 29 is pumped through heat exchangers 26a and 26b, and into
drillstring 50 via cementing unit 27. Ram 42 of BOP 41 may be
actuated to create annular seal 43. However, instead of allowing
fluid communication between choke line 44 and kill line 46 with
chamber 35c, a component of lines 44, 46, may be sealed (e.g.,
lower valve 44a). In this embodiment, the sealed component (e.g.,
valve 44a) may be pressure tested to see if it holds the BOP test
pressure for a requisite period of time (e.g., five minutes).
[0052] Referring now to FIG. 9, drilling system 10 previously
described with reference to FIG. 3 is shown configured for pressure
testing well completion system 80. Well completion system 80
generally includes wellhead 60, tubing hanger 82, tubing 84, casing
70 and cement 72. In this example, drillstring 50 has a lower
terminal end 50c that couples to tubing hanger 82. Tubing hanger
82, disposed within wellhead 60, seals annulus 35 of riser 30 via
annular seal 84a. Tubing 84 couples to tubing hanger 82 at terminal
end 84a, and extends downward into wellbore 62. Tubing 84 is
configured to act as a route of fluid communication between
formation 16 and a production riser (not shown) that is installed
following completion. Tubing hanger 82 physically supports tubing
80 and allows for a route of fluid communication between tubing 80
and drillstring 50. Further, annular seal 84a of hanger 82 prevents
fluid within wellbore 62 from flowing upward and out of wellbore 62
via annulus 35. Casing 70 allows for selective fluid communication
between wellbore 62 and formation 16. For instance, following the
completion pressure tests, casing 70 is perforated at predetermined
locations in wellbore 62 to provide routes of fluid communication
with the formation 16 via the perforations.
[0053] Prior to installing the production system, well completion
system 80 is pressure tested in order to ensure that completion 80
will not leak once fluid from formation 16 begins to flow into
wellbore 62 and tubing 84 once production of hydrocarbons from
formation 16 has commenced. As part of the pressure test, a radial
port or opening 86 is provided within tubing 84 to allow for a
route of fluid communication between tubing 84 and wellbore 62.
Prior to the initiation of the completion pressure test,
drillstring 50, tubing 80 and wellbore 62 are filled with high
density testing fluid 29 (e.g., mud, SOBM, completion brine, etc.)
at a relatively low pressure. Once filled, an additional volume of
testing fluid 29 is pumped into drillstring 50 via conduit 28 and
cementing unit 27. Testing fluid 29 is pumped from mud pit 25 where
it is stored at ambient pressure and temperature (e.g., 90.degree.
F. and atmospheric pressure).
[0054] Testing fluid 29 passes through heat exchanger 26a prior to
pressurization by cementing unit 27, and flows through a second
heat exchanger 26b prior to entering string 650. Thus, testing
fluid 29 is chilled to below the ambient air temperature to a
temperature of approximately 68.degree. F. prior to pressurization
via cementing unit 27, which increases the pressure of fluid 29
from 5,000-12,000 psi, in this example. Due to PVT effects (e.g.,
friction from pumping), pressurization of fluid 29 results in a
temperature increase of the pressurized fluid such that fluid 29
returns to ambient temperature (e.g., the temperature of the
testing fluid 29 as it exits mud pit 25). Before entering
drillstring 50, fluid 29 passes through heat exchanger 26b,
reducing the temperature of fluid 29 to below the ambient air
temperature to a temperature of approximately 80.degree. F., in
this example. Thus, the temperature of fluid 29 as it enters string
650 is substantially equal to the temperature of the water 13.
[0055] Although the temperature of the water 13 proximal to rig 20
may vary by depth, because only a relatively small volume of fluid
29 is pumped into drillstring 50, the pressurized fluid 29 may be
reduced to a temperature heat exchanger 26b to a temperature
substantially equal to the temperature of the water 13 at shallower
depths (e.g., 0-500 feet below water line 12). Further, the pump
rate of cementing unit 27 and the flow rate of chilled water 26g
(FIG. 5) may be varied to vary the temperature of fluid 29 as it
enters drillstring 50. The temperature of fluid 29 may be varied to
match the temperature of the water 13 at the depth below water line
12 where that portion of fluid 29 will be disposed following the
completion of pumping. For instance, a first portion of fluid 29
pumped into drillstring 50 may be cooled to a greater extent than a
later portion of fluid 29, because the first portion will occupy a
lower depth in drillstring 50, which is surrounded by relatively
cooler water 13, while the later portion will occupy a shallower
depth within drillstring 50, which is surrounded by relatively
warmer water 13. Thus, by ensuring a relatively small temperature
difference between the pumped in fluid 29, and the ambient water 13
disposed proximal to that fluid 29, heat transfer from between the
ambient water 13 and the pumped in fluid 29 may be minimized.
[0056] Referring still to FIG. 9, as testing fluid 29 is pumped
into drillstring 50, fluid within drillstring 50 is displaced out
of opening 86 and into wellbore 62, pressurizing wellbore 62. Once
wellbore 62 has reached a completion test pressure (e.g., 12,000
psi), pumping via cementing unit 27 is stopped and the completion
pressure test enters a shut-in phase. During the shut-in phase of
the pressure test, continuous pressure measurements may be taken
and transmitted to rig 20 via nodes 51 and electromagnetic network
56. Sensors 57 of Nodes 51 continuously measure pressure within
annulus 35 of riser 30 and within drillstring 50.
[0057] Referring now to FIG. 10, a well or production system 600 is
shown. Production system 600 generally comprises rig 20, a
production riser 630 having a central axis 635 and ends 630a and
630b, a Christmas tree 410 having an upper end 410a and a lower end
410b, and well completion system 80. Production riser 630 extends
from upper end 630a at rig 20 to lower end 630b that is coupled to
the first end 410a of Christmas tree 410. The second end 610b of
Christmas tree 410 couples to wellhead 60. Fluid communication
between fluid within formation 16 and production riser 630 is
provided by tubing 84 disposed within wellbore 602. Production
riser includes one or more nodes 51, which partly form
electromagnetic network 56. Christmas tree 410 generally includes
an assembly of valves, spools and other fittings.
[0058] During and/or at the onset of the production phase, the
various sealing elements and components of Christmas tree 410 are
pressure tested in order to ensure that production system 600 may
contain a high pressure influx of fluid from formation 16. In this
example, testing fluid 29 may be pressurized and injected into
production riser 630 via testing fluid circuit 21 disposed at the
rig 20. Christmas tree 410 may be isolated from the formation 16
via displacing a testing plug downward through production riser 630
such that the plug is disposed within wellhead 60, sealing tubing
84 from tree 410 and riser 630. Testing fluid 29 is then pumped
into production riser 630, and a pressure test of Christmas tree
410 is conducted. This pressure test may be iterated for every
individual sealing element and component of Christmas tree 410
(e.g., repeated for every valve, spool, etc.). Due to the cooling
provided by heat exchangers 26a and 26b, the temperature of the
testing fluid 29 entering production riser 630 is substantially
equal to or below the temperature of the testing fluid 29 exiting
mud pit 25 (e.g., ambient air temperature at 90.degree. F.). Thus,
the time required for pressure testing of Christmas tree 410 is
reduced, as the transfer of heat out of pressurized testing fluid
29 into the surrounding ambient water 13 is eliminated or at least
substantially minimized.
[0059] While embodiments have been shown and described,
modifications thereof can be made by one skilled in the art without
departing from the scope or teachings herein. The embodiments
described herein are exemplary only and are not limiting. Many
variations and modifications of the systems, apparatus, and
processes described herein are possible and are within the scope of
the invention. Accordingly, the scope of protection is not limited
to the embodiments described herein, but is only limited by the
claims that follow, the scope of which shall include all
equivalents of the subject matter of the claims. Unless expressly
stated otherwise, the steps in a method claim may be performed in
any order. The recitation of identifiers such as (a), (b), (c) or
(1), (2), (3) before steps in a method claim are not intended to
and do not specify a particular order to the steps, but rather are
used to simplify subsequent reference to such steps.
* * * * *