U.S. patent application number 13/668680 was filed with the patent office on 2014-05-08 for systems and methods for conducting pressure tests on a wellbore fluid containment system.
This patent application is currently assigned to Intelliserv, LLC. The applicant listed for this patent is INTELLISERV, LLC. Invention is credited to Daniel Marco Veeningen.
Application Number | 20140123747 13/668680 |
Document ID | / |
Family ID | 50621122 |
Filed Date | 2014-05-08 |
United States Patent
Application |
20140123747 |
Kind Code |
A1 |
Veeningen; Daniel Marco |
May 8, 2014 |
SYSTEMS AND METHODS FOR CONDUCTING PRESSURE TESTS ON A WELLBORE
FLUID CONTAINMENT SYSTEM
Abstract
A method for pressure testing a well system includes:
pressurizing testing fluid within a closeable chamber of a well
system; determining a leak within the closeable chamber using real
time pressure and temperature measurements of the volume of testing
fluid within the closeable chamber; and determining the pathway of
the leak using real time pressure and temperature measurements of a
volume of fluid that is disposed adjacent to the closeable
chamber.
Inventors: |
Veeningen; Daniel Marco;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
INTELLISERV, LLC |
Houston |
TX |
US |
|
|
Assignee: |
Intelliserv, LLC
Houston
TX
|
Family ID: |
50621122 |
Appl. No.: |
13/668680 |
Filed: |
November 5, 2012 |
Current U.S.
Class: |
73/152.51 |
Current CPC
Class: |
E21B 47/06 20130101;
E21B 47/001 20200501 |
Class at
Publication: |
73/152.51 |
International
Class: |
E21B 47/06 20060101
E21B047/06 |
Claims
1. A method for pressure testing a well system comprising:
pressurizing a volume of testing fluid within a closeable chamber
of a well system; determining a leak within the closeable chamber
using real time pressure and temperature measurements of the volume
of testing fluid within the closeable chamber; and determining the
pathway of the leak using real time pressure and temperature
measurements of a volume of fluid disposed adjacent to the
closeable chamber.
2. The method of claim 1, wherein determining a leak within the
closeable chamber comprises determining the change in fluid
pressure within the closeable chamber due to a change in volume of
the volume of testing fluid within the closeable chamber.
3. The method of claim 2, wherein determining the change in fluid
pressure within closeable chamber due to a change in volume of the
volume of testing fluid within the closeable chamber comprises
subtracting the change in fluid pressure within the closeable
chamber due to a change in temperature of the volume of testing
fluid within the closeable chamber from the total change in fluid
pressure within the closeable chamber.
4. The method of claim 1, wherein pressurizing fluid within a
closeable chamber of a well system comprises flowing fluid into the
closeable chamber.
6. The method of claim 2, wherein determining the change in fluid
pressure within closeable chamber due to a change in volume of the
volume of testing fluid within the closeable chamber comprises
measuring in real time a change in fluid pressure within the
closeable chamber using a sensor disposed within the closeable
chamber.
7. The method of claim 2, wherein determining the change in fluid
pressure within closeable chamber due to a change in volume of the
volume of testing fluid within the closeable chamber comprises
measuring in real time a change in fluid temperature within the
closeable chamber using a sensor disposed within the closeable
chamber.
8. The method of claim 1, wherein determining the pathway of the
leak using real time pressure and temperature measurements of a
volume of fluid disposed adjacent to the closeable chamber
comprises disposing a sensor within the volume of fluid disposed
adjacent to the closeable chamber.
8. The method of claim 1, wherein determining the pathway of the
leak comprises detecting a fluid pressure increase in real time
within the volume of fluid disposed adjacent to the closeable
chamber.
9. The method of claim 8, wherein detecting a pressure increase
within the volume of fluid disposed adjacent to the closeable
chamber comprises determining the change in fluid pressure within
the volume due to a change in volume of the volume of fluid
disposed adjacent to the closeable chamber.
10. The method of claim 1, wherein determining a leak within the
closeable chamber using real time pressure and temperature
measurements comprises transmitting the pressure and temperature
measurements of the volume of testing fluid to a computer of the
well system.
11. The method of claim 1, wherein the closeable chamber is formed
using a blowout preventer and a testing plug.
12. The method of claim 11, wherein the pathway of the leak
comprises a sealing surface of the blowout preventer.
13. The method of claim 11, wherein the pathway of the leak
comprises a sealing surface of the testing plug.
14. The method of claim 1, wherein the closeable chamber comprises
a component of a fluid containment system.
15. A method for pressure testing a blowout preventer comprising:
pressurizing a volume of testing fluid within the blowout
preventer; determining a leak within the blowout preventer using
real time pressure and temperature measurements of fluid disposed
within the well system; and determining the pathway of the leak
using real time pressure and temperature measurements of a volume
of fluid disposed adjacent to blowout preventer.
16. The method of claim 15, wherein pressurizing the volume of
testing fluid within the blowout preventer comprises actuating a
ram of the blowout preventer.
17. The method of claim 15, wherein pressurizing the volume of
testing fluid within the blowout preventer comprises actuating an
annular of the blowout preventer.
18. The method of claim 15, wherein determining the leak within the
blowout preventer using real time pressure and temperature
measurements of fluid disposed within the well system comprises
determining a leak across a ram of the blowout preventer.
19. The method of claim 15, wherein determining the leak within the
blowout preventer using real time pressure and temperature
measurements of fluid disposed within the well system comprises
determining a leak across an annular of the blowout preventer.
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 service equipment. More
particularly, the disclosure relates to systems and methods for
reliably and effectively troubleshooting a failed pressure test of
wellbore fluid containment system (FCS) 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 FCS of the well system may be
actuated and steps may be taken to "kill" the well and regain
control. The FCS includes all critical sealing points, including
the BOP itself and each of its individual rams, the choke manifold
and kill manifolds, an internal blowout preventer (IBOP), as well
as other components.
[0007] Due to the criticality of the functional operation of the
FCS with regard to containing and managing fluid pressurizations
within the drilling or well system, periodic testing of the FCS is
required. As part of the FCS testing procedure, a FCS testing plug
may be landed against a sealing surface within the FCS, followed by
subsequent pressurization of the FCS. Per current federal
regulations, pressure testing of the FCS must be conducted upon
installation and before 14 days have elapsed since the last BOP
pressure test. Low and high pressure tests must be conducted for
each individual component, and each component 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 components of a FCS 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, friction
generated by the action of pumping a fluid (e.g., via a
reciprocating pump) increases the temperature as the fluid is
pressurized. Referring to FIG. 1, graph 100 illustrates fluid
pressures in relation to time at different positions along a
vertically-oriented subsea drill string during a high pressure
test. Pressure curve 110 illustrates the fluid pressure at a point
within the drill string near the sea floor, with curves 120, 130
and 140 illustrating fluid pressure at progressively shallower
points along the drill string, with curve 140 illustrating fluid
pressure at the shallowest point, near the surface. 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.
[0009] As shown in FIG. 1, the high 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 FCS. Testing fluid may be pumped into the drill string by a
cement unit or mud pump disposed at the drilling rig of the well
system. Once the FCS of the well system has been pressurized to the
appropriate 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 144b of the shut-in phase. Also, in this pressure test,
each shut-in phase includes a pressurization point (114c, 124c,
134c and 144c) where additional testing fluid is pumped into the
well system to slightly increase fluid pressure within the FCS,
known in the field as "bumping up the pressure." This additional
fluid may be pumped in at the pressurization point during the
shut-in phase in order to return the fluid pressure within the FCS
to the appropriate test pressure, a level similar to that existing
near the beginning of the tests, at points 114a, 124a, 134a and
144a.
[0010] The pressure decay occurring during the shut-in phases
(e.g., 114, 124, 134 and 144) for each pressure curve (e.g., 110,
120, 130 and 140) is due to heat transfer from pressurized fluid
within the FCS to fluid in the surrounding environment. As will be
discussed in greater detail herein, heat transfer is greater for
testing fluid near the surface, as opposed to testing fluid within
the FCS that is disposed farther downhole. The greater amount of
heat transfer near the surface is due to friction generated during
the process of pumping the testing fluid into the well system
(e.g., via a cement unit or mud pump) for the purpose of
pressurizing testing fluid within the FCS. This heat transfer leads
to a greater relative difference in temperature between the testing
fluid disposed within the marine riser and ambient water
surrounding the drill string at that same vertical depth, resulting
in a relatively large amount of heat transfer from the testing
fluid disposed near the surface and the ambient water surrounding
the drill string at that depth The total or aggregate pressure
decay within the FCS, when there is no fluid leak between the FCS
and the surrounding environment, corresponds with the total or net
heat transfer out of the fluid disposed within the FCS to the
surrounding environment.
[0011] During the performance of the FCS low pressure and high
pressure test, an analog, low resolution circular chart surface
recorder may be used by drilling personnel on the drilling rig to
observe a continuous pressure reading of the FCS. Even in cases
where the tested FCS component is not leaking, the pressure test
may often last over half an hour or longer before the pressure
within the FCS begins to stabilize enough such that a continuous
five minute period of successful pressure stabilization may be
recorded. Further, due to pressure decay caused by PVT effects
(e.g., pumping effects) and the low resolution of the analog chart
recorder, FCS pressure tests are sometimes judged as successful
before full stabilization (e.g., decay of 4 psi/min or less), thus
allowing for the risk that remaining pressure decay may be due to a
leak within the FCS, in addition to PVT effects. In practice, this
phenomenon is especially impactful at higher testing pressures, as
are required in deeper, hot wells and where oil based mud (OBM) or
synthetic oil 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 FCS. 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] 1. In an embodiment, a method for pressure testing a well
system comprises pressurizing a volume of testing fluid within a
closeable chamber of a well system, determining a leak within the
closeable chamber using real time pressure and temperature
measurements of the volume of testing fluid within the closeable
chamber and determining the pathway of the leak using real time
pressure and temperature measurements of a volume of fluid disposed
adjacent to the closeable chamber. In some embodiments, determining
a leak within the closeable chamber comprises determining the
change in fluid pressure within the closeable chamber due to a
change in volume of the volume of testing fluid within the
closeable chamber. In some embodiments, determining the change in
fluid pressure within closeable chamber due to a change in volume
of the volume of testing fluid within the closeable chamber
comprises subtracting the change in fluid pressure within the
closeable chamber due to a change in temperature of the volume of
testing fluid within the closeable chamber from the total change in
fluid pressure within the closeable chamber. In some embodiments,
pressurizing fluid within a closeable chamber of a well system
comprises flowing fluid into the closeable chamber. In some
embodiments, determining the change in fluid pressure within
closeable chamber due to a change in volume of the volume of
testing fluid within the closeable chamber comprises measuring in
real time a change in fluid pressure within the closeable chamber
using a sensor disposed within the closeable chamber.
[0013] In other embodiments, determining the change in fluid
pressure within closeable chamber due to a change in volume of the
volume of testing fluid within the closeable chamber comprises
measuring in real time a change in fluid temperature within the
closeable chamber using a sensor disposed within the closeable
chamber. In some embodiments, determining the pathway of the leak
using real time pressure and temperature measurements of a volume
of fluid disposed adjacent to the closeable chamber comprises
disposing a sensor within the volume of fluid disposed adjacent to
the closeable chamber. In some embodiments, determining the pathway
of the leak comprises detecting a fluid pressure increase in real
time within the volume of fluid disposed adjacent to the closeable
chamber. In some embodiments, detecting a pressure increase within
the volume of fluid disposed adjacent to the closeable chamber
comprises determining the change in fluid pressure within the
volume due to a change in volume of the volume of fluid disposed
adjacent to the closeable chamber. In some embodiments, determining
a leak within the closeable chamber using real time pressure and
temperature measurements comprises transmitting the pressure and
temperature measurements of the volume of testing fluid to a
computer of the well system. In some embodiments, the closeable
chamber is formed using a blowout preventer and a testing plug. In
some embodiments, the pathway of the leak comprises a sealing
surface of the blowout preventer. In some embodiments, the pathway
of the leak comprises a sealing surface of the testing plug. In
some embodiments, the closeable chamber comprises a component of a
fluid containment system.
[0014] In an embodiment, a method for pressure testing a blowout
preventer comprises pressurizing a volume of testing fluid within
the blowout preventer, determining a leak within the blowout
preventer using real time pressure and temperature measurements of
fluid disposed within the well system and determining the pathway
of the leak using real time pressure and temperature measurements
of a volume of fluid disposed adjacent to blowout preventer. In
some embodiments, pressurizing the volume of testing fluid within
the blowout preventer comprises actuating a ram of the blowout
preventer. In some embodiments, pressurizing the volume of testing
fluid within the blowout preventer comprises actuating an annular
of the blowout preventer. In some embodiments, determining the leak
within the blowout preventer using real time pressure and
temperature measurements of fluid disposed within the well system
comprises determining a leak across a ram of the blowout preventer.
In some embodiments, determining the leak within the blowout
preventer using real time pressure and temperature measurements of
fluid disposed within the well system comprises determining a leak
across an annular of the blowout preventer.
[0015] 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
[0016] For a detailed description of the exemplary embodiments of
the invention disclosed herein, reference will now be made to the
accompanying drawings in which:
[0017] FIG. 1 is a graph illustrating pressure curves generated
during a pressure test of a well system;
[0018] FIG. 2 is a schematic view of an embodiment of a well system
configured to conduct a fluid containment system pressure test in
accordance with principles described herein;
[0019] FIGS. 3A-3D are perspective views, some in cross-section,
showing components of the wired pipe communication network shown in
FIG. 3;
[0020] FIG. 4A is a graph illustrating a pressure curve generated
during a pressure test of the well system shown in FIG. 3; and
[0021] FIG. 4B is a graph illustrating a temperature curve
generated a pressure test of the well system shown in FIG. 3.
DETAILED DESCRIPTION
[0022] 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.
[0023] 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.
[0024] A system and method for pressure testing components of a
well system is disclosed herein. Embodiments described herein may
be employed in various drilling and production applications;
however, it has particular application as a system and method for
mitigating PVT effects during the pressure testing of pressure
containing components of a well system, such as a fluid containment
system (FCS). Further, it has particular application with regard to
offshore well drilling and production systems.
[0025] Referring now to FIG. 2, an offshore well drilling system 10
generally includes an offshore semi-submersible drilling rig 20
disposed at the water line 12 with a derrick 24 and deck 22 having
a testing fluid system (TFS) 21 disposed thereon. System 10 further
includes a riser 30 that extends between the rig 20 and a wellhead
60 disposed at the sea floor 14, a FCS 40, a drill string 50
disposed within a marine riser 30 and having a central axis 55 and
internal passageway 50a. . . Well system 10 further includes casing
70 that extends downward from a wellhead spool 61 of wellhead 60
and is secured in place via cement 72.
[0026] TFS 21 is disposed at rig floor 22 and comprises a mud pit
25, a cement unit 27 and a fluid conduit 28. Conduit 28 provides a
fluid flowpath 29 for the passage of testing fluid 29a from mud pit
25, through cement unit 27, and to the passageway 50a of drill
string 50. Cement unit 27 comprises a high pressure, reciprocating
triplex pump. However, in other embodiments cement unit 27 may
comprise other components configured to pressurize a fluid. Testing
fluid 29 comprises a drilling fluid that may be at a high density
or high weight (e.g., drilling fluid, SOBM, completion fluid, etc.)
relative to the ambient water 13 disposed below water line 12. For
instance, fluid 29 typically has a high enough density to overcome
the pressure of fluid within the adjacent formation 16.
Alternatively, testing fluid may also comprise a relatively lower
density fluid, such as water or base oil.
[0027] An annulus 35 is formed between drill string 50 and riser 30
and allows for the recirculation of drilling fluid between rig 20
and a wellbore 62 that extends into subterranean formation 16 from
the sea floor 14. FCS 40 generally includes components configured
to retain and manage fluid pressure within well system 10 (e.g.,
drill string 50, FCS 40, annulus 35, wellbore 62, etc.) by acting
as a closeable chamber isolating or sealing fluid disposed within
well system 10 and the surrounding environment. In the embodiment
of well system 10, FCS 40 includes BOP 41, choke line 44, kill line
46 and an internal blowout preventer (IBOP) 48, wellhead 60,
wellbore 62, casing 70 as well as other components. BOP 41 includes
annular 41a and rams 42, each configured to create an annular seal
about drill string 50. For instance, rams 42 of BOP 41 are
configured to provide an annular seal 43 about drill string 50 upon
actuation, dividing annulus 35 into a first or upper section 35a
extending between rig 20 and seal 43 and a second or middle section
35b extending from seal 43 downward to a FCS testing plug 49
coupled to drill string 50.
[0028] A third or lower section 35c extends from wellhead 60 into
the wellbore 62. Testing plug 49 is configured to prevent fluid
flow between middle portion 35b of annulus 35 and a lower portion
35c extending into wellbore 62. Testing plug 49 forms an annular
seal 49c against an annular surface 61a of a wellhead spool 61
disposed within wellhead 60. Testing plug 49 is coupled to an end
of two adjacent tubular joints 52 extending between adjacent nodes
51 and physically engages upper annular surface 61a of wellhead
spool 61 via lower annular surface 49a. 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 above
testing plug 49. During drilling, a pressure spike or kick of fluid
from the formation 16 that has a relatively higher pressure than
drilling fluid disposed within wellbore 62 may flow into wellbore
62 and travel upward through lower section 35c of annulus 35
(testing plug 49 is not installed in well system 10 during the act
of drilling). The formation kick may be trapped or isolated below
upper section 35a of annulus 35 via actuating one or more rams 42
of BOP 41 to provide the annular seal 43. Choke line 44 and kill
line 46 may be used to provide for alternate routes of fluid
communication between rig 20 and annulus 35 such that the testing
fluid (e.g., water, drilling mud, etc.) is pumped into FCS 40 to
prevent further upward flow of fluid from formation 16.
[0029] During a formation kick, an influx of fluid from the
formation may be circulated upward through choke line 44 to the rig
20, in an effort to regain control and stabilize the flow of
formation fluid into annulus 35 such that fluid pressure within FCS
40 may stabilize. Choke line 44 generally includes a lower valve
44a, a manifold 44b and an upper valve 44c. Fluid flow through
choke line 44 may be restricted by closing lower valve 44a or upper
valve 44c. Further, choke manifold 44b includes a plurality of
valves, chokes and other equipment, and as such 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 individually pressure tested during the pressure testing of
FCS 40. Kill line 46 is also used to manage a formation kick by
allowing for circulation between annulus 35 and rig 20. For
instance, kill line 46 is used as a route of fluid communication to
pump high density drilling mud or other fluid downward from rig 20
to the annulus 35 to forcibly maintain the fluid from the formation
kick or influx within the wellbore 62. Thus, a kill line such as
kill line 46 may be used to "kill" the well by reversing, stopping
or at least substantially restricting the flow of fluid from the
formation into the wellbore 62 by pumping heavy fluid into the
entire fluid circulation system (e.g., annulus 35, choke line 44,
kill line 46, etc.) 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 FCS 40, valves 46a, 46c and
manifold 46b are pressure tested as well.
[0030] Another component of FCS 40, 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 (e.g., at the drill bit). For instance,
IBOP 48 includes a valve that allows for the passage of fluid into
string 50 but may be closed to restrict fluid from flowing out of
string 50 through IBOP 48 in the event of a formation kick. Thus,
because IBOP 48 may be used in effectively controlling a formation
kick, IBOP 48 is pressure tested during the pressure testing of FCS
40.
[0031] Referring now to FIGS. 2 and 3A-3D, drill string 50
comprises a plurality of nodes 51 (e.g., 51a-51d, etc.) coupled
between the plurality of tubular 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). Tubular 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.
[0032] Nodes 51 comprise a portion of a wired pipe communication
network 56 that provides an electromagnetic signal path that is
used to transmit information along the drill string 50. The
communication network 56, or broadband network telemetry, may thus
include multiple nodes 51 based along the drill string 50.
Communication links or wired conductors 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. Signals from the plurality of sensors of nodes 51 along the
drill string 50 are transmitted to rig 20 through wire conductors
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. 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 drill string, or a
combination thereof. Sensors 57 of nodes 51 may measure properties
of fluid disposed within string 50 or within annulus 35 or wellbore
62. Thus, sensors 57 of nodes 51 (e.g., nodes 51a-51d) may measure
temperature, pressure, etc., of fluid within string 50 or annulus
35 of well system 10.
[0033] Network nodes 51 are disposed along the drill string 50
between joints 52. 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.
[0034] Rig 20 includes a well site computer 58 that may display
information for the drilling operator. The wired pipe communication
network 56 transmits information from each of a plurality of
sensors 57 to a surface computer 58. 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
(e.g., drill string 50) 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.
[0035] Due to the risk of losing control of well system 10 (i.e.,
the uncontrolled flow of formation fluids into well system 10)
caused by an uncontrolled wellbore influx of fluid from the
formation, it is important to detect the influx as soon as
possible. In some circumstances, a BOP (e.g., BOP 41) of the FCS
(e.g., FCS 40) is actuated to close off the well above the wellbore
influx. In some cases, for example in deepwater wells, the wellbore
influx may migrate above the BOP before a ram of the BOP fully
closes to seal off the wellbore. In the embodiments disclosed
herein, the wired pipe communication network 56 allows wellsite
personnel to identify potential remedial actions for the migrated
wellbore influx. In some embodiments, the measurements used are
independent from surface measurements.
[0036] One or more embodiments of a well drilling system 10
comprising a fluid containment system 40 and a testing fluid system
21 having been disclosed, one or more embodiments of a method of
pressure testing components of the FCS 40 are also disclosed
herein. Further, one or more embodiments of a method for evaluating
or troubleshooting the results of a failed pressure test of
components of FCS 40 are disclosed herein. In an embodiment, a FCS
pressure testing method generally includes the steps of engaging a
testing plug of the FCS against a sealing surface within the FCS
(e.g., a wellhead spool), disposing a quantity of testing fluid
(e.g., drilling fluid, etc.) within the FCS, isolating a component
of the FCS (e.g., actuating a ram or annular of the BOP, closing a
valve of the choke line, etc.), displacing an additional quantity
of testing fluid into the FCS to increase the fluid pressure within
the FCS to a predetermined testing pressure, shut-in the FCS by
ceasing the displacement of testing fluid into the FCS,
continuously in real-time monitor fluid pressure within the FCS via
an wired pipe communication network for a period of time.
[0037] In the event that the FCS is unable to hold a relatively
stable fluid pressure for a predetermined period of time (e.g.,
five minutes), the failed pressure test may be evaluated by
continuously monitoring fluid pressure during the shut-in phase
within cavities adjacent to the FCS component being tested.
Following this, the particular leak path resulting in the failed
FCS pressure test may be determined by determining which adjacent
cavity of the FCS increased in fluid pressure during the course of
the shut-in phase of the pressure test. By determining the
particular leak path, it may be further determined whether the
particular FCS component being tested (e.g., a ram of the BOP) was
at least partially responsible for the leak or whether another
component was responsible for the leak path (e.g., the FCS testing
plug). Optionally, following the methods of FCS pressure testing
and evaluation, the particular components of the well system
responsible for the leak path may be replaced and the pressure test
may be conducted again in an effort to achieve a successful
pressure test of the particular FCS component.
[0038] In an embodiment, ram 42 of BOP 41 may be pressure tested as
part of the regime for pressure testing each individual component
of FCS 40. In this embodiment, testing plug 49 is coupled to drill
string 50 and displaced downward through marine riser 30 until
annular surface 49a of tool 49 engages annular surface 61a of
wellhead spool 61 to create annular seal 49c, which divides annulus
35 into upper section 35a and lower section 35c. Before, during or
after sealing engagement has been achieved between tool 49 and
spool 61, high density testing fluid 29 (e.g., drilling fluid,
SOBM, competition fluid, etc.) is disposed within drill string 50
and riser 30 at a relatively low pressure using cement unit 27 and
flowpath 29a. Also, prior to commencement of the pressure testing
of FCS 40, ram 42 of BOP 41 is actuated to form an annular seal 43
against an outer surface of drill string 50, substantially
preventing testing fluid from a port 45 of string 50 from flowing
upward into the upper section 35a of annulus 35. Thus, annular
seals 49c and 43 form middle section or closable annular chamber
35b within marine riser 30. During the course of the pressure
testing of ram 42, pressure and temperature of fluid within annulus
35 and drill string 50 is continuously measured at different
vertical depths along string 50 via nodes 51a-51d etc. For
instance, pressure and temperature of fluid within chamber 35b is
continuously measured via node 51b while pressure and temperature
in upper portion 35a and lower portion 35c are measured via nodes
51d and 51c, respectively. Measurements taken by sensors 57 at
nodes 51 (e.g., nodes 51a-51d) are continuously transmitted to
computers 58 or 59 at rig 20 via wired pipe communication network
56.
[0039] Following the engagement of annular seals 49c and 43, fluid
pressure within drillstring 50 and chamber 35c of annulus 35 is
increased to a predetermined testing pressure by displacing a
volume of testing fluid 29 into chamber 35c via port 45. Testing
fluid 29 is pumped using cement unit 27 into drill string 50 via
fluid flowpath 29a, which comprises mud pit 25, cement unit 27 and
passageway 50a of string 50. Testing fluid 29 within chamber 35c is
subsequently pressurized to approximately between 5,000-15,000 psi
by cement unit 27. During the process of pressurizing testing fluid
within chamber 35c, testing fluid 29 is disposed within choke line
44 and kill line 46, preventing fluid within chamber 35c from
flowing up lines 44, 46, via the weight of the fluid 29 disposed
within lines 44, 46.
[0040] Referring now to FIGS. 2, 4A and 4B, pressure graph 500
illustrates pressure curve 510 as measured by and transmitted from
node 51b, and temperature graph 600 illustrates temperature curve
610 of additional testing fluid 29 pumped into FCS 40 as measured
by and transmitted from node 51b during the FCS 40 pressure test
illustrated in FIG. 2. As shown in FIG. 2A, 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 cement unit 27, which in turn displaces a volume
of fluid into chamber 35b, pressurizing the chamber 35b to the
predetermined testing pressure. Once pressure within chamber 35b
has reached the FCS testing pressure, the beginning 514a of shut-in
phase 514 initiates with the cessation of pumping from cement unit
27, stopping the flow of testing fluid 29 into drillstring 50 at
rig 20. As part of the BOP pressure test shown in FIG. 2, ram 42
must successfully hold the FCS test pressure for a specified period
of time. In one example, ram 42 must hold 15,000 psi for a period
of five minutes. Friction from pumping results in an increase in
temperature of the additional testing fluid 29 pumped into FCS 40
and string 50 from mud pit 25. During shut-in phase 514, heat
generated within the pumped-in testing fluid 29 begins to transfer
out into fluid occupying riser 30 and/or the ambient seawater 13
surrounding riser 30. Thus, at least partially due to the transfer
of heat from testing fluid 29, fluid pressure within chamber 35b
steadily decreases in response to the decreasing temperature of
fluid within FCS 40, especially with regard to the additional
testing fluid 29 pumped into FCS 40 from mud pit 25.
[0041] As discussed previously, friction from pumping results in an
increase in temperature of testing fluid 29 pumped into FCS 40. As
shown in FIG. 4B, temperature curve 610 illustrates the transfer of
heat from the pumped-in testing fluid 29 into fluid within riser 30
and/or ambient sea water 13 surrounding riser 30. As fluid 29
decreases in temperature (as measured near the water line 12 by
node 51d), it in turn decreases in volume due to PVT effects,
resulting in a corresponding decrease in pressure over time of
fluid within chamber 35b (as measured by node 51b). The pressure
loss within chamber 35b due to the drop in temperature (dP.sub.T)
of the pumped-in testing fluid 29 may be calculated in real time
and subtracted from the total pressure drop (dP) to arrive at a
pressure drop due to a change in volume of FCS 40 (i.e., pressure
drop caused by a leak within chamber 35c) (dP.sub.V) over a given
period of time. The dP.sub.T of testing fluid 29 within chamber 35b
may be calculated given the volumetric coefficient of thermal
expansion (.alpha..sub.f) and the compressibility factor (.beta.)
of the testing fluid 29 (e.g., SOBM, completion fluid, etc.).
[0042] Using the pressure curve 510 and temperature curve 610 data
measured by nodes 51b and 51d, the dP.sub.V of fluid within chamber
35c is calculated in real time. Thus, in the absence of a leak, the
dP.sub.V should remain substantially stable during the shut-in
phase of the BOP test, with five minutes of stable dP.sub.V
satisfying the conditions of the BOP test. Thus, relying on the
real time dP.sub.V of fluid within chamber 35b allows for a
relatively timelier BOP pressure test because the test conductor
(e.g., drilling operator at rig 20) will not have to wait on the dP
of fluid within testing fluid system 21, which must follow
stabilization of the temperature of fluid within FCS 40 (especially
the additional pumped-in testing fluid). 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., 15,000 psi) within chamber 35b for a specified
amount of time (e.g., five minutes) will be satisfied more quickly
due to the stability of calculated dP.sub.V versus measured dP,
allowing for a faster BOP pressure test.
[0043] Further, while in this example temperature data from node
51d is relied upon in determining dP.sub.T, in other embodiments
temperature data may be measured and transmitted from a plurality
of nodes spanning the length of drill string 50 between test plug
49 and rig 20, allowing for the computation of the overall dP.sub.T
for all of the testing fluid 29 within string 50, flowpath 29a and
chamber 35b of FCS 40.
[0044] In some cases, a leak will occur within chamber 35b,
possibly at seal 43 provided by ram 42 or at seal 49c provided by
BOP testing tool 49. A leak may be determined by a drilling
operator at rig 20 in real time via the dP.sub.V of fluid within
chamber 35b during shut-in phase 514, which may be calculated from
the measured pressure curve 510 and temperature curve 610 of the
fluid. For instance, if the dP.sub.V steadily decreases during
shut-in phase 514, then a leak has occurred within chamber 35b,
regardless of any temperature changes in the fluid within chamber
35b. If seal 43 is allowing fluid within chamber 35b to pass into
upper portion 35a of annulus 35, then BOP 41 has failed the BOP
pressure test and a new ram 42, annular BOP or BOP 41 may need to
be installed before the drilling operation may be continued.
However, if a faulty seal 49c is responsible for the fluctuation of
the dP.sub.V of fluid within chamber 35b, then a new BOP testing
tool 49 may be installed and a new BOP pressure test conducted,
without yet having to replace ram 42 or BOP 41. For instance,
continuous pressure and temperature measurements of fluid within
lower portion 35c of annulus 35 may be taken at node 51c to
calculate a real time dP.sub.V of fluid within lower portion 35c.
If the dP.sub.V of fluid within lower portion 35c increases during
shut-in phase 514, then fluid within pressurized chamber 35b is
leaking past seal 49c of tool 49 and into lower portion 35c of
annulus 35. However, if the dP.sub.V of fluid within lower portion
35c remains stable during shut-in phase 514, then fluid is not
leaking into lower portion 35c, and the cause of the leak within
chamber 35b must extend to a different portion of the FCS 40 and/or
well system 10. Also, a real time dP.sub.V of fluid within upper
portion 35a of annulus 35 may be calculated using real time
temperature and pressure measurements of the fluid via node 51a. In
this example, if the dP.sub.V of fluid within upper portion 35a
increases during shut-in phase 514, then fluid is leaking into
upper portion 35a via a leak within seal 43 of ram 42, resulting in
a failure by BOP 41 of the BOP pressure test.
[0045] Referring back to FIG. 2, in addition to ram 42 of BOP 41,
other components of FCS 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 testing plug 49. Likewise, lower valves 44a, 46a, manifolds
44b, 46b, and upper 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 into drillstring 50 via cement 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 b 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).
[0046] 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.
* * * * *