U.S. patent application number 15/639059 was filed with the patent office on 2019-01-03 for systems and methods for hydrate management.
The applicant listed for this patent is OneSubsea IP UK Limited. Invention is credited to Bjoern Aalstad, Stig Kaare Kanstad.
Application Number | 20190003293 15/639059 |
Document ID | / |
Family ID | 62837685 |
Filed Date | 2019-01-03 |
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United States Patent
Application |
20190003293 |
Kind Code |
A1 |
Kanstad; Stig Kaare ; et
al. |
January 3, 2019 |
SYSTEMS AND METHODS FOR HYDRATE MANAGEMENT
Abstract
An apparatus includes a first flow line, a second flow line and
a seabed-disposed pump station. The first and second flow lines
extend to a sea surface platform. The pump station to, in response
to a shut down of a production flow in the first flow line, operate
a pump of the station to transfer liquid from the first flow line
to the second flow line to reduce a liquid column in the first flow
line and push liquid in the second flow line to the sea surface
platform for removal; and open a bypass valve for the pump to allow
a liquid column in the second flow line to decrease to reduce a
pressure in the second flow line during a period in which the pump
station is shut down. The pump station may also be operated to
communicate a pig through flow lines, and during a time interval in
which the production is shut down, the pump station may be operated
in a bypass mode to prevent hydrate formation in a subsea flow
line.
Inventors: |
Kanstad; Stig Kaare;
(Bergen, NO) ; Aalstad; Bjoern; (Bergen,
NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
OneSubsea IP UK Limited |
London |
|
GB |
|
|
Family ID: |
62837685 |
Appl. No.: |
15/639059 |
Filed: |
June 30, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 41/0007 20130101;
E21B 43/255 20130101; E21B 43/168 20130101; E21B 43/101 20130101;
E21B 43/013 20130101; E21B 43/01 20130101; E21B 37/06 20130101 |
International
Class: |
E21B 43/25 20060101
E21B043/25; E21B 43/013 20060101 E21B043/013; E21B 43/16 20060101
E21B043/16; E21B 43/10 20060101 E21B043/10 |
Claims
1. A method comprising: shutting down production from a subsea
well, comprising reducing a pressure in a first flow line; wherein
reducing the pressure in the first flow line comprises: operating a
seabed disposed pump to draw down liquid followed by gas to reduce
a liquid level in a second flow line extending from a surface
platform and push liquid in the first flow line to the surface
platform; and removing liquid from the first flow line at the
surface platform.
2. The method of claim 1, further comprising: operating the seabed
disposed pump to communicate a production flow from the subsea well
through the first flow line.
3. The method of claim 1, wherein: removing the liquid from the
first flow line comprises using a separator disposed on the surface
platform; and the first flow line extends to the separator.
4. The method of claim 3, wherein reducing the pressure in the
first flow line further comprises: operating a pump bypass valve to
bypass the seabed disposed pump to decrease a liquid column height
of the liquid in the first flow line.
5. The method of claim 3, wherein reducing the pressure further
comprises flaring gas present in the first flow line.
6. The method of claim 1, wherein reducing the pressure in the
first flow line further comprises: stopping the seabed disposed
pump and allowing liquid in the first flow line to flow through a
pump bypass valve and through a local recirculation path.
7. The method of claim 1, wherein shutting down production
comprises shutting down production flow through the first flow line
and continuing a production flow through another flow line while
production flow through the first flow line is shut down.
8. An apparatus comprising: a first flow line to extend to a sea
surface platform; a second flow line to extend to the sea surface
platform; and a seabed-disposed pump station to, in response to a
shut down of a production flow in the first flow line: operate a
pump of the seabed-disposed pump station to flow a liquid followed
by a gas in the first flow line and to transfer the liquid from the
first flow line to the second flow line to reduce a liquid column
in the first flow line and push liquid in the second flow line to
the sea surface platform for removal; and open a bypass valve for
the pump to allow a liquid column in the second flow line to
decrease to reduce a pressure in the second flow line.
9. The apparatus of claim 8, further comprising: a wellhead valve
to connect the first flow line to the second flow line to form a
path to allow operation of the pump to transfer liquid from the
first flow line to the second flow line.
10. The apparatus of claim 8, wherein the seabed-disposed pump
station closes the bypass valve, resumes operation of the pump and
subsequently reopens the bypass valve to reduce the pressure in the
second flow line during the period in which the seabed-disposed
pump station is shut down.
11. The apparatus of claim 8, wherein the pump operates to pump
production fluid from a well, through the second flow line, and to
the sea surface platform.
12-25. (canceled)
26. A system, comprising: a controller; and a subsea pump
communicatively coupled to the controller, wherein the subsea pump
is configured to couple with first and second flow lines extending
to a surface platform, the controller is configured to operate the
subsea pump to drive a fluid flow from the surface platform to the
subsea pump through the first flow line and from the subsea pump to
the surface platform through the second flow line in response to a
shutdown of a production flow, wherein the fluid flow in the first
flow line comprises a liquid followed by a gas to reduce a first
liquid level in the first flow line.
27. The system of claim 26, wherein the controller is configured to
operate the subsea pump to reduce the first liquid level in the
first flow line to reduce pressure and hydrate formation in the
first flow line.
28. The system of claim 27, wherein the controller is configured to
control removal of liquid in the second flow line at the surface
platform to reduce a second liquid level, pressure, and hydrate
formation in the second flow line.
29. The system of claim 28, comprising a liquid gas separator
coupled to the second flow line.
30. The system of claim 26, comprising a bypass valve configured to
bypass the subsea pump to reduce a second liquid level in the
second flow line.
31. The system of claim 30, wherein the subsea pump is coupled to a
local recirculation path.
32. The system of claim 31, wherein the local recirculation path
comprises a loop between the subsea pump and a wellhead.
33. The system of claim 26, comprising a valve disposed between the
first and second flow lines.
34. The system of claim 33, wherein the valve is disposed at a
wellhead.
35. The system of claim 26, comprising at least a portion of the
first flow line and at least a portion of the second flow line.
36. A method, comprising: identifying a shutdown condition of a
production flow; and controlling a subsea pump to drive a fluid
flow from a surface platform to the subsea pump through a first
flow line and from the subsea pump to the surface platform through
a second flow line in response to the shutdown condition, wherein
the fluid flow in the first flow line comprises a liquid followed
by a gas to reduce a first liquid level in the first flow line.
37. The method of claim 36, wherein controlling the subsea pump
comprises reducing the first liquid level in the first flow line to
reduce pressure and hydrate formation in the first flow line.
38. The method of claim 37, comprising controlling removal of
liquid in the second flow line at the surface platform to reduce a
second liquid level, pressure, and hydrate formation in the second
flow line.
39. The method of claim 36, comprising controlling a bypass valve
to bypass the subsea pump and provide fluid flow along a local
recirculation path between the subsea pump and a wellhead.
Description
BACKGROUND
[0001] Natural gas hydrates are crystalline solids that form when
water and natural gas combine in high pressure and low temperature
environments. The formation of hydrates may occur in oil and
natural gas wells, pipelines, pumping systems, production systems,
and other industrial applications. In some instances, hydrate
formations may result in the precipitation of ice-like hydrate
plugs, which may reduce or block flow in fluid lines, including
production lines.
SUMMARY
[0002] In accordance with an example implementation, a technique
includes shutting down production from a subsea well, including
reducing a pressure in a first flow line. Reducing the pressure in
the first flow line includes operating a seabed disposed pump to
draw down liquid in a second flow line extending from a surface
platform and push liquid in the first flow line to the surface
platform; and removing liquid from the first flow line at the
surface platform.
[0003] In accordance with another example implementation, an
apparatus includes a first flow line, a second flow line and a
seabed-disposed pump station. The first and second flow lines
extend to a sea surface platform. The pump station to, in response
to a shut down of production flow in the first flow line, operate a
pump of the station to transfer liquid from the first flow line to
the second flow line to reduce a liquid column in the first flow
line and push liquid in the second flow line to the sea surface
platform for removal; and open a bypass valve for the pump to allow
a liquid column in the second flow line to decrease to reduce a
pressure in the second flow line.
[0004] In accordance with another example implementation, a
technique includes operating a seabed-disposed pump station to
communicate a production flow from a subsea well; operating the
seabed-disposed pump station to draw a pig through a first flow
line, where the first flow line extends between the pump station
and a sea surface platform; and operating the pump station to push
the pig through a second flow line to the platform.
[0005] In accordance with another example implementation, an
apparatus includes a seabed-disposed pump station and a pig
detector. The pump station to communicate a production flow from a
subsea well. The pump station includes a pump and is adapted to be
placed in a first state to allow operation of the pump to draw a
pig through a first flow line, where the first flow line extending
between the pump station and a sea surface platform; in response to
the pig detector detecting the pig, be placed in a second state to
allow the pig to be pushed through a path from an inlet of the pump
to an outlet of the pump; and resume operation of the pump to push
the pig through a second flow line to the platform.
[0006] In accordance with yet another example implementation, a
technique includes shutting down production from a subsea well; and
during a time interval in which the production is shut down,
operating a subsea production pump in a bypass mode to remove
hydrate formations in a subsea flow line.
[0007] Advantages and other features will become apparent from the
following drawings, description and claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] FIGS. 1 and 3 are schematic diagrams of subsea production
systems according to example implementations.
[0009] FIGS. 2A and 2B are flow diagrams depicting techniques to
inhibit hydrate formation in a flow line according to example
implementations.
[0010] FIGS. 4 and 6 are schematic diagrams of seabed-disposed pump
stations according to example implementations.
[0011] FIG. 5 is a schematic diagram illustrating a state of the
pump station of FIG. 4 during a pigging operation according to an
example implementation.
[0012] FIG. 7 is a schematic diagram illustrating a state of the
pump station of FIG. 6 in which a service fluid is used to push a
pig from a position downstream of a pump of the pump station to a
position upstream of the pump according to an example
implementation.
[0013] FIGS. 8, 9 and 10 are flow diagrams depicting
seabed-disposed pump station-based pigging operations according to
example implementations.
[0014] FIG. 11 is a schematic diagram of a pump station according
to a further example implementation.
[0015] FIG. 12 is a flow diagram depicting a technique remove
hydrate formations from a flow line according to an example
implementation.
DETAILED DESCRIPTION
[0016] In the drawings and description that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals. The drawing figures are not necessarily to
scale. Certain features of the disclosed implementations may be
shown exaggerated in scale or in somewhat schematic form and some
details of conventional elements may not be shown in the interest
of clarity and conciseness. The present disclosure is susceptible
to implementations of different forms. Specific implementations are
described in detail and are shown in the drawings, with the
understanding that the present disclosure is to be considered an
exemplification of the principles of the disclosure, and is not
intended to limit the disclosure to that illustrated and described
herein. It is to be fully recognized that the different teachings
of the implementations discussed below may be employed separately
or in any suitable combination to produce desired results.
[0017] Unless otherwise specified, 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." Any use of any form of the terms
"connect," "engage," "couple," "attach," or any other term
describing an interaction between elements is not meant to limit
the interaction to direct interaction between the elements and may
also include indirect interaction between the elements described.
The various characteristics mentioned above, as well as other
features and characteristics described in more detail below, will
be readily apparent to those skilled in the art upon reading the
following detailed description of the implementations, and by
referring to the accompanying drawings.
[0018] A flow line of a subsea production system may occasionally
undergo a period of time in which no flow is communicated through
the flow line. For example, the flow line may be a production flow
line, and production through the flow line may temporarily be shut
down due to equipment failure, routine maintenance, well
intervention, and so forth. During this shutdown interval, the
conditions for hydrates to form in the flow line may be favorable,
and as such, hydrate formations in the flow line potentially
restrict or block flow through the flow line when the flow is to
resume.
[0019] In accordance with example implementations that are
described herein, a seabed-disposed pump station is operated in a
manner to create a relatively low pressure inside a flow line to
prepare the flow line for shut down. The low pressure, in turn,
inhibits hydrate formation inside the flow line. Moreover, in
accordance with example implementations, the seabed-disposed pump
station may be used to assist in pigging operations; and in yet
further example implementations, the pump station may have a
recirculation mode of operation in which thermal energy from the
pump station is used in a local recirculation path (a local
recirculation path between the pump station and the well head
and/or a local recirculation path inside the pump station, as
examples) to remove hydrates from a partially blocked flow
line.
[0020] More specifically, referring to FIG. 1, in accordance with
example implementations, a subsea production system 100 includes a
well 110 that extends into a sea floor, or seabed 120, for purposes
of producing hydrocarbon-based well fluid from one or multiple
geologic formations 109. In this regard, as depicted in FIG. 1, the
well 110 may include a wellbore 114, one or multiple production
strings 116 that extend into the wellbore 114, and so forth.
Moreover, as depicted in FIG. 1, the well 110 may include a
wellhead 112, which may include various valves, a manifold and
potentially other controls for purposes of controlling fluid flow
to and from the well 110. In this manner, the wellhead 112 may be
connected to a flow line, which communicates produced well fluid
and extends to production equipment 135 that is located on a
platform 129 (a platform that includes a surface vessel 130 for the
example implementation of FIG. 1) at the sea surface 131.
[0021] As depicted in FIG. 1, the subsea production system 100 may
include flow lines, which extend from the seabed 120 to the surface
platform 129, such as example flow lines 124 and 126. The flow
lines 124 and 126 may be used for various purposes, such as, for
example, communicating produced well fluid from the well 110 to the
surface platform 129 and communicating chemicals, service fluids,
and to the well 110 from the sea surface platform 129 and so forth.
Moreover, different flow lines may be used for production at
different times.
[0022] In accordance with example implementations, flow lines of
the subsea production system 100, such as the flow lines 124 and
126, may be disposed inside a riser (not shown) that extends from
the sea surface platform 129 to the wellhead 112.
[0023] For the example implementation depicted in FIG. 1, the sea
surface platform 129 is formed by a surface vessel 130. However,
the platform 129 may take on other forms, in accordance with
further example implementations. As examples, the sea surface
platform 129 may be a floating production system, such as a
floating, storage and offloading (FSO) system or a floating,
production, storage and offloading (FPSO) system. In accordance
with further example implementations, the sea surface platform 129
may be a drilling vessel, a semi-submersible floating platform, a
tension leg platform that is connected by mooring cables to the sea
bed 120, a gravity-based platform that is anchored directly to the
sea bed 120 by a rigid anchor, and so forth.
[0024] In accordance with example implementations, a pump station
140 of the subsea production system 100 is disposed on the sea bed
120 and may be connected inline with one or multiple flow lines.
For the example implementation of FIG. 1, the pump station 140 is
connected inline with the flow lines 124 and 126. In this manner,
as depicted in FIG. 1, for the flow line 124, a first segment 124-1
may extend between the pump station 140 and the platform 129, and
another segment 124-2 of the flow line 124 may extend from the pump
station 140 to the wellhead 112. In a similar manner, for the flow
line 126, a first segment 126-1 may extend between the pump station
140 and the platform 129, and another segment 126-2 of the flow
line 126 may extend from the pump station 140 to the wellhead
112.
[0025] In general, the pump station 140 may include one or multiple
pumps and one or multiple control valves (as further described
herein) for purposes of assisting the communication of fluid
between the well 110 and production equipment 135 at the platform
129. In this manner, when the subsea production system 100 is
producing well fluid from the well 110, the pump station 140 may be
operated to assist in communicating the well fluid through one of
the flow lines, such as the flow line 126 (in direction 140
depicted in FIG. 1), to the production equipment 135. The pump
station 140 may also be operated to assist in communicating fluid
(injected treatment chemicals, gas used for lifting operations, and
so forth) to the well 110, such as communicating fluid in direction
139 through the flow line 124, for example.
[0026] In accordance with example implementations, the pumps of the
pump station 140 may be hydraulic compressors, such as single phase
pumps, multiple phase pumps, wet gas compressors, and so forth.
Moreover, in accordance with further example implementations, the
pump station 140 may include dry gas compressors, as the system may
experience issues with hydrates even when using a dry gas
compressor. For instance, the pump may be a dry gas compressor and
a scrubber. Various control lines (hydraulic control lines and/or
electrical control lines), which are not depicted in FIG. 1, may
extend from the platform 129 to the pump station 140 for purposes
of controlling the pumps and valves of the pump station 140, as
described herein.
[0027] Production by the subsea production system 100 may
occasionally be partially or entirely shut down due to a variety of
reasons, such as equipment failure, equipment replacement, well
interventions, and so forth. In this manner, a production flow
through a particular flow line 124 or 126 may be shut down for a
time interval, and this shut down may involve shut down of the pump
station 140. During the time interval in which production through a
particular flow line is shut down, if proper measures are not
undertaken, hydrates may form in the flow line(s) in which flow
does not occur. Hydrate formation-based plugs in a flow line may
impede, if not block, fluid communication through the flow line
when flow through the flow line(s) resumes.
[0028] As described herein, for purposes of preparing a given flow
line to be shut down, the pump station 140 may be operated to
prepare the flow line for the shut down interval by creating a
relatively low pressure inside the flow line, and this low
pressure, in turn, inhibits hydrate formation in the flow line
while the line does not communicate a fluid flow.
[0029] In accordance with example implementations, the pump station
140 may be operated to assist in other operations, such as pigging
operations, which may remove hydrate formations from flow
lines.
[0030] Moreover, in accordance with example implementations, the
pump station 140 may be operated in a bypass mode when the pump
station 140 is otherwise shut down for purposes of used using
thermal energy from the pump's station 140 to remove hydrate
formations from flow passageways. In this manner, when the pump
station 140 is not being used to pump fluid to the surface platform
129, the pump station 140 may be placed in a bypass mode. In this
bypass mode, a local recirculation path through the pump station is
created. Recirculating fluid through the pump station acquires
thermal energy due to the pump station's operation and delivers
thermal energy along the local recirculation path to remove hydrate
formations. The local recirculation path may include, for example,
flow passageways of the pump station as well as flow passageways
that are local (within fifty feet, for example) to the pump
station. As examples, the recirculation path may be entirely
internal to the pump station 140 or may include flow lines that are
external to the pump station 140, such as a recirculation path
formed from flow line segments 124-2 and 126-2 (connected together
by a valve/manifold of the wellhead 112 or connected together by a
valve/manifold closer to the pump station 140, for example) or a
recirculation path formed between flow line segments 124-1 and
126-1.
[0031] In accordance with example implementations, when flow
through a given flow line is to be shut down for a period of time,
a shut down procedure may be used. For the following example, it is
assumed that flow through the flow lines 124 and 126 of FIG. 1 are
shut down. However, it is understood that in accordance with
further example implementations, flow through more than two flow
lines or through a single flow line may be shut down for a period
of time using the techniques that are described herein to reduce
pressure in the flow line(s).
[0032] Assuming, for this example, that the flows through the flow
lines 124 and 126 are to be shut down, the shut down procedure may
be as follows: 1. the appropriate valves/controls of the subsea
production system 100 are operated to create a flow path that
includes the flow line 124, the flow line 126 and a liquid-gas
separator 134 that is part of the production equipment 135 on the
platform 129; 2. the pump station 140 is operated to assist the
communication of fluid through the created flow path to remove
liquid from the flow lines 124 and 126; and 3. lastly, after liquid
has been removed or at least significantly reduced, the pump
station 140 may be shut down.
[0033] The removal of liquid from the flow lines 124 and 126
reduces pressures inside the flow lines 124 and 126, so that
hydrate formation inside the flow lines 124 and 126 is inhibited
while no flows are communicated through these lines. In his manner,
the pressure reduction in each flow line is due to the reduced
static liquid column height. Flaring may further be used, in
accordance with example implementations, to further reduce the
pressure by burning off gas above the liquid column. The reduced
liquid content in the system results in reduced hydrate formations
if hydrate formation conditions still exist.
[0034] More specifically, in accordance with example
implementations, creating the flow path that includes the flow line
124, the flow line 126 and the liquid-gas separator 134 may include
closing a valve to connect the flow lines 124 and 126 together,
such as closing a valve 113 (as an example) of the wellhead 112, as
depicted in FIG. 1. The operation of the pump station 140 during
the shut down procedure draws down a liquid level inside the flow
line 124 (in direction 139) and correspondingly pushes liquid to
the liquid-gas separator 134 via the flow line 126 (in direction
140). In this manner, as depicted by example inset portion 169 of
FIG. 1, the flow line 124 contains a liquid column 172 that has an
associated height, with gas 170 being disposed above the liquid
column 172; and operation of the pump station 140 reduces the
height of the liquid column 172.
[0035] The suction pressure that is exerted by the pump station 140
on the flow line 124 is a function of the boiling pressure of the
fluid in the flow line 124; and in accordance with some
implementations, the suction pressure may be limited by the
pressure of the liquid-gas separator 134. Due to the pumping by the
pump station 140, the flow line segment 124-1 and most of the flow
line segment 126-2 may be emptied. In this manner, in accordance
with example implementations, during the shutdown procedure, the
pump station 140 produces the fluid in the flow line segment 126-2
topside at the platform 129 until the suction gas volume fraction
(GVF) in the flow line segment 124-2 becomes sufficiently too low
to be able to produce further fluid topside. At this point, in
accordance with example limitations, the shutdown procedure
includes stopping the pumping by the pump station 140 and then,
opening a pump bypass valve (not depicted in FIG. 1) to allow the
liquid column in the flow line 126 to decrease. This reduces the
static pressure caused by the liquid column and allows the pressure
inside both flow lines 124 and 126 to be brought near or at the
gas-liquid interphase pressure pending height of remaining liquid
column in risers, in accordance with example implementations.
[0036] The above-process may be repeated in cases in which the
liquid backflow from the flow line 126 (due to the opening of the
pump bypass valve) fills up the flow line upstream of the pump
station 140. In accordance with further example implementations,
the pressures in the flow line 124 and/or 126 may further be
reduced by flaring the gas in the flow line.
[0037] Thus, referring to FIG. 2A, in accordance with example
implementations, a technique 200 may be used to in a partial or
full shut down of production for a subsea production system. The
technique 200 includes operating (block 204) a seabed-disposed pump
to draw down liquid in a first flow line extending to a sea surface
platform and force liquid in a second flow line to the platform.
The technique 200 includes removing (block 208) liquid from the
second flow line to reduce pressure in the second flow line while
production is shut down.
[0038] More specifically, in accordance with example
implementations, a technique 220 that is depicted in FIG. 2B may be
used for purposes of shutting down production from a subsea well in
a manner that reduces a pressure in a production flow line. In this
manner, referring to FIG. 2B, the technique 220 includes
configuring (block 224) valve(s) so that operation of a
seabed-disposed pump station lowers the liquid level of a first
flow line and pushes liquid in a second flow line to sea surface
platform. The technique 220 includes operating (block 228) the
seabed-disposed pump station to push liquid the second flow line to
separator on the platform where the liquid is removed. The
operation of the pump station continues until a determination is
made (decision block 232) that a suction pressure limit has been
reached (e.g., the GVF is too low to continue pumping). After this
limit is reached, the technique 220 includes opening (block 236) a
pump bypass valve to allow the liquid column height in the second
flow line to decrease. In accordance with example implementations,
at this point, the static pressure caused by the liquid column is
now removed, and the system is at a boiling/separator pressure down
to the gas-liquid interphase. If, in accordance with example
implementations, a determination is made (decision block 240) that
after the liquid backflow, liquid still exists in the second flow
line, then the bypass valve is closed (block 242) and control
returns to block 228 to repeat the pumping process.
[0039] It is noted that the techniques 200 (FIG. 2A) and 220 (FIG.
2B) may be used to reduce the pressure in one or multiple flow
lines, as production may continue in one flow line, while
production is halted in other flow line. For example, referring to
FIG. 1, in accordance with some implementation, flow may be halted
in flow line segment 126-1, while flow continues in segment 124-1,
or vice versa.
[0040] In accordance with example implementations, a
seabed-disposed pump station, such as the pump station 140, may be
used to assist in launching and retrieving pigs to clean out
hydrate formations (as well as other obstructions) from flow lines.
More specifically, FIG. 3 depicts a subsea production system 300
that has similar components to the subsea production system 100 of
FIG. 1. In this manner, in FIG. 3, similar reference numerals are
used to denote similar components to the subsea production system
100, whereas different reference numerals are used to denote
different components. In particular, the subsea production system
300 includes a pig launching and retrieval system 304 that is
disposed on the surface platform 129. As described herein, the
seabed-disposed pump station 140 may be operated for purposes of
assisting in communicating a pig 320 through flow lines of the
subsea production system 300 in a round trip that begins and ends
at the surface platform 129. In particular, in accordance with
example implementations, the pump station 140 may be operated to
pull a pig 320 that is launched from the pig launching and
retrieval system 304 through the flow line 124 (as depicted in FIG.
3); reroute the pig 320 to the flow line 126; and push the pig 320
back through the flow line 126 to the pig launching and retrieval
system 304.
[0041] In accordance with some implementations, the pump station
140 may have an implementation that is depicted in FIG. 4. For this
example implementation, the pump station 140 includes a first pump
404 and a second pump 420. In general, the first pump 404 may have
a discharge outlet 405 that may be selectively connected to the
flow line segment 124-2 by an isolation valve 408, and the pump 404
may have a suction inlet 407 that may be selectively connected to
the flow line segment 124-2 via an isolation valve 410. The pump
404 has an associated bypass valve 414 that is connected between
the flow line segments 124-1 and 124-2. In general, to connect the
pump 404 inline with the flow line 124, the isolation valves 408
and 410 are opened, and the bypass valve 414 is closed; and to
bypass the pump 404, the isolation valves 408 and 410 are closed,
and the bypass valve 414 is opened.
[0042] The pump 420 may have a discharge outlet 421 that may be
selectively connected to the flow line segment 126-2 by an
isolation valve 424, and the pump 420 may have a suction inlet 423
that may be selectively connected to the flow line segment 126-2
via an isolation valve 428. The pump 420 has an associated bypass
valve 432 that is connected between the flow line segments 126-1
and 126-2. In general, to connect the pump 420 inline with the flow
line 126, the isolation valves 424 and 428 are opened, and the
bypass valve 432 is closed; and to bypass the pump 420, the
isolation valves 424 and 428 are closed, and the bypass valve 432
is opened. The pump station 140 may further include a crossover
valve 417 that may be opened, as further described herein to
connect the flow line segments 124-1 and 126-1 together.
[0043] It is noted that the pump station 140 may include other
and/or additional components, in accordance with further example
implementations, such as a single pump, more than two pumps, flow
regulators and so forth. The components of the pump station 140
illustrated in FIG. 4, the pump station depicted in other figures,
and the other pump stations that may be depicted herein are merely
shown for purposes of illustrating an example implementation of a
seabed-disposed pump station that may be used to assist in
communicating a pig through a flow line. Thus, many other
implementations are contemplated, which are within the scope of the
appended claims.
[0044] For purposes of detecting the pig 320 when the pig 320 is in
vicinity of the pump inlet 423, the pump station 140 may include a
pig detector 416. For the implementation that is depicted in FIG.
4, the pig detector 416 is connected to the flow line segment 124-1
for purposes of detecting the pig 320 when the pig 320 is upstream
of the crossover valve 417.
[0045] In accordance with example implementations, the pig detector
426 may be a physical contact-based detector that sense physical
contact with the pig 320 inside the flow line. In accordance with
further example implementations, the pig detector 416 may be
constructed to sense the presence of the pig 320 without physically
contacting the pig 320. As examples, the pig detector 416 may
detect the pig 320 using an acoustic energy detected via an
acoustic sensor, detect the pig 320 using a change in a magnetic
field detected using a wire coil, and so forth.
[0046] For purposes of regulating operations of the pump station
140, such as pigging operations, operations involving shutting down
the pump station 140 (shutting down the pump station 140 using
techniques 200 (FIG. 2A) and/or 220 (FIG. 2B), for example) and
possibly other operations, the pump station 140 may include a
controller 403. In accordance with some implementations, the
controller 403 may be constructed to sequence the pump station 140
through various states involved in these operations. For example,
in accordance with some implementations, the controller 403 may
have a telemetry interface to communicate with the surface platform
129 for purposes of receiving commands to configure the particular
state of the station 140 and selectively turn on the pumps 404 and
420. More specifically, to shut down the subsea system, an operator
at the platform 129 may communicate a command to the controller 403
may operate the pump 420, the bypass valve 432 and other valves of
the pump station 104 to perform the techniques 200 and 220 to lower
the pressure in flow lines.
[0047] As another example, for a pigging operation, an operator at
the surface platform 129 may communicate a command to the
controller 403 to place the pump station 140 in an initial state
that is associated with the pigging operation in which the pump 420
is operated to draw the pig 320 through the flow line 124 to the
pump station 104. The controller 403 may be coupled to the pig
detector 416 so that the controller 403 automatically stops the
pump 420 in response to detection of the pig 320. Moreover, in
accordance with some implementations, either via control signaling
from the surface platform 129 or autonomous operation, the
controller 403 may place the pump station 140 in a state and
operate the pump station 140 (as described herein) to move the pig
320 to the outlet side of the pump 420. Subsequently, via control
signaling from the surface platform 129 or autonomous operation
(depending on the particular implementation), the controller 403
may place the pump station 140 in a state (described herein) to
allow the pump 420 to push the pig 320 through the flow line 126;
and then the controller 403 may cause the pump 420 to resume
operation to push the pig 320 through the flow line 126 back to the
surface platform 129.
[0048] The controller 403 may have many different forms, depending
on the particular implementation. In this manner, the controller
403 may disposed inside the pump station 140 (as schematically
depicted in FIG. 4). However, in accordance with further
implementations, the controller 403 may be located in other seabed
equipment, may be located on the surface platform 129, may be a
distributed system that is located on the sea bed and at the
surface platform 129, may be wholly or partially remotely located
at a location other than the subsea production system 300, and so
forth. In accordance with some implementations, the controller 403
may include a telemetry interface and one or multiple processors
(one or multiple central processing units (CPUs), one or multiple
CPU processing cores, and so forth) that execute machine executable
instructions (software) to control the pump station 140 as
described herein. These instructions may be stored in a
non-transitory storage medium, such as semiconductor-based storage,
magnetic-based storage, optical storage, and so forth. Moreover, in
accordance with further example implementations, the controller 403
may include a dedicated hardware circuit to perform one or multiple
functions of the controller 403, such as a field programmable gate
array (FPGA) or application specific integrated circuit (ASIC). In
yet further example implementations, the controller 403 may be a
hydraulic controller that responds to hydraulic stimuli that are
communicated from the platform 129.
[0049] In accordance with example implementations, to begin a
pigging operation to clean out flow lines of the subsea production
system 300, the pig 320 may be placed inside the flow line 124 at
the platform 129 (see also FIG. 3) via the pig launching and
retrieval system 304 (see also FIG. 3); and the pump 420 of the
subsea pump station 140 may then be operated to draw the pig 320
through the flow line segment 124-1 toward the pump station 140.
For this purpose, the isolation valves 408 and 410 are closed to
isolate the pump 404, which is turned off. Moreover, the bypass
valve 414 for the pump 404 is opened; the valve 113 of the wellhead
112 (other valve/manifold path) is opened to connect the flow line
segments 124-2 and 126-2 together; the isolation valves 424 and 428
for the pump 420 are opened; the crossover valve 417 is closed; and
the bypass valve 432 is closed.
[0050] In this state, the operation of the pump 420 allows the pig
320 to be drawn through the flow line segment 124-1 toward and into
the pump station 140. The pig detector 416 may be used to detect
when the pig 320 is in proximity of the crossover valve 417 so that
the pump 420 may be momentarily stopped and other measures employed
to move the pig 320 from the inlet side to the outlet side of the
pump 420 before operation of the pump 420 resumes to push the pig
320 through the flow line 126 back to the surface platform 129.
[0051] In accordance with some implementations, the pump 404 of the
pump station 140 may be used to push the pig 320 to the outlet side
of the pump 420. In this manner, in accordance with further example
implementations, the pump station 140 may be placed in a state 500
that is depicted in FIG. 5. In the state 500, the bypass valve 432
is opened; the isolation valves 408 and 410 are opened; the bypass
valve 414 is opened; and the crossover valve 417 is opened. The
crossover valve 417 establishes communication between the discharge
outlet 405 of the pump 404 and the inlet 423 of the pump 420.
Therefore, the pump 404 may be operated to push the pig 320 to the
outlet side of the pump 420. The pump 404 may then be halted, the
bypass valve 432 may be closed, and the isolation valves 424 and
428 (see FIG. 4) may be opened so that pump 420 may be operated to
push the pig 320 back to the surface platform 129.
[0052] In accordance with further example implementations, the pump
station 140 may include a pigable check valve that forms a shunt
path between the flow line segments 124-2 and 124-6 fora more
compact design.
[0053] Referring to FIG. 6, in accordance with further example
implementations, a pump station 600 may be used in place of the
pump station 140, with similar reference numerals being used in
FIG. 6 to components that the pump stations 140 and 600 share in
common. The pump station 600 includes a service fluid injection
port 604 to push the pig 320 from the inlet to the outlet side of
the pump 420. More specifically, in accordance with example
implementations, the injection port 604 may be, for example, a
service fluid injection port associated with an injection line 600.
In this regard, the injection line 600 may be used for purposes of
providing a service fluid that is communicated from the surface
platform 129 for purposes of injecting service fluid into the well,
and the injection line 600 may be used for purposes of introducing
a service fluid into the flow line segment 126-2 to push the pig
320 to the outlet of the pump 420. It is noted that depending on
the particular implementation, the service fluid may be a gas or a
liquid (methanol, methanol ethylene glycol (MEG) or triethylene
glycol (TEG), as a few examples).
[0054] In this manner, referring to FIG. 7 in conjunction with FIG.
6, in accordance with example implementations, instead of using the
pump 404 to push the pig 320 to the outlet 421 of the pump 420, the
pump station 140 may be placed in a state 700 which both pumps 404
and 420 are isolated, and service fluid is injected at the port 604
to move the pig 320 through the bypass valve 432 to the outlet side
of the pump 420. After this occurs, the pump station 140 may be
configured in a state, as described above, to allow the pump 420 to
resume operation and push the pig 320 through the flow line 126 to
the surface platform 129.
[0055] In accordance with further example implementations, a fluid
may be injected by a remotely operated vehicle (ROV). For example,
the ROV may have a pump and a reservoir that stores a fluid. In
accordance with example implementations, the ROV may connect (e.g.,
hot stab) into a connection port of the pump station (or a
connection port near the pump station), which allows the ROV to
pump the fluid stored in its reservoir into a flow line to push the
pig through the pump station.
[0056] Thus, referring to FIG. 8, in accordance with example
implementations, a technique 800 includes operating (block 804) a
seabed-disposed pump station to communicate a production flow from
a subsea well and operating (block 808) the seabed-disposed pump
station to draw a pig through a first flow line. The first flow
line extends between the pump station and a sea surface platform.
The technique 800 includes operating (block 812) the
seabed-disposed pump station to push the pig through a second flow
line to return the pig to the platform.
[0057] More specifically, referring to FIG. 9, in accordance with
example implementations, a technique 900 includes operating (block
904) a first pump of a seabed-disposed pump station to draw a pig
through a first flow line that extends to a surface platform. The
technique 900 includes, in response to detecting the pig near an
inlet of the first pump, operating a second pump of the
seabed-disposed pump station to push the pig through a path to
place the pig at an outlet of the first pump, pursuant to block
908. Operation of the first pump may then resume to push the pig
through the second flow line to return the pig to the surface
platform, pursuant to block 912.
[0058] Referring to FIG. 10, in accordance with further example
implementations, a technique 1000 includes operating (block 1004) a
first pump of a seabed-disposed pump station to draw a pig through
a first flow line that extends to a surface platform. The technique
1000 includes, in response to detecting the pig near an inlet of
the first pump, injecting a service fluid into a service fluid
injection port of a wellhead to push the pig through a path to
place the pig at an outlet of the first pump, pursuant to block
1208. Operation of the first pump may then resume to push the pig
through the second flow line to return the pig to the surface
platform, pursuant to block 1012.
[0059] In accordance with further example implementations, other
measures may be employed for purposes of inhibiting and removing
hydrate formations. For example, referring to FIG. 11, in
accordance with some implementations, a seabed-disposed pump
station 1100 may be used in place of the other pump stations
described above. In general, the pump station 1100 includes at
least one pump 1110, and the pump station 1100 has an inlet 1148
and an outlet 1144. The pump 1110 has a recirculation flow path
1133 that operates when the pump station 1100 is placed in a bypass
recirculation mode. In this regard, the pump 1110 has an inlet 1111
and an outlet 1112. The outlet 1112 is connected by a connection (a
T connection, a Y connection or other connection) to an inlet 1129
to the recirculation flow path 1133 and to another flow path 1131
that is connected to an outlet valve 1130. The recirculation flow
path 1133 includes a choke valve 1120 that is connected to a T
connection to the inlet 1111 and to a flow path 1127 that is
connected to an inlet valve 1136. Moreover, a bypass valve 1138 may
be connected between the inlet 1148 and the outlet 1144.
[0060] It is noted that FIG. 11 merely depicts an example
configuration of the pump station. Other variations are
contemplated and are within the scope of the appended claims. For
example, in accordance with further implementations, the
recirculation path 1133 may branch out to/from the main flow line
(may branch out and be connected upstream of the inlet 1148 and/or
downstream of the outlet 1144, as examples).
[0061] In accordance with example implementations when the pump
station 1100 is not pumping production fluid, the pump station 1100
may be placed in a bypass mode of operation. In this mode of
operation, the pump 1110 operates to produce a flow through the
recirculation path 1133; and the pump 1110 may be connected in a
local recirculation flow path (i.e., a path extending between the
outlet 1144 and inlet 1148). The local recirculation flow path may
be, for example, a path entirely inside the pump station 1100 or
may be a path that extends outside of the pump station 1100. As
examples, the path may extend outside the pump station by up to ten
feet, up to twenty feet, up to fifty feet, or even farther,
depending on the particular implementation. The local recirculation
flow path may be created by, for example, actuating valves or other
flow control paths to couple together the outlet 1144 and inlet
1148. The operation of the pump 1110 in the bypass mode produces
thermal energy, and the recirculating flow acquires thermal energy
from the pump 1110 and transfers this thermal energy along the
local recirculation flow path. The local recirculation flow path,
in accordance with example implementations, may extend in a path
that is sufficiently short enough to allow the acquired thermal
energy to be used to remove hydrate formations along the path.
[0062] Thus, referring to FIG. 12, in accordance with example
implementations, a technique 1200 includes shutting down production
from a subsea well, pursuant to block 1204 and during a time
interval in which the production is shut down, operating (block
1208) a subsea production pump in a bypass mode to remove hydrate
formations in a flow path.
[0063] While the present disclosure has been described with respect
to a limited number of implementations, those skilled in the art,
having the benefit of this disclosure, will appreciate numerous
modifications and variations therefrom. It is intended that the
appended claims cover all such modifications and variations.
* * * * *