U.S. patent application number 10/138020 was filed with the patent office on 2003-11-06 for subsea riser separator system.
Invention is credited to Carmon, Ken, Eng, Jonathan, Hopgood, Dave, Landeck, Chris, Lush, David, Ucok, Hikmet.
Application Number | 20030205384 10/138020 |
Document ID | / |
Family ID | 29269231 |
Filed Date | 2003-11-06 |
United States Patent
Application |
20030205384 |
Kind Code |
A1 |
Lush, David ; et
al. |
November 6, 2003 |
SUBSEA RISER SEPARATOR SYSTEM
Abstract
A preferred embodiment of the inventive fluid delivery system
comprises a vertical liquid/vapor separator and riser assembly that
comprises a multi-phase separator inlet, a vapor outlet and riser,
and a liquid outlet port connected to a hydraulically-driven
centrifugal pump. By controlling the operational speed of the pump,
the level of the separated liquid within the separator can be
controlled without the need for control valves. The vertical
separator is capable of low pressure operation and large variations
in controlled liquid levels within the separator, allowing the
relatively slow reaction time pump to control the liquid level from
low pressure wells penetrating low pressure reservoirs.
Inventors: |
Lush, David; (Houston,
TX) ; Eng, Jonathan; (Sugar Land, TX) ; Ucok,
Hikmet; (Sugar Land, TX) ; Hopgood, Dave;
(Missouri City, TX) ; Landeck, Chris; (Sugar Land,
TX) ; Carmon, Ken; (Richmond, TX) |
Correspondence
Address: |
William O. Jacobson
UNOCAL
P.O. Box 7600
Brea
CA
92822-7600
US
|
Family ID: |
29269231 |
Appl. No.: |
10/138020 |
Filed: |
May 2, 2002 |
Current U.S.
Class: |
166/357 ;
166/265 |
Current CPC
Class: |
E21B 43/36 20130101;
E21B 43/01 20130101 |
Class at
Publication: |
166/357 ;
166/265 |
International
Class: |
E21B 043/00 |
Claims
What is claimed is:
1. An apparatus for recovering fluids from a subsea well located at
a water depth of at least about 1,500 feet from a surface location,
said apparatus comprising: a fluid separator having a nominal
vertical dimension larger than a nominal horizontal dimension, said
fluid separator capable of operating at an internal pressure of no
more than about half of the external pressure and having at least
two fluid outlets and one multi-phase fluid inlet; a transducer
producing a signal that is at least in part dependent upon a fluid
interface level within said fluid separator; an upper, less-dense
fluid outlet of said fluid separator fluidly connected to a riser
assembly that extends from said fluid separator to a near surface
location; a hydraulically-driven pump fluidly connected to a lower,
more-dense fluid outlet of said fluid separator, wherein the
operational speed of said hydraulically driven pump is at least in
part controlled by said signal produced by said transducer.
2. The apparatus of claim 1 wherein said hydraulically driven pump
is located outside of said fluid separator.
3. The apparatus of claim 2 wherein said riser assembly and said
fluid separator are composed of tubular sections and wherein said
fluid separator has a nominal diameter of no more than about 36
inches.
4. The apparatus of claim 3 wherein said fluid separator and said
riser assembly have nominal internal diameters of at least about 12
inches.
5. The apparatus of claim 4 which also comprises a removable mixed
fluid inlet.
6. The apparatus of claim 5 wherein said fluid separator has a
nominal internal diameter of no more than about 30 inches.
7. The apparatus of claim 6 wherein said fluid separator has a
vertical height of about at least 30 feet.
8. The apparatus of claim 7 wherein said fluid separator has a
vertical height of about at least 50 feet.
9. The apparatus of claim 8 wherein said fluid separator has a
vertical height of about at least 80 feet.
10. The apparatus of claim 9 wherein said hydraulic pump and a
liquid-level interface within said fluid separator form a partially
self-regulating liquid-level interface controller.
11. The apparatus of claim 10 wherein said separator is capable of
operating at an internal pressure of 500 psi or less.
12. The apparatus of claim 11 wherein said separator is capable of
operating at an internal pressure of 200 psi or less.
13. An apparatus for separating fluids from a multi-phase fluid
source, said apparatus located at a water depth of at least about
1,500 feet from a surface location, said apparatus comprising: a
fluid separator capable of operating at an internal pressure of
about 1/2 of the external pressure or less and having a nominal
vertical dimension larger than a nominal horizontal dimension, said
fluid separator comprising well tubular sections and having at
least two fluid outlets and at least one inlet fluidly connected to
said multi-phase fluid source; an upper fluid outlet of said fluid
separator fluidly connected to a riser assembly that extends from
said fluid separator to a near-surface location; and a centrifugal
pump fluidly connected to a lower fluid outlet of said fluid
separator, wherein the operational speed of said pump is at least
in part controlled by a fluid level interface within said fluid
separator.
14. The apparatus of claim 13 wherein said pump is a hydraulic pump
located outside of said fluid separator.
15. The apparatus of claim 14 wherein said pump is capable of
operating when the height of said fluid level interface within said
fluid separator varies by as much as 40 feet.
16. The apparatus of claim 15 wherein said riser comprises at least
two concentric conduits.
18. The apparatus of claim 16 wherein the nominal diameter of said
fluid separator is about 4 feet or less.
19. A process for recovering fluids from a subsea well comprising:
fluidly connecting said subsea well to a fluid inlet of a subsea
vertical separator; fluidly connecting a riser assembly to an upper
fluid outlet of said subsea vertical separator; fluidly connecting
a hydraulically-driven pump to a lower outlet of said subsea
vertical separator separator; determining a fluid level within said
subsea vertical separator; and controlling the internal pressure
within said vertical separator to 1/2 the external pressure or less
and controlling the operational speed of said hydraulically-driven
pump using at least in part said determined fluid level.
20. The process of claim 19 wherein said controlling step uses at
least in part a self-regulating output characteristic of said
hydraulically driven pump and said hydraulically driven pump has a
response time of at least 20 seconds in response to changes in
liquid interface level within said vertical separator.
Description
FIELD OF THE INVENTION
[0001] This invention relates to the offshore resource-recovery
devices and processes. More specifically, the invention is
concerned with improved oil and gas or other multi-phase fluid
production from offshore subsea wells, especially from ultra-deep
offshore wells.
BACKGROUND OF THE INVENTION
[0002] Some offshore resource recovery activities, e.g., withdrawal
of hydrocarbon fluids from a subsurface reservoir through a well
tubular and riser assembly to surface fluid delivery facilities,
have previously been accomplished using an offshore platform. The
offshore platform typically supports at least a portion of the
riser and fluid delivery facilities and other equipment needed to
process and recover resource fluids.
[0003] For shallow water depth locations, a well and fluid delivery
system typically includes a riser and the remainder of the fluid
delivery system that is generally located on a rigid platform
structure fixed to a seafloor anchor or foundation. For deepwater
offshore platforms locations, e.g., offshore platforms located in
waters having a depth exceeding about 1,500 feet (or about 457
meters), this type of fixed tower structure is typically not cost
effective, and other types of facilities may be used, e.g., subsea
wellheads and delivery systems.
[0004] As the distance between the subsea wellheads and surface
processing facilities increases, e.g., due to increasing water
depths, the addition of external energy to the recovered fluids may
become necessary to recover commercial quantities of oil or other
fluids from deepwater reservoirs. For wells in deepwater locations,
especially in ultra deepwater locations (herein defined as water
surface to mudline depths of at least about 10,000 feet or 3,000
meters), the addition of external energy may extend the working
range of reservoir pressures that can be produced. The additional
external energy can be a major factor in producing commercial
flowrates of oil and gas from these deepwater or ultra-deepwater
resources.
[0005] One of the items of equipment that may be required to
process and recover commercial quantities of oil and/or gas from
deep, multi-phase reservoirs is a pump. The pump must be able to
handle multi-phase fluids such as oil with lighter hydrocarbon or
inert gases, oil with steam or flashing hot brine, slurries, or
other fluid-like mixtures of components having density
differences.
SUMMARY OF THE INVENTION
[0006] One embodiment of the inventive fluid delivery system
comprises a vertical, low-pressure fluid separator and integral
vapor riser assembly having a liquid outlet port connected to a
pump assembly, preferably hydraulically driven. The pump assembly
increases the pressure of the separated liquid allowing the
delivery of pressurized liquid to other fluid handling facilities
at the surface. The pump speed is simultaneously controlled to
limit the range of vapor/liquid interface levels within the
separator. The large variation in liquid interface levels within
the vertical separator also allows the use of a subsea
hydraulically-driven pump (typically having a relatively slow
reaction time especially if hydraulically driven from a surface
source of pressurized fluid) even during periods of system upsets.
Because of the system upset tolerance, the relatively open system
design, and simplicity of the operating controls, the present
invention is expected to be reliable, safe, and cost effective.
Moreover, the removal of most of the liquid-phase from the vapor
riser allows a minimum operating or reservoir abandonment pressure,
minimizing the backpressure on the subsea well.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 shows a side view of a subsea separator, riser and
pump assembly supplied by a multi-phase fluid mixture; and
[0008] FIG. 2 shows side view of an alternative subsea separator,
riser, and pump with the separator directly connected to the subsea
well.
[0009] In these Figures, it is to be understood that like reference
numerals and letters refer to like elements or features, or to
elements or features functioning in like manner.
DETAILED DESCRIPTION OF THE INVENTION
[0010] FIG. 1 shows a side view of a tubular vertical separator 6
supported by a piling 13 and a liquid or dense fluid pump assembly
9 similar to the comparable devices shown in FIG. 2. The preferred
elongated tubular separator 6 in FIG. 1 is essentially composed of
one or more pipe sections or other cylindrical elements having a
nominal diameter larger than the nominal diameter of the concentric
riser assembly 8 similar to that described for the elongated
vertical separator 6 shown in FIG. 2. The tubular separator 6 shown
in FIG. 1 comprises at least one multi-phase fluid inlet 12, at
least one liquid or more-dense fluid outlet 11 connected to the
pump assembly 9, and at least one vapor or less-dense-phase fluid
outlet connected to a riser assembly 8.
[0011] The multi-phase fluid inlet line 12 is in fluid
communication and is thus supplied by a subsea well (not shown in
FIG. 1) or a manifold connected to a plurality of subsea wells. The
pressurized outlet line 14a from the pump assembly 9 is connected
to a connector block 15 and fluidly connected to the interior
tubing 17 of a two-concentric-piped riser assembly 8. However, some
applications may use a separate vapor riser and pressurized liquid
piping or riser system, e.g., see FIG. 2.
[0012] In the embodiment shown in FIG. 1, the inlet port and line
12 typically supplies a multi-phase mixture of liquids (e.g., crude
oil, water and/or gas condensates) and vapors (such as carbon
dioxide, methane and other light hydrocarbon gases) from a spaced
apart well to the tubular separator 6. The entry direction of the
multi-phase mixture to the tubular separator 6 includes a
tangential component, forcing the multi-phase fluid into a whirling
or cyclonic motion constrained within the diameter of the tubular
separator 6. The cyclonic motion tends to force heavier liquids or
more dense fluids to the circumferential walls of the tubular
separator 6 while allowing gravity to drain the separated liquids
near the walls towards the bottom or lower outlet. As flowrates
increase, the whirling speed within the tubular separator may also
increase, tending to improve separation efficiency (as compared
with a horizontal separator where increased flow rates tend to
degrade separator efficiency).
[0013] The capability of the inventive system to handle varying
flow rates of liquid is especially important as reservoir (water
and well) depths increase and/or non-vertical subsea well sections
are used. The severity and/or possibility of slug flow (e.g.,
periods when the well produces essentially all liquid flow followed
by periods when the well produces essentially all gaseous flow) and
other mixed flow variations tend to increase with increasing well
depths and/or lengths, especially in horizontal well segments.
Unless the wide variations in mixed flowrates can be tolerated or
smoothed out by the separation system, unacceptably wide variations
in delivered flowrates and shutdown of the well are possible. Slug
flow can also damage pipelines and equipment, so separation and
smoothing of liquid and vapor flowrates can also assist in the safe
operation of the hydrocarbon producing system.
[0014] The separated liquid from the tubular separator 6 is
withdrawn through the lower outlet line 11a and conducted to a pump
assembly 9. The pressurized liquid from the pump assembly 9 is
conducted through the pump discharge line 14 and a riser connector
block 15 to an inner conduit 17 (shown cutaway and dotted within
the outer conduit 18 of the generally concentric riser assembly 8).
The separated vapor or less dense fluid from the tubular separator
6 rises through the connector block 15 to the annulus outside of
the inner conduit 17 and within the concentric riser assembly 8. In
alternative embodiments, the pressurized and separated liquid from
the pump assembly 9 can be conducted to other devices besides the
concentric riser strings 8, e.g., conducted to the surface using a
separate dedicated (liquid) conduit or riser string, conducted to a
liquid collector or manifold, conducted to an injection well,
conducted to a water-oil separator or other processing facilities,
or conducted to an oil export pipeline or other flowline.
[0015] The concentric riser strings 8 preferably comprise 30-50
foot (9.14-15.2 meter) sections of 12-16 inch (30.5-40.6 cm)
nominal diameter N-80 pipe having a nominal wall thickness of
1-11/2 inches (2.54-3.81 cm) for the outer pipe string 18 and 30-50
foot (9.14-15.2 meter) sections of 6-10 inch (15.2-20.5 cm) nominal
diameter N-80 pipe having a nominal wall thickness of 1/2-1 inch
(1.27-2.54 cm) for the inner conduit or pipe string 17. Separate
riser strings 8. The concentric riser assembly 8 also typically
comprises couplings, instrumentation and control cabling/hydraulic
fluid tubing. A minimum internal diameter of the inner tubing
string 17 is preferably at least about 4 inches (10.2 cm), more
preferably at least about 6 inches (15.2 cm) to allow cable tools
to be lowered through the concentric riser assembly 8 and tubular
separator 6.
[0016] The riser assembly 8 conducting generally vapors from the
tubular separator 6 to at or near the surface allows low-pressure
operation of the tubular separator. Instead of an internal pressure
comparable to the external pressure or the pressure head of
produced liquids in a riser at the deepwater or ultra-deepwater
location, the vapor riser and thick wall construction of the
tubular separator 6 allows the separator to operate at much reduced
pressures, preferably less than 1/2 the external subsea pressure
for low pressure reservoirs, more preferably less than about 500
psi, and still more preferably less than about 200 psi for depleted
reservoirs.
[0017] In one embodiment, the tubular separator 6 is essentially a
widened and generally open portion of one or more riser tubular
sections. The tubular separator 6 typically has a nominal diameter
of no more than about 3 feet (0.94 meter) for the embodiment shown.
Although there is no theoretical limit on the nominal diameter of
the tubular separator 6 or vertical separator shown in FIG. 2 in
other embodiments, the nominal diameter of the tubular separator
typically varies from about 24 inches to 36 inches (or about 61.0
to 91.4 centimeters). This allows the tubular separator 6 to be
picked up, handled, and installed mostly using handling equipment
used for riser sections.
[0018] The overall length of the elongated tubular separator 6 can
be a significant portion of the entire length of the riser assembly
8 if needed, but is more typically in the range of at least about
30 feet (9.14 meters) and less than about 100 feet (30.5 meters),
more preferably at least about 60 feet (18.3 meters), and for some
applications, most preferably at least about 80 feet (24.4 meters).
In the most typical range of lengths, the vertical separator is
essentially a widened extension of the outer conduit 18 of the
riser assembly 8, e.g., composed of large riser tubular sections
welded or otherwise joined together with a reducer at the upper end
to connect to the rest of the riser assembly. A pipe end cap may
also be provided for support at the lower end of the separator.
[0019] The operation of pump assembly 9 is preferably controlled by
the pressure of the separated liquid sensed in the lower outlet
line 11a as an indicator of liquid interface level in the
separator. In an alternative embodiment, the pressure at a second
port (e.g., at the second or emergency outlet port ED) is also
sensed, and the pressure difference is used to control the
operation of pump assembly 9. The liquid pressure or pressure
difference is an indication of the height of the separated liquid
within tubular separator 6 or between ports. Because of the
significant distance ODR between the lower liquid outlet level LLOL
and upper fluid inlet level UFIL, the height of separated liquid
within the vertical separator can vary widely, e.g., can range from
at or near the lower liquid level outlet to at or near the upper
fluid inlet level. Preferably, the separator nominally functions
with a liquid height midway between the multi-phase inlet level
UFIL and the liquid outlet level LLOL, but can vary to as high as
near the connector block 15 or as low as near a second or emergency
liquid outlet ED, e.g., the fluid interface level can vary by about
40 feet or 60 feet (12.2 or 18.3 meters) or more.
[0020] Instead of using the sensed liquid pressures at the liquid
outlet line 11 to control the flow and operational speed of pump
assembly 9 and maintain the level of separated liquids within a
controlled range within vertical separator 6, alternative
embodiments control the flow of separated fluids by other means.
Other flow control means can include using signals indicating
liquid pressures to operate control valves in the lower outlet line
11 or release additional liquids to a second outlet line and port
ED, using the presence and/or absence of fluid at one or more
outlets in a vertical separator to control pump speed, and using
ultrasonic or other liquid level sensors and the rate of indicated
level change to control valves (not shown) and/or pump operational
speed.
[0021] In a preferred embodiment, the pump element of pump assembly
9 may be a centrifugal or other pump type that tends to vary in
volumetric flowrate with changes in net positive suction head
(NPSH) at the fluid inlet. If this type of pump is used, pump
assembly 9 and tubular separator 6 may be, at least in part, self
regulating, i.e., the pump flowrate falls as the NPSH and liquid
level falls until minimal flow is discharged at minimum NPSH or
essentially little or no liquid flow is discharged when the liquid
level falls below the minimum NPSH. Conversely, at the maximum
height of liquid in tubular separator 6, pump flowrates and
operating efficiency are maximized, tending to lower the level of
separated liquid in the vertical separator.
[0022] The preferred configuration incorporates a centrifugal pump
assembly 9 combined with a differential pressure transducer in the
liquid outlet line 11 to control the speed (and flowrate) of the
separated liquid removed from tubular separator 6. The preferred
pressure transducer is supplied by Corr Ocean located in Oslo,
Norway.
[0023] The preferred hydraulic pump assembly 9 is supplied by Weir
Pumps located in Glasgow, Great Britain. A drive fluid, e.g., water
supplied by surface pumps and transmitted to the pump assembly 9
through control tubing extending from the surface drive-fluid pumps
to near the mudline, drives the pump assembly 9. Pump speed
variation (and/or other controls) as well as the self-regulating
characteristics of the system are used to generally maintain the
liquid interface level between the upper fluid inlet level UFIL and
the lower liquid outlet level LLOL. The distance or depth
difference between the inlet and outlet levels UFIL and LLOL is
preferably at least about 30 feet (9.14 meters), more preferably at
least about 50 feet (15.2 meters), and nominally about 80 feet
(24.4 meters).
[0024] The process of using the fluid delivery system 2 for normal
multiphase flowrates (e.g., separating vapor and liquid from a
mixed flow inlet stream) involves controlling the pump speed as a
function of the height/pressure of the separated liquid in the
vertical separator 6. If the liquid inflow rate from the well
increases and the liquid interface level rises, the pump speed will
be increased to reduce the liquid level in the separator. If the
liquid interface level in the tubular separator 6 falls, the pump
can be slowed or shut down to generally maintain the desired liquid
interface level.
[0025] The preferred hydraulic pump and/or control system typically
has a relatively slow response time, e.g., at least about 20
seconds and more typically about 60 seconds. This is especially
true if portions of the control system are located at the surface
requiring signals (e.g., fluid pressure or electrical signals) to
travel from a deep subsea location to the surface and/or the power
fluid to be delivered from the surface to drive the hydraulic pump
at the subsea location. The elongated height of vertical separator
6 (shown in FIG. 2) or tubular separator 6 (shown in FIG. 1) allows
a wide variation in liquid levels, allowing response times to vary
to as much as 120, but more typically no more than about 180
seconds.
[0026] An advantage of the inventive separation system is
reliability. The preferred embodiment comprises hydraulic pumps to
avoid potential problems with electric-driven submersible pumps,
e.g., power cable insulation breakdown, shorting, cooling surface
contamination, galvanic corrosion, and other reliability problems.
The use of power fluid components located at the surface makes
these components easily accessible for maintenance and repair.
Avoiding the need for control valves by controlling the speed of
the hydraulic pump assembly 9 avoids potential problems of stuck
valves, loss of control valve signals, contamination blockage of
the control valves, and other valve reliability problems. Using
tubular sections for the riser and tubular separator assemblies
reduces potential damage by improper handling and improper
connection designs. The use of tubular sections also makes for ease
of handling, since rig crews are familiar with this type of
equipment. Placing the essentially vertical riser on top of the
nominally vertical tubular separator allows direct maintenance and
repair access to the separator using wire line tools or other
reliable well maintenance and repair procedures and tools well
known in the art.
[0027] Other advantages of the invention are improved efficiency
and performance. The lack of control valves in the preferred
embodiment avoids a pressure loss associated with control valves.
The relatively open design of the tubular separator and direct
coupling of the riser avoids additional losses. In addition to
acceptable fluid pressure losses, the swirling motion of the fluids
in the tubular separator results in good separation efficiency,
especially for two phase mist flow, which tends to be difficult to
separate in horizontal separators.
[0028] FIG. 2 shows a schematic side view of an alternative
embodiment of the inventive subsea fluid delivery system 2 directly
connected to a well tubular 4 extending from an offshore oil &
gas well 3 penetrating an underground reservoir R. Although the
inventive fluid delivery system 2 shown may be connected to other
onshore or offshore wells in shallower water depths penetrating
reservoirs at various pressures, the system is expected to be most
applicable to deep offshore wells penetrating low pressure
reservoirs R and located in deepwater locations, especially
ultra-deep water locations. Low pressure reservoirs is herein
defined as having a static pressure of less than the head pressure
of sea water at about the depth under sea level where the reservoir
is located. Even if a reservoir is initially not classified as a
low-pressure reservoir, commercial production may cause the
reservoir pressures to decline over time so that the reservoir,
especially near commercial depletion, is classified as a
low-pressure reservoir at a later time.
[0029] The offshore or subsea well 3 has one or more strings of
tubular sections 4 that extend generally downward from at or near a
mudline level ML through formation F to at least a reservoir R with
the tubulars typically cemented in place. The offshore well 3 may
produce a mixed phase fluid, e.g., a crude oil/condensate and
natural gas mixture. The well tubular sections 4 are fluidly
connected to an inlet port of vertical separator 6 having at least
two outlets, an upper outlet connected to a riser assembly 8 and a
lower outlet connected to a pump assembly 9. Because vapor removal
is via a relatively open gas riser 8a and the liquid is removed by
pump assembly 9, back-pressure on the well 3 can be reduced to as
little as a few psig or the back-pressure generated by a column of
low pressure gas extending from near the mudline to the surface
level SL. Although internal pressures in the vertical separator 6
can be as much as 5000 psig or more, they more typically range from
about 50 psig to several thousand psig. For very low pressure or
depleted reservoirs, vertical separator pressures may be no more
than about 500 psig or even 200 psig.
[0030] The collected and pressurized liquids from pump assembly 9
are typically pumped to the surface by increasing the pressure to
at least that required to overcome the back-pressure generated by a
column of separated liquid extending from near the mudline to the
surface. The riser/separator configuration allows low pressure
liquid and/or vapor fluid streams to be produced from the formation
F or, in a similar alternative embodiment, low pressure liquid and
vapor sources at the surface to be injected to a low pressure
reservoir. In contrast to prior art multiphase pumping systems, the
direct connection of the generally vertical riser and separator
promotes efficiency and availability of the oil and gas production
system. When coupled with a preferred hydraulic pump, the inventive
system allows simplified operation over a wide variety of varying
inflow conditions.
[0031] In contrast to the embodiment shown in FIG. 1, the offshore
well 3 in FIG. 2 directly supplies mixed-phase fluid flow as input
to the vertical separator 6 through an extended nozzle 12 that
protrudes into vertical separator. In alternative embodiments,
similar vertical separators, risers, and/or pumped fluid delivery
systems may also be supplied by multi-phase flow pipelines, subsea
solution mining wells, geothermal wells, and other subsea sources
of a fluid mixture requiring some type of separation.
[0032] The subsea well 3 typically comprises several types of well
tubulars 4, e.g., a casing string, a liner string, and a production
string. Some of the tubular sections can have nominal diameters of
30 inches (76.2 cm) or 36 inches (91.4 cm) or more, but a typical
well tubular connected to the separator 6a has a nominal diameter
typically less than about 13 inches (33.0 cm).
[0033] A connector 5 is used to attach well tubular 4 to a vertical
separator 6. The connector 5 not only provides a duct-like
passageway for fluids, but at least also partially supports
vertical separator 6. Although connector 5 is typically weldably
connected to well tubular 4 and the vertical separator 6, bolted,
threaded, or other means for connecting the well tubular to the
vertical separator may be used. Because of potentially severe
bending and other loads on the connector 5, the connector typically
has a wall thickness greater than the vertical separator 6, well
tubulars 4, and/or the tubular riser sections 7 extending down from
the ship or surface platform S.
[0034] Both the tubular separator 6 shown in FIG. 1 and the
vertical separator 6 shown in FIG. 2 can be distinguished from
prior art horizontal separators. For example, the separators 6
include a two-phase fluid inlet 12 imparting a flow direction
typically having a radial component and a tangential component. The
fluid inflow impinges on the internal walls of vertical separator
6, causing a generally swirling internal fluid flow around a
nominally vertical centerline. Separation is typically
accomplished, at least in part, by the swirling motion that tends
to throw denser fluids (e.g., liquid droplets) outwardly. The
swirling liquid or other denser fluids coalesce on the walls and
then gravity-flow downwardly towards outlet line 11 while the
less-dense swirling fluids (e.g., gases) "float" upward and inward
to be withdrawn from an upper and more central outlet connected to
the vapor riser assembly 7.
[0035] Other types of separation methods may be used to supplement
the essentially open, swirling action previously described for the
vertical separator and tubular separator 6, e.g., providing (within
the vertical separator) tortuous fluid paths, baffles, trays,
screens, hydrocyclones, or other internal components. Some of these
other separation devices and methods depend at least in part on
differences in fluid wetting properties providing added "wetted"
surface area to supplement extended height/swirling action of the
vertical separator or tubular separator 6. These supplementary
separation devices may be removable (e.g., attached to a removable
fluid inlet 12) or located at or near the walls of the vertical
separator or tubular separator 6 so as not to interfere with the
generally open interior of the separator.
[0036] Because of the internal swirling fluid motions, vertical
orientation, and elongated interior shape of vertical separator or
tubular separator 6, the separated liquid (or denser-fluid-phase)
interface level within the separator may be varied over most of the
entire height of the separator with little or no adverse impact on
separation efficiencies. In addition, adding to the elongated
height of the vertical separator or tubular separator 6 allows each
fluid phase entering the separator more time within the separator
before separately exiting, thereby improving separation
efficiency.
[0037] In one embodiment with limited flowrates and/or not
requiring extremely low back-pressure operation, the vertical
separator 6 is similar to the tubular separator 6 in that it is
composed of one or more well or riser tubular sections having thick
walls. Use of available tubular section is possible since the
nominal horizontal dimension or diameter of the vertical separator
in this embodiment is equal to or less than the nominal diameter of
available large risers, drill pipe, and/or other well tubular
sections and the wall thickness is sufficient to withstand the
differences in external and internal pressures. This allows common
tools and/or procedures to be used for the vertical separator 6 and
other tubulars, simplifying handling, installation, maintenance and
repair. In other applications where even lower pressure and higher
flowrates require larger, thicker-walled construction of a vertical
separator 6, e.g., over 36 inches (91.4 cm), especially over 48
inches (121.9 cm) in nominal diameter with more than a two inch
(5.08 cm) wall thickness, cylindrically-shaped and welded forging
sections can be used instead of pipe or other well tubulars.
[0038] The pump assembly 9 is connected to and supplied by the
liquid (or more-dense-phase) fluid outlet 11 of vertical separator
6. After the pump typically increases the pressure of the liquid to
about the external (or seawater) head pressure at the subsea
location or at least the head pressure of the pressurized liquid at
that location. The discharge line 14 typically ranges from about 2
to 12 inches (5.08 to 30.5 cm) in diameter and may use thinner wall
tubing or piping than the fluid outlet line 11. The discharge line
14 transfers the separated and pressurized liquid to other fluid
handling devices, e.g., liquid storage facilities on the surface
ship S. The liquid outlet line 11, discharge line 14, and hydraulic
pump assembly 9 are at least partially supported by a piled or
cemented footing foundation C located at or near the sea floor or
mudline ML.
[0039] Pressurized power fluid (e.g., water) to drive the preferred
hydraulic pump assembly 9 can be supplied from a surface pump or
pressurized liquid supply at the surface. The pumped or otherwise
pressurized liquid is conducted to the hydraulically driven pump
assembly 9 through at least one pump tubing line PT, more typically
a supply and return tubing pair. The tubing line(s) PT are
characteristically composed of carbon steel, but may be also be
composed of other materials.
[0040] The riser assembly 7 is connected to the vapor or less dense
fluid outlet of the vertical separator 6. The riser assembly 7 is
at least partially supported by a buoyancy can 10, but may also be
supported by ship S, a buoy, platform or other means for supporting
the riser assembly.
[0041] In one embodiment, riser assembly 7 comprises nominal 30-50
foot (9.14-15.2 meter) sections of 10-14 inch (25.4-35.6 cm)
nominal diameter N-80 pipe having a nominal wall thickness of
3/4-11/4 inches (1.90-3.18 cm). Besides the riser sections 8, the
riser assembly 7 may be composed couplings, instrumentation and
control cabling/hydraulic fluid tubing. Typically, a minimum
internal diameter of at least about 4 inches (10.2 cm), preferably
at least about 6 inches (15.2 cm), is maintained to allow cable
tools to be lowered through the riser assembly 7 and vertical
separator 6.
[0042] The mixed fluid inlet 12 of the vertical separator can
include a removable protruding and offset nozzle, but may also
include deflectors, baffles, and other devices to generate a
swirling motion. Removability of the fluid inlet 12 allows cable
tool access to the directly-connected well 3, and adjustment and/or
replacement of the fluid inlet/nozzle for different quality fluid
mixtures.
[0043] FIG. 2 shows a floating drill ship, barge, or other surface
platform S fluidly connected to the buoyancy can 10 and the
vertical separator 6 with a portion of the riser assembly 7. In
alternative embodiments, the riser assembly 7 may be connected to a
ship S that is horizontally offset from the over-well position
shown. In other embodiments, the drill ship may be supplemented or
replaced by a spar, tension leg platform, semi-submersible vessel,
or other surface fluid handling facility. In still other
embodiments, instead of the vapor outlet of the vertical separator
6 being directly connected to a riser assembly 7, the riser
assembly can include an emergency dump valve (e.g., similar to the
second or emergency port and valve ED attached to the tubular
separator 6 as shown in FIG. 2) connected to buoyed flare stack,
temporary storage tanks (e.g., bladders), a secondary vapor
handling facility, or other fluid-handling devices.
[0044] Still other alternative embodiments are possible. These
include: a series of vertical separators designed for different
flow and fluid quality ranges instead of a single separator (e.g.,
a first separator efficiently separating a portion of the range of
expected fluid conditions and assisting in separating the remainder
of the inputs prior to being more fully separated in a subsequent
separator), using a pump within the vertical separator instead of a
pump external to the separator, using a mixer or other
pre-treatment of the multi-phase fluid upstream of the vertical
separator (e.g., to smooth out slug flow), having at least a
portion of the pump and separator system composed of hardened
materials (e.g., to handle slurry flow), and having the vertical
separator placed substantially within or below a bladder or other
type of gaseous containment enclosure allowing gases to be vented
during system upsets.
[0045] Although the preferred embodiment of the invention has been
shown and described, and some alternative embodiments also shown
and/or described, changes and modifications may be made thereto
without departing from the invention. Accordingly, it is intended
to embrace within the invention all such changes, modifications,
and alternative embodiments as fall within the spirit and scope of
the appended claims.
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