U.S. patent application number 12/871730 was filed with the patent office on 2012-03-01 for method, system, and production and storage facility for offshore lpg and lng processing of associated gases.
This patent application is currently assigned to CHEVRON U.S.A. INC.. Invention is credited to Edwin J. Kolodziej.
Application Number | 20120047942 12/871730 |
Document ID | / |
Family ID | 45695327 |
Filed Date | 2012-03-01 |
United States Patent
Application |
20120047942 |
Kind Code |
A1 |
Kolodziej; Edwin J. |
March 1, 2012 |
METHOD, SYSTEM, AND PRODUCTION AND STORAGE FACILITY FOR OFFSHORE
LPG and LNG PROCESSING OF ASSOCIATED GASES
Abstract
A method, system and production and storage facility is
disclosed for offshore LPG and LNG processing of associated gases.
The system includes a first production facility and a second
production and storage facility. The first facility receives and
processes produced fluids to produce crude oil, water and rich
associated gases. The second facility includes a gas treatment unit
for processing the rich associated gases to remove contaminants and
produce a treated gas stream of hydrocarbons. The second facility
also has at least one LPG and/or LNG production unit for producing
one of LPG and/or LNG from the treated gas stream. At least one
storage tank on the second facility stores at least one of the LPG
and/or LNG. The second production facility may be a retrofit LNG or
LPG carrier. The treatment unit, LPG and/or LNG production and
needed offloading facilities and equipment can be added to the
LNG/LPG carrier. Existing storage tanks can be modified as needed
or else new storage tanks can also be added.
Inventors: |
Kolodziej; Edwin J.;
(Tomball, TX) |
Assignee: |
CHEVRON U.S.A. INC.
San Ramon
CA
|
Family ID: |
45695327 |
Appl. No.: |
12/871730 |
Filed: |
August 30, 2010 |
Current U.S.
Class: |
62/611 ;
62/51.1 |
Current CPC
Class: |
B63B 27/24 20130101;
F25J 2205/04 20130101; F25J 2220/64 20130101; F25J 2200/04
20130101; C10L 3/102 20130101; F25J 2260/60 20130101; F25J 3/0233
20130101; F25J 2200/70 20130101; F25J 3/0209 20130101; F25J 2215/64
20130101; F25J 3/0242 20130101; C10L 3/12 20130101; F25J 1/004
20130101; F25J 2215/04 20130101; F25J 3/0247 20130101; F25J 2215/66
20130101; F25J 1/005 20130101; F25J 2200/02 20130101; F25J 1/023
20130101; F25J 1/0022 20130101; F25J 2260/20 20130101; F25J 1/0278
20130101; F25J 1/0072 20130101; F25J 1/0035 20130101; F25J 2240/02
20130101; F25J 1/0204 20130101; F25J 1/0208 20130101; F25J 2290/72
20130101 |
Class at
Publication: |
62/611 ;
62/51.1 |
International
Class: |
F25J 1/00 20060101
F25J001/00; F25B 19/00 20060101 F25B019/00 |
Claims
1. A method for separating produced fluids containing hydrocarbons
received from an offshore subterranean reservoir, the method
comprising: (a) receiving a rich associated gas stream on an
offshore production and storage facility and removing at least one
of acid gases, water vapor and mercury from the rich associated
gases to produce a treated gas; (b) producing at least one of
liquefied petroleum gas (LPG) and liquefied natural gas (LNG) from
at least a portion of the treated gas; and (c) storing the at least
one of LPG and LNG in at least one of a liquefied petroleum gas
(LPG) storage tank and a liquefied natural gas (LNG) storage tank
on the production and storage facility.
2. The method of claim 1 wherein: LPG is produced in step (b); and
LPG is stored in step (c) in at least one LPG storage tank located
on the production and storage facility.
3. The method of claim 1 wherein: LNG is produced in step (b); and
LNG is stored in step (c) in at least one LNG storage tank located
on the production and storage facility.
4. The method of claim 1 wherein: LPG and LNG are both produced on
the production and storage facility in step (b).
5. The method of claim 4 wherein: LNG is stored in at least one LNG
storage tank and LPG is stored in at least one LPG storage
tank.
6. The method of claim 1 wherein: acid gases are removed from the
rich associated gases in step (a).
7. The method of claim 1 wherein: the production and storage
facility is one of an LPG carrier or an LNG carrier which is
retrofit to include a gas treatment unit for removing at least one
of acid gases, water vapor and mercury from the rich associated
gases and which includes at least one of an LPG and LNG production
unit to produce one of LPG and LNG.
8. An offshore production and storage facility comprising: a
support structure; a gas treatment unit which is adapted to receive
rich associated gases, the gas treatment unit mounted on the
support structure and being capable of removing at least one of
acid gases, water vapor and mercury from associated gases to
produce a treated gas stream; at least one of an LPG production
unit and an LNG production unit mounting on the support structure
and being capable of producing at least one of LPG and LNG from at
least a portion of the treated gas stream; and at least one storage
tank on the support structure to store at least one of the LPG and
LNG.
9. The offshore production and storage facility of claim 8 wherein:
the at least one of an LPG production unit and an LNG production
unit is a LPG production unit; and the at least one storage tank
includes at least on one storage tank for storing LPG.
10. The offshore production and storage facility of claim 9
wherein: the at least one of an LPG production unit and LNG
production unit is an LNG production unit; and the at least one
storage tank includes at least on one storage tank for storing
LNG.
11. The offshore production and storage facility of claim 9
wherein: the at least one of an LPG production unit and LNG
production unit includes both an LPG production unit and an LNG
production unit.
12. The offshore production and storage facility of claim 11
wherein: at least one storage tank includes at least on one storage
tank for storing LNG and at least one storage tank for storing
LPG.
13. The offshore production and storage facility of claim 9
wherein: the supporting structure is a floating vessel.
14. The offshore production and storage facility of claim 13
wherein: the floating vessel is one of a retrofit LNG carrier and a
retrofit LPG carrier.
15. A system for separating produced fluids containing hydrocarbons
received from an offshore subterranean reservoir, the system
comprising: a first offshore production facility and a second
offshore production and storage facility and a first conduit
fluidly connecting the first and second facilities; the first
offshore production facility being adapted to receive produced
fluids from at least one subterranean reservoir and having
facilities for separating the produced fluids into crude oil, water
and rich associated gases; the second offshore production facility
including: a gas treatment unit in fluid communication with the
first conduit to receive the rich associated gases from the first
production facility and capable of removing at least one of acid
gases, water vapor and mercury from the rich associated gases to
produce a treated gas stream; at least one an LPG production unit
capable of producing LPG from a portion of the treated gas stream
and one of an LNG production unit capable of producing LNG from a
portion of the treated gas stream; and at least one storage tank
for storing at least one of LPG or LNG on the second production and
storage facility.
16. The system of claim 15 wherein: the one an LPG production unit
capable of producing LPG from a portion of the treated gas stream
and one of an LNG production unit capable of producing LNG from a
portion of the treated gas stream includes an LPG production
unit.
17. The system of claim 15 wherein: the one an LPG production unit
capable of producing LPG from a portion of the treated gas stream
and one of an LNG production unit capable of producing LNG from a
portion of the treated gas stream includes an LNG production
unit.
18. The system of claim 15 wherein: the at least one an LPG
production unit capable of producing LPG from a portion of the
treated gas stream and an LNG production unit capable of producing
LNG from a portion of the treat gas stream includes both an LPG
production unit and an LNG production unit.
19. The system of claim 18 wherein: the at one storage tank for
storing at least one of LPG or LNG includes at least one storage
tank for storing LPG and at least one storage tank for storing LNG
located on the second production and storage facility.
Description
BACKGROUND
[0001] 1. Technical Field
[0002] The present disclosure relates to offshore production
facilities including floating production, storage and offloading
(FPSO) vessels and floating liquefied natural gas (FLNG) vessels
that process produced fluids from undersea subterranean
hydrocarbon-bearing reservoirs.
[0003] 2. Description of Related Art
[0004] Produced fluids from hydrocarbon containing subterranean
reservoirs often contain mixtures of crude oil, water, entrained or
associated gases and other contaminants. Associated gas production
streams separated from the remainder of the produced fluids must be
processed to enable offshore crude oil production. Typically, the
associated gases include hydrocarbons containing one to five or
more carbon atoms such as methane (C.sub.1), ethane (C.sub.2),
propane (C.sub.3), butane (C.sub.4) and heavier condensates
(C.sub.5+). The associated gases often contain other unwanted
constituents such as acid gases including carbon dioxide (CO.sub.2)
and hydrogen sulfide (H.sub.2S), water and contaminants such as
mercury (Hg).
[0005] It is desirable to extract hydrocarbon components from the
associated gas streams and produce liquefied petroleum gas (LPG),
predominantly C.sub.3 and C.sub.4 gases, and/or produce liquefied
natural gas (LNG) (predominantly C.sub.1 and C.sub.2 gases), as
these saleable liquid products provide high market value. The
offshore LPG product extraction is typically performed on either
(1) an offshore fixed or floating oil and gas processing platform,
or (2) an oil FPSO (floating production, storage and offloading)
facility having additional gas processing facilities (oil/LPG
FPSO). For both options, the valuable LPG products are offloaded to
a separate floating storage and offloading vessel (FSO), or routed
through a pipeline to shore. Currently, no LNG production
facilities exist as part of an offshore processing platform or oil
FPSO. Instead, lean residue gas is often reinjected into a
subterranean formation, or else is routed to a pipeline for gas
sales or to shore where LNG production takes place.
[0006] In the offshore platform processing option, separate
floating storage vessels, or separate export pipelines to shore,
are required for transport of the crude oil/condensate and LPG
products. In the oil/LPG FPSO option, the combination of oil/gas
production and LPG processing facilities, along with the onboard
oil/condensate/LPG storage, creates a very large and complex
vessel. An example of a large oil/LPG FPSO vessel is a vessel
operated by ConocoPhillips in the Belanak Field, South Natuna,
Indonesia.
[0007] For both of the above offshore oil and gas processing
options, the addition of LPG production, LNG production and storage
facilities adds considerably to complexity and cost. There is a
need for an offshore oil and LPG processing alternative, which can
be provided at a low cost.
[0008] A number of patents have suggested that natural gas be
pretreated to remove undesirable contaminants on a first production
vessel. These contaminants include acid gases, water and components
such as mercury. Subsequently, dedicated second floating LNG
production vessels can be used to liquefy gases into LNG. Examples
of such patents include U.S. Pat. Nos. 5,025,860, 6,003,603 and
6,889,522. In order to be commercially feasible, the first
production vessels must be of sufficient size to accommodate gas
processing equipment needed to clean up or treat hydrocarbon
containing gases containing acid gases, water and other
contaminants, prior to treated gases being sent to the second
production vessel for liquefaction of natural gas to produce
LNG.
SUMMARY
[0009] A production and storage facility, a method, and a system
for offshore LPG and/or LNG processing of associated gases is
disclosed. The offshore production and storage facility comprises a
support structure that supports a gas treatment unit, at least one
of an LPG and/or LNG production unit, and at least one storage tank
for storing one LPG and LNG. The gas treatment unit is adapted to
receive rich associated gases and is capable of removing at least
one of acid gases, water vapor and mercury from the rich associated
gases to produce a treated gas stream. In one embodiment, the LPG
production unit produces LPG. In another embodiment, both LNG and
LPG are produced on the facility. One or both of LPG and LNG may be
stored on the facility. The facility may be a retrofit LNG or LPG
carrier that has been converted to include the gas treatment unit
and the LNG and/or LPG production units and any necessary
offloading facilities or equipment.
[0010] The method provides for receiving a rich associated gas
stream separated from produced fluids containing hydrocarbons
received from an offshore subterranean reservoir. The rich
associated gas stream is received on an offshore production and
storage facility and at least one of acid gases, water vapor and
mercury are removed from the rich associated gases to produce a
stream of treated gas. At least one of liquefied petroleum gas
(LPG) and liquefied natural gas (LNG) are produced from at least a
portion of the treated gas. The LPG and/or LNG are then stored on
the offshore production and storage facility in one or more storage
tanks.
[0011] The system is designed for separating produced fluids
containing hydrocarbons received from an offshore subterranean
reservoir. The system includes a first offshore production facility
and a second offshore production and storage facility and a conduit
fluidly connecting the first and second facilities. The first
offshore production facility is adapted to receive produced fluids
from at least one subterranean reservoir and has facilities for
separating the produced fluids into crude oil, water and rich
associated gases.
[0012] The second offshore production facility includes a gas
treatment unit, at least one of an LPG and LNG production unit, and
at least one LPG or LNG storage tank. The gas treatment unit is in
fluid communication with the conduit to receive the rich associated
gases from the first production facility and is capable of removing
at least one of acid gases, water vapor and mercury from the rich
associated gases to produce a treated gas stream. At least one of
an LPG and LNG production unit is capable of producing LPG and/or
LNG from at least a portion of the treated gas stream. LPG and/or
LNG produced may be stored on the second offshore production
facility.
[0013] The second production and storage facility may be an LPG
carrier or an LNG carrier which has been retrofit to include a gas
treatment unit for removing at least one of acid gases, water vapor
and mercury from the rich associated gases and which includes at
least one of an LPG and an LNG production unit to produce one of
LPG and LNG. Existing storage tanks can be retrofit to store LNG
and/or LPG as needed. Existing or newly added offloading facilities
and equipment may be used to offload the LPG and/or LNG.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] These and other objects, features and advantages of the
embodiments disclosed will become better understood with regard to
the following description, pending claims and accompanying drawings
where:
[0015] FIG. 1 is a schematic drawing of a system wherein
hydrocarbon containing fluids are produced from one or more subsea
reservoirs with the produced fluids being separated into crude oil,
water and rich associated gases on a first production facility, and
compressed rich associated gases being sent to and processed on a
cooperating second production and storage facility to remove
contaminants in the rich associated gases to produce a treated gas
stream which yields LPG and/or LNG;
[0016] FIG. 2 is a block diagram of the first production facility
that cooperates with the adjacent second production and storage
facility to produce LPG for offloading to a LPG carrier. In
addition, this second production and storage facility produces
C.sub.5+ liquid condensate that is returned to the first production
facility for blending with crude oil, and residue gas which is also
returned to the first production facility;
[0017] FIG. 3 is a schematic diagram of a portion of the second
production and storage facility of FIG. 2 used to treat the rich
associated gases to remove acid gases, water and other contaminants
and then the treated gases are further processed into residue gas,
LPG, and C.sub.5+ liquid condensates;
[0018] FIG. 4 is a block diagram of another embodiment of a first
production facility that produces rich associated gases from
produced fluids and sends the rich associated gases to a second
production and storage facility for treatment or removal of
contaminants to produce a treated gas stream which is processed
into LNG, LPG, and C.sub.5+ liquid condensate; and
[0019] FIG. 5 is a schematic diagram of an LNG production unit used
on the second production and storage facility of FIG. 4 to produce
LNG, predominantly C.sub.2+ liquids and residue gas from treated
associated gases; the C.sub.2+ liquids are then converted to LPG
and C.sub.5+ liquid condensates.
DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS
[0020] For the purposes of this disclosure, the following terms
shall have following meanings:
[0021] Condensate refers to liquids recovered from rich associated
gases having predominantly C.sub.5+ hydrocarbons;
[0022] LNG (Liquefied natural gas) refers to a cryogenic fluid
comprising predominately methane (C.sub.1) with lesser amounts of
C.sub.2+ hydrocarbons, which is sufficiently cold to remain in a
liquid state at or near atmospheric pressures;
[0023] LPG (Liquefied petroleum gas) refers to fluids comprising
predominately C.sub.3 and C.sub.4 hydrocarbons, which can either be
refrigerated to remain liquid at near atmospheric pressures or
pressurized to remain liquid at atmospheric temperature;
[0024] Residue gas refers to gases recovered from LPG or LNG
processing that contain primarily C.sub.1 and C.sub.2
hydrocarbons;
[0025] Rich associated gases refers to gases separated from
hydrocarbon containing produced fluids on a first production
facility, including crude oil and water, which contain
contaminants, such as acid gases, water vapor and mercury, and
gaseous hydrocarbons including C.sub.1, C.sub.2, C.sub.3, C.sub.4
and C.sub.5+ components;
[0026] Lean gases refers to gases containing primarily C.sub.1 and
C.sub.2 from which heavier hydrocarbon components C.sub.3+ have
been substantially removed.
[0027] Illustrative embodiments are described below. In the
interest of clarity, not all features of an actual embodiment are
described in this specification. It will of course be appreciated
that in the development of any such actual embodiment, numerous
implementation-specific decisions must be made to achieve the
developers' specific goals, such as compliance with system-related
and business-related constraints, which will vary from one
implementation to another. Moreover, it will be appreciated that
such a development effort might be complex and time-consuming, but
would nevertheless be a routine undertaking for those of ordinary
skill in the art having the benefit of this disclosure.
[0028] Offshore Production Facility Producing Crude Oil and Rich
Associated Gases
[0029] FIG. 1 shows an exemplary embodiment of a system 20 wherein
first and second cooperating offshore production facilities 22 and
24 are used to process produced fluids from one or more
subterranean reservoirs, into marketable products including crude
oil, liquefied petroleum gas (LPG) and/or liquefied natural gas
(LNG), and possibly lean residue sales gas. First production
facility 22 receives produced fluids from one or more subterranean
reservoirs 26a, 26b and 26c by way of a subsea flow lines 30a, 30b,
30c that are fluidly connected to a manifold 32. Manifold 32 is
connected to a flow line 34 that leads to a riser 36 that connects
to first production facility 22. Tether lines 40 moor first
production facility 22, which in this embodiment, is a floating
production, storage and offloading FPSO vessel. By way of example
and not limitation, first production facility 22 could also be a
fixed or floating platform, a jacketed platform or a
semi-submersible platform.
[0030] Sales export line or pipeline 42 leads to a sales facility
44 that receives processed fluids from first or second production
and storage facility 22 or 24. Import line 46 is used to import
rich associated gas to second facility 24 from first production
facility 22. Residue gas line 48 and condensate line 50 bring
residue gas and liquid condensate, respectively, from second
production and storage facility 24 back to first production
facility 22.
[0031] The produced fluids 26 are separated into crude oil, water
and gases using separation and compression facilities 52 on first
production facility 22. These gases 70 are referred to as
"associated gases" and are sent on to second production and storage
facility 24 for further gas treatment and separation into
hydrocarbon products having differing carbon chain lengths.
[0032] In this particular exemplary embodiment, separation facility
52 separates the gases and liquids using a primary multi-stage
separator train 54 which includes a three-phase separator
(oil/water/gas) followed by a secondary oil/gas separator. Liquids
are sent to an optional water-crude oil separator 60 where water is
separated from crude oil. Secondary water separation from crude oil
may be carried out using a water treatment apparatus 62 for gravity
separation or may include a centrifuge. The water is sufficiently
treated such that it meets environmental standards appropriate for
disposal of the treated water overboard into the sea. Those skilled
in the art of water treatment will appreciate other combinations of
equipment can also be used to treat the produced fluids to produce
water ready for disposal.
[0033] The associated gases 70 are separated from the crude oil and
water by passing the produced fluids through the series of
separators comprising separator train 54 that operate at decreasing
pressures allowing entrained gases to escape from the crude oil
and/or water. These associated gases are then typically compressed
in a gas compression facility 58 from the various separators, to a
common higher pressure suitable for gas export or gas reinjection.
Ideally, the crude oil has enough gases removed such that only
small amounts of hydrocarbon gases are left in the crude oil to
dissipate at atmospheric pressure. Such crude oil is referred to as
"stabilized oil." Techniques for producing stabilized crude oil at
an oil production facility are well known.
[0034] The stabilized crude oil is stored in one or more crude oil
storage tanks 64 located on first production facility 22. The
stabilized crude oil preferably has a vapor pressure of less than
14.7 psia (101 kPa), and even more preferably less than 5 psia (34
kPa). See U.S. Pat. No. 6,541,524 for more details on crude vapor
pressure regulations for crude oil tankers. A crude oil tanker 68
may be used to transport the crude oil to a distant location for
refining operations. A conventional crude oil transport conduit 69
may be used to convey the crude oil from first production facility
22 to tanker 68.
[0035] LPG Production and Storage Facility
[0036] Referring now to FIG. 2, a stream of rich associated gases
70 is transferred by import line 46 to second production and
storage facility 24 with an arrival pressure in the range 1000-1200
psig (6900-8300 kPa). In one embodiment, as shown in FIG. 2, the
stream of feed or rich associated gases 70 is processed to produce
liquefied petroleum gas (LPG) 74 comprising predominantly C.sub.3
and C.sub.4 components (propane and butane), a residue gas 72
comprising primarily C.sub.1 and C.sub.2 gases, and a stream of
C.sub.5+ liquid condensate 76. It is further envisioned that the
propane and butane could further be separated from one another and
stored in separate propane and butane storage tanks on second
production and storage facility 24 if so desired.
[0037] Rich associated gases 70 are first pretreated using a gas
treatment unit 80 to remove, by way of example and not limitation,
one or more of contaminants such as acid gases (CO.sub.2,
H.sub.2S), water vapor and other contaminants such as mercury (Hg).
Contaminants should be sufficiently removed from the stream 70 of
rich associated gases to produce a treated gas stream 82 that can
be readily processed into LPG and/or LNG. Below are exemplary, and
not limiting, levels below which the stream 70 of rich associated
gases may be treated to produce treated gas stream 82 of suitable
specification:
TABLE-US-00001 TABLE 1 Level of Contaminants in Treated Gas Stream
Contaminant Maximum amount of Contaminant Component Component in
Treated Gas Stream Carbon dioxide (CO.sub.2) <50 parts per
million by volume; Hydrogen Sulfide (H.sub.2S) <3 parts per
million by weight; Water vapor (H.sub.20) <1 part per million by
weight; Mercury (Hg) <0.1 micrograms/square meter.sup.3
[0038] In the embodiment shown in FIG. 2, at least a portion of the
residue gas 72 can be combusted to produce heat and energy for
machinery and utilities on second production and storage facility
24. The residue gas 72 can also be sent by return line 48 back to
the first production facility 22 for recompression and sales gas
export or reinjection into a subterranean reservoir. Also, a
portion of the residue gas 72 can be combusted on first production
facility 22. Extra compression units (not shown) may be added to
second production facility 24 as needed for recompression and gas
export or reinjection of the residue gas 72.
[0039] LPG 74 produced in LPG production unit 84 is routed to one
or more LPG storage tanks 94 located on second production and
storage facility 24. Periodically, LPG 74 is removed from the one
or more LPG storage tanks 94 using conventional LPG transfer
equipment 100 and offloaded to a LPG carrier 104 for transport to a
market destination for LPG 74.
[0040] Referring now to FIG. 3, additional details are shown for
the pretreatment and separation of the rich associated or feed
gases 70. Feed or associated gas 70 is received by gas treatment
unit 80. Acid gases such as carbon dioxide (CO.sub.2) and/or
hydrogen sulfide (H.sub.2S) are removed from rich associated gases
70. By way of example and not limitation, another acid gas that
might be removed includes carbonyl sulfide (COS). For removal of
carbon dioxide, a conventional amine solvent-based system 110 may
be used to strip CO.sub.2 and H.sub.2S from rich associated gas
stream 70. As another non-limiting example, a mole sieve based acid
gas removal system may be used. A prime consideration for all of
the equipment selected to be used on second production and storage
facility 24 is that that the equipment be compact and
lightweight.
[0041] Water vapor entrained in the gas stream may be removed such
as by using mole sieve dehydrator 114 to prevent freezing of water
vapor in a cryogenic section of LPG production unit 84. The gas
stripped of the acid gases and dehydrated is then routed to a
mercury removal system 118.
[0042] The stream 82 of treated gas is pre-cooled by passing
through a feed gas/residue gas heat exchanger 122. Feed gas heat
exchanger 122, in this exemplary embodiment, is a brazed aluminum
plate fin type, with treated gas 82 flowing through a coil section
124, and a cold residue gas passing through a coil section 126, and
condensed liquids passing through a coil section 128. The precooled
stream 82 of treated gas is routed through conduit 130 to a cold
separator 140 for separation of a predominant C.sub.1 expanded cold
vapor stream and a C.sub.2+ natural gas liquid stream. The cold
vapor stream flows through conduit 142 to a turboexpander unit 132,
which yields an expanded cryogenic stream that flows through
conduit 134 to the top section of a deethanizer column 144. The
stream of liquids C.sub.2+ from the cold separator 140 is throttled
through a pressure let down valve 135, and flows through coil
section 128 of the feed gas heat exchanger 122, and through a
conduit 136 into the lower section of the deethanizer column 144.
Deethanizer column 144 yields a predominantly C.sub.1, C.sub.2
overhead cold residue gas stream that passes through gas conduit
146 to heat exchanger 122, and emerges as lean residue gas 72 which
is exported through conduit 48 from second production and storage
facility 24, net fuel gas needs used for combustion on second
production and storage facility 24.
[0043] Deethanizer column 144 yields a bottoms stream of heavier
components C.sub.3+ that are routed through a liquid conduit 150 to
a depropanizer column 152 in which the LPG (C.sub.3, C.sub.4)
fluids 74 are separated from the heavier stream 76 of C.sub.5+
liquid condensate. The deethanizer column 144 typically has an
internal condenser and thermosyphon reboiler (not shown). The
depropanizer column 152 has (not shown) an air-cooled overhead
condenser, reflux drum, reflux pumps, and thermosyphon
reboiler.
[0044] The LPG 74 (C.sub.3, C.sub.4) is then transferred to and
stored in one or more LPG tanks 94 adapted to store LPG. By way of
non-limiting examples, these LPG storage tanks may be of the Moss
spherical type tank, or self-supporting independent prismatic (SPB)
type A or type B tank. The C.sub.5+ condensate 76 is sent through
condensate export line 50 to be mixed and stored with the crude oil
in crude oil storage tank 64 on the first production facility 22.
As referenced above, the mixture of C.sub.5+ condensate 76 and
crude oil should meet industry specifications necessary for
transport of crude oil on crude oil tankers. As an alternative, the
C.sub.5+ condensate 76 may be used for combustion on second
production and storage facility 24 by boilers or other operational
equipment. If all of C.sub.5+ condensate is consumed on facility
24, then no export line 50 is necessary.
[0045] Floating LPG Production and Storage Facility
[0046] In one exemplary embodiment, second production and storage
facility 24 may be a floating LPG (FLPG) developed at relatively
low cost, by conversion of an existing LNG carrier vessel (such as
with Moss-type storage tanks), that is still within its design
service life. The FLPG production facility could also be developed
at relatively low cost, by conversion of an existing LNG or LPG
carrier vessel (such as with IHI self-supporting prismatic type B
(SPB)-type storage tanks), that is also still within its design
service life. By way of example and not limitation, the FLPG
production vessel might process a rich associated gas stream 70
with a flow rate in the range of 50-150 MMSCFD (1.4-4.2 million
cubic meters per day at 15.6.degree. C.). As another non-limiting
example, production facility 24 might process a rich associated gas
stream with natural gas liquids (C.sub.2+) content in the range
5-20% (mol.).
[0047] Deethanizer and depropanizer reboilers (not shown) can be
steam-driven to utilize the existing steam system on an LNG or LPG
carrier. The existing steam system may need to be upgraded for the
new implementation of producing LPG liquids and liquid condensates.
LPG storage tanks and tandem LPG offloading facilities on an
existing LPG carrier can be reused for the FLPG production
facility. LNG storage tanks on an existing LNG carrier can be
recertified for LPG service, and tandem LPG offloading facilities
added to the existing LNG carrier vessel, for the converted FLPG
production facility. Temporary storage tanks can also be added to
an existing LNG or LPG carrier for storing residual C.sub.5+ liquid
condensate which can be later combusted or transferred to a crude
oil tanker.
[0048] Electrical power generation equipment on an existing LPG or
LNG carrier can be reused for the FLPG production facility, with
additional electrical power requirements to be provided by a new
aeroderivative turbogenerator. Utility systems on an existing LPG
or LNG carrier (e.g., instrument, air, nitrogen, fuel gas,
firewater, etc.), and control and safety systems can be reused and
upgraded if needed, for the FLPG production facility. The existing
LPG or LNG carrier can be retrofitted with a turret mooring system,
designed for station keeping of the FLPG production facility. The
turret would have sufficient riser capacity for the associated gas
import line and lean residue gas and residual C.sub.5+ liquid
condensate export lines 48, 50.
[0049] LNG/LPG Production and Storage Facility
[0050] FIG. 4 shows an exemplary second embodiment of a system 200
including a first production vessel 202 and a second production
vessel 204. First production vessel 202 again may be an offshore
fixed or floating oil and gas processing platform, or an oil FPSO
vessel where rich associated gases 206 are produced and then
exported to second production vessel 204 with an arrival pressure
in the range 1000-1200 psig. Associated gases 206 are treated to
remove contaminants and converted into liquefied natural gas (LNG)
210, liquefied petroleum gas (LPG) 212 and liquid C.sub.5+
condensate 214. A stream of residue gas 216 is also produced.
[0051] Associated gases 206 are delivered from first production
facility 202 using an import line 222 to a gas treatment unit 224
on second production vessel 204 at an arrival pressure in the range
1000-1200 psig (6900-8300 kPa). Associated gases 206 are treated to
remove one or more of the components of acid gases (CO.sub.2,
H.sub.2S), water vapor, and contaminants such as Hg, to produce a
treated hydrocarbon gas stream 226 (see FIG. 5) that is delivered
by a gas conduit 230 to a liquefied natural gas (LNG) production
unit 232.
[0052] LNG production unit 232 produces LNG 210 along with a
predominantly C.sub.2+ stream of liquids and lean residue gas 216.
LNG production unit 232 and its operation will be described in
greater detail below with reference to FIG. 5. Produced LNG 210 is
first conveyed by a cryogenic conduit 234 to one or more cryogenic
LNG storage tanks 236. By way of example, and not limitation, these
LNG storage tanks may be of the Moss spherical type tank, or
self-supporting independent prismatic (SPB) type B tank. After
sufficient LNG 210 is produced to fill the LNG storage tanks, LNG
210 is transferred through a cryogenic conduit 240 and specialized
LNG transfer equipment 242 by way of a conduit 244 to an LNG
carrier 246, which transports the LNG 210 to distant markets. By
way of example and not limitation, such specialized LNG transfer
equipment 242 may include equipment such as is described in U.S.
Pat. Nos. 7,726,358 and 7,726,359.
[0053] A liquefied petroleum gas (LPG) production unit 250 receives
C.sub.2+ liquids from LNG production unit 232 by way of liquids
conduit 252. LPG production unit 250 separates C.sub.2, C.sub.3,
C.sub.4 liquids from heavier liquids to produce LPG 212 and
C.sub.5+ condensate 214. Equipment similar to that described above
with respect to FIG. 3, i.e., deethanizer column 144, and
depropanizer column 152, may be used by LPG production facility 250
to separate C.sub.2+ liquids into LPG 212 and C.sub.5+ condensate
liquids 214.
[0054] LPG 212 produced by LPG production unit 250 is conveyed by a
liquids conduit 256 to one or more LPG storage tanks 260. When
sufficient LPG 212 has been accumulated, LPG 212 is conveyed by a
liquid conduit 262 to LPG transfer equipment 264, and liquids
conduit 266 to a LPG transport vessel 268. LPG 212 can then be
transported by LPG transport vessel 268 to market locations.
[0055] As most of the lighter C.sub.1, C.sub.2 gases are converted
into LNG 210 by LNG production unit 232, a return or export line
for residue gas 216 is not absolutely required. Whatever residue
gas 216 is produced may be combusted on second production and
storage facility vessel 204 by boilers or other operational
equipment. Also, boil-off gas (BOG) from the production, storage
and transfer of LNG 210 may also be collected and combusted (not
shown). Alternatively, the residue gas 216 and/or BOG may also be
recompressed, and mixed with treated gas stream 230 from gas
treatment unit 224 and reprocessed by LNG production unit 232.
[0056] Liquid C.sub.5+ condensate 214 will be returned to first
production vessel 202 to be mixed with crude oil and stored in one
or more crude oil storage tanks 220. The mixture of crude oil and
condensate can then be offloaded to a crude oil tanker (not shown)
for transport to an onshore refinery.
[0057] FIG. 5 shows a more detailed embodiment of the exemplary LNG
production unit 232 as described above with reference to FIG. 4.
This LNG production unit utilizes a nitrogen expander loop
refrigeration process, which can also be configured as a compander
unit. The LNG production unit 232 should be compact in size and
lightweight, as deck space on, and weight capacity of, an offshore
structure is generally at a premium.
[0058] Treated gas 226 is introduced into LNG production unit 232.
First, a turboexpander 240 may be used to expand and precool
treated gas in conduit 228 prior being input into a cold box 280.
Cold box 280 has a "warm" section 282 and "cold" section 284. In
this particular embodiment, nitrogen expander loop equipment 286 is
used for refrigeration, which is detailed as follows. Relatively
warm nitrogen is delivered by a coil section 292 to a first stage
compressor 294 where nitrogen is compressed to a predetermined
interstage pressure and delivered to coil section 296. A cooler 300
is used for nitrogen compression intercooling, which utilizes sea
water as the cooling media. Nitrogen is compressed by a second
stage compressor 302 to a predetermined final discharge pressure
and sent to another coil section 304. The further compressed
nitrogen is again cooled by a second aftercooler 306. Additional
compression stages can be added if necessary. An electric motor 290
is used to drive both the first stage compressor 294 and second
stage compressor 302.
[0059] High-pressure nitrogen is routed by a coil section 308 into
the warm section of the cold box 282 for pre-cooling. The
pre-cooled nitrogen in coil section 308 is delivered to and rapidly
expanded in turboexpander 310 to cool the nitrogen to a low
temperature, i.e., such as below -270.degree. F. (-170.degree. C.).
The low pressure cold nitrogen is then routed to cold section 284
of the cold box 280 to provide liquefaction duty for a natural gas
separator gas stream 322 (described below). After the low pressure
cold nitrogen has been warmed by cooling the lean gas stream 322,
the nitrogen flows to the warm section of the cold box 280, to
provide cooling duty for expanded feed gas stream 228 and precooled
high pressure nitrogen loop stream in coil section 308. The
nitrogen then exits from cold box 280 and returns to coil section
292 to be recycled and recompressed again by first stage compressor
294.
[0060] Expanded treated gas stream 228 is further cooled in warm
section 282 of the cold box 280 and is delivered to natural gas
separator 320 that separates this stream into predominantly
C.sub.1, C.sub.2 lean gases carried by gas conduit 322 and a bottom
liquid stream of predominantly C.sub.2+. Extracted C.sub.2+ liquids
are passed out of LNG production unit 232 to be processed by LPG
production unit 250, as described above with reference to FIG.
4.
[0061] The lean gas stream in conduit 322 is passed back into cold
section 284 of the cold box 280 in preparation for liquefaction.
Upon exiting cold box 280, the liquefied lean gas stream is passed
through an expansion valve 324 to reduce the pressure for LNG
production and storage, and then routed to a cold separator 326.
LNG 210 is passed from the bottom of cold separator 326 and flows
from LNG production unit 232 by conduit 234 to LNG storage tanks
236 for storage. An overhead stream of residue gas 216 is delivered
from cold separator 326 and out of LNG production unit 232. One or
more portions of residue gas 216 can then be combusted by equipment
on second production vessel 204, or recompressed and returned to
LNG production unit 232 for reprocessing.
[0062] The liquefaction process is designed to produce a rich LNG
(to a maximum gross heating value GHV specification). The
pre-cooling section of the liquefaction process is used to extract
sufficient NGL components (C.sub.2+) from the treated stream 226 to
the extent needed to meet the LNG maximum GHV specification.
[0063] The extracted C.sub.2+, stream is sent to LPG production
unit 250 and flows into the top section of a deethanizer column to
yield a predominantly C.sub.1, C.sub.2 overhead residue gas stream
that is mixed with residue gas 216, and a bottoms C.sub.3+ stream
that is sent to a depropanizer column which is used to separate a
C.sub.3/C.sub.4 LPG product 210 in the overhead stream, from a
bottoms residual C.sub.5+ condensate stream, in a similar manner to
that described above with respect to the first embodiment shown in
FIGS. 2 and 3. The overhead condensed liquid C.sub.3/C.sub.4 LPG
product 210 is routed to the LPG storage tanks 260. The
depropanizer column (not shown) may include an air-cooled overhead
condenser, reflux drum, reflux pumps, and thermosyphon
reboiler.
[0064] Floating LNG/LPG Production Facility
[0065] A floating LNG/LPG production facility (FLNG) could also be
developed at relatively low cost, again ideally by conversion of an
existing LNG or LPG carrier vessel. The LNG and LPG products would
share the existing LNG or LPG carrier vessel storage. Use of the
pre-existing storage offers a potential cost advantage compared to
an integrated offshore oil/gas/LPG processing facility, coupled
with pipeline transport and storage of LNG and/or LPG products
onshore, or floating storage vessels.
[0066] The floating LNG/LPG (FLNG) production vessel can be
developed at relatively low cost, by conversion of an existing LNG
carrier vessel (with Moss-type storage tanks), that is still within
its design service life. The FLNG production vessel could also be
developed at relatively low cost as well, by conversion of an
existing LNG or LPG carrier vessel (with IHI SPB-type storage
tanks), that is still within its design service life. The FLNG
production facility would take a rich associated gas stream from an
offshore fixed or floating oil and gas processing platform, or an
oil FPSO, and process this rich associated gas for production of a
rich LNG, and a mixed C.sub.3/C.sub.4 LPG product, which are
saleable products of high market value. A residual C.sub.5+
condensate product could be routed back to oil and gas processing
platform, or oil FPSO. As an alternative, the C.sub.3 and C.sub.4
products can be separated and stored in separate propane and butane
storage tanks if so desired.
[0067] The FLNG production facility would include a gas treatment
unit, an LNG production and LPG production units, which would be
retrofitted into the existing LNG or LPG carrier vessel. The
associated or feed gas is routed to an acid gas removal unit (amine
solvent-based) for removal of CO.sub.2 (and traces of H.sub.2S, if
present), and to mole sieve dehydrators for removal of water vapor,
sufficient to avoid freezing in the cryogenic section of the LNG
production unit. The gas is then routed to a mercury removal
system.
[0068] The treated gas stream is routed to a liquefaction unit for
production of the LNG stream. It is envisioned that this may be a
nitrogen expander loop type liquefaction process with cold box for
compactness of system design. The liquefaction process will be
designed to produce a rich LNG. The pre-cooling section of the
liquefaction process will be used to extract NGL components
(primarily C.sub.2+) from the treated gas stream, to the extent
needed to meet the rich LNG maximum GHV specification, The LNG is
then routed to a cold separator, and then to at least one LNG
storage tank.
[0069] The C.sub.2+, stream is sent to a deethanizer column to
yield an overhead residue gas stream that is mixed with cold
separator vapor, and will be used for FLNG fuel gas. The bottoms
C.sub.3+ stream is sent to a depropanizer column, which would
separate a C.sub.3/C.sub.4 LPG product in the overhead stream, from
a bottoms residual C.sub.5+ condensate stream. The mixed
C.sub.3/C.sub.4 LPG product is routed to the LPG storage tanks The
depropanizer column may include an air-cooled overhead condenser,
reflux drum, reflux pumps, and a thermosyphon reboiler. The
deethanizer and depropanizer reboilers would be steam-driven to
utilize the existing steam system on the LNG or LPG carrier. The
existing steam system may need to be upgraded for the new service.
As an alternative, it is also possible that a separation of the
C.sub.2+ components may be done in a single taller column with a
lean residue gas stream, an LPG (C.sub.3/C.sub.4) side stream and a
C.sub.5+ bottoms stream.
[0070] LNG storage tanks and side-by-side LNG offloading facilities
on an existing LNG carrier would be reused for LNG service on the
FLNG vessel production facility, and upgraded if needed. LPG
storage tanks on an existing LPG carrier would be recertified for
LNG service, and side-by-side LNG offloading facilities would be
added to the LPG carrier vessel, for LNG service on the FLNG vessel
production facility.
[0071] LNG storage tanks on an existing LNG carrier would be
recertified for LPG service, and tandem LPG offloading facilities
would be added to the LNG carrier vessel, for LPG service on the
FLNG vessel production facility. LPG storage tanks and tandem LPG
offloading facilities on an existing LPG carrier would be reused
for LPG service on the FLNG vessel production facility.
[0072] Temporary storage tanks can be added to an existing LNG or
LPG carrier for the C.sub.5+ condensate product. Electrical power
generation equipment on an existing LPG or LNG carrier could be
reused for the FLNG production facility, with additional electrical
power requirements to be provided by a new aeroderivative
turbogenerator. Utility systems on an existing LPG or LNG carrier
(e.g., instrument air, nitrogen, fuel gas, firewater, etc.), and
control and safety systems could be reused and upgraded if needed,
for the new FLNG production facility service.
[0073] The existing LPG or LNG carrier can be retrofitted with a
turret mooring system, designed for station keeping of the FLNG
vessel, and to have sufficient riser capacity for the associated
gas import, and residual C.sub.5+ condensate export lines.
[0074] While in the foregoing specification this invention has been
described in relation to certain preferred embodiments thereof, and
many details have been set forth for purpose of illustration, it
will be apparent to those skilled in the art that the invention is
susceptible to alteration and that certain other details described
herein can vary considerably without departing from the basic
principles of the invention.
[0075] For example, it is envisioned that second production and
storage facilities 24, 204 can be utilized with an existing
production facility that either flares gas, exports the gas onshore
or reinjects the gas into subterranean formations. In this manner,
valuable products such as LPG and LNG can be captured that might
otherwise not be lost.
* * * * *