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.

Description

BACKGROUND

1. Technical Field

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.

2. Description of Related Art

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 (C₁), ethane (C₂), propane (C₃), butane (C₄) and heavier condensates (C₅₊). The associated gases often contain other unwanted constituents such as acid gases including carbon dioxide (CO₂) and hydrogen sulfide (H₂S), water and contaminants such as mercury (Hg).

It is desirable to extract hydrocarbon components from the associated gas streams and produce liquefied petroleum gas (LPG), predominantly C₃ and C₄ gases, and/or produce liquefied natural gas (LNG) (predominantly C₁ and C₂ 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.

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.

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.

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

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.

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.

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.

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.

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

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:

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;

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 C₅₊ 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;

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 C₅₊ liquid condensates;

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 C₅₊ liquid condensate; and

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 C₂₊ liquids and residue gas from treated associated gases; the C₂₊ liquids are then converted to LPG and C₅₊ liquid condensates.

DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS

For the purposes of this disclosure, the following terms shall have following meanings:

Condensate refers to liquids recovered from rich associated gases having predominantly C₅₊ hydrocarbons;

LNG (Liquefied natural gas) refers to a cryogenic fluid comprising predominately methane (C₁) with lesser amounts of C₂₊ hydrocarbons, which is sufficiently cold to remain in a liquid state at or near atmospheric pressures;

LPG (Liquefied petroleum gas) refers to fluids comprising predominately C₃ and C₄ hydrocarbons, which can either be refrigerated to remain liquid at near atmospheric pressures or pressurized to remain liquid at atmospheric temperature;

Residue gas refers to gases recovered from LPG or LNG processing that contain primarily C₁ and C₂ hydrocarbons;

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 C₁, C₂, C₃, C₄ and C₅₊ components;

Lean gases refers to gases containing primarily C₁ and C₂ from which heavier hydrocarbon components C₃₊ have been substantially removed.

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.

Offshore Production Facility Producing Crude Oil and Rich Associated Gases

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.

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.

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.

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.

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.

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.

LPG Production and Storage Facility

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 C₃ and C₄ components (propane and butane), a residue gas 72 comprising primarily C₁ and C₂ gases, and a stream of C₅₊ 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.

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 (CO₂, H₂S), 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 1
Level of Contaminants in Treated Gas Stream
	Contaminant	Maximum amount of Contaminant
	Component	Component in Treated Gas Stream
	Carbon dioxide (CO2)	<50	parts per million by volume;
	Hydrogen Sulfide (H2S)	<3	parts per million by weight;
	Water vapor (H20)	<1	part per million by weight;
	Mercury (Hg)	<0.1	micrograms/square meter3

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.

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.

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 (CO₂) and/or hydrogen sulfide (H₂S) 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 CO₂ and H₂S 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.

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.

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 C₁ expanded cold vapor stream and a C₂₊ 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 C₂₊ 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 C₁, C₂ 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.

Deethanizer column 144 yields a bottoms stream of heavier components C₃₊ that are routed through a liquid conduit 150 to a depropanizer column 152 in which the LPG (C₃, C₄) fluids 74 are separated from the heavier stream 76 of C₅₊ 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.

The LPG 74 (C₃, C₄) 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 C₅₊ 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 C₅₊ condensate 76 and crude oil should meet industry specifications necessary for transport of crude oil on crude oil tankers. As an alternative, the C₅₊ condensate 76 may be used for combustion on second production and storage facility 24 by boilers or other operational equipment. If all of C₅₊ condensate is consumed on facility 24, then no export line 50 is necessary.

Floating LPG Production and Storage Facility

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° C.). As another non-limiting example, production facility 24 might process a rich associated gas stream with natural gas liquids (C₂₊) content in the range 5-20% (mol.).

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 C₅₊ liquid condensate which can be later combusted or transferred to a crude oil tanker.

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 C₅₊ liquid condensate export lines 48, 50.

LNG/LPG Production and Storage Facility

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 C₅₊ condensate 214. A stream of residue gas 216 is also produced.

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 (CO₂, H₂S), 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.

LNG production unit 232 produces LNG 210 along with a predominantly C₂₊ 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.

A liquefied petroleum gas (LPG) production unit 250 receives C₂₊ liquids from LNG production unit 232 by way of liquids conduit 252. LPG production unit 250 separates C₂, C₃, C₄ liquids from heavier liquids to produce LPG 212 and C₅₊ 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 C₂₊ liquids into LPG 212 and C₅₊ condensate liquids 214.

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.

As most of the lighter C₁, C₂ 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.

Liquid C₅₊ 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.

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.

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.

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° F. (−170° 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.

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 C₁, C₂ lean gases carried by gas conduit 322 and a bottom liquid stream of predominantly C₂₊. Extracted C₂₊ 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.

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.

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 (C₂₊) from the treated stream 226 to the extent needed to meet the LNG maximum GHV specification.

The extracted C₂₊, stream is sent to LPG production unit 250 and flows into the top section of a deethanizer column to yield a predominantly C₁, C₂ overhead residue gas stream that is mixed with residue gas 216, and a bottoms C₃₊ stream that is sent to a depropanizer column which is used to separate a C₃/C₄ LPG product 210 in the overhead stream, from a bottoms residual C₅₊ 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 C₃/C₄ 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.

Floating LNG/LPG Production Facility

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.

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 C₃/C₄ LPG product, which are saleable products of high market value. A residual C₅₊ condensate product could be routed back to oil and gas processing platform, or oil FPSO. As an alternative, the C₃ and C₄ products can be separated and stored in separate propane and butane storage tanks if so desired.

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 CO₂ (and traces of H₂S, 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.

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 C₂₊) 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.

The C₂₊, 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 C₃₊ stream is sent to a depropanizer column, which would separate a C₃/C₄ LPG product in the overhead stream, from a bottoms residual C₅₊ condensate stream. The mixed C₃/C₄ 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 C₂₊ components may be done in a single taller column with a lean residue gas stream, an LPG (C₃/C₄) side stream and a C₅₊ bottoms stream.

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.

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.

Temporary storage tanks can be added to an existing LNG or LPG carrier for the C₅₊ 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.

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 C₅₊ condensate export lines.

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.

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.

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.