PROCESS AND APPARATUS FOR REDUCING THE HEATING VALUE OF LIQUEFIED NATURAL GAS

Abstract

A process and apparatus is provided for reducing the heating value of imported LNG by removing natural gas liquid products while condensing boil-off gas. The LNG is pumped from a storage container and is then heated by cross exchange to a dew point temperature. A portion of this heated LNG is sent out to be vaporized while the remaining portion is further heated by cross exchange with demethanizer overhead vapors and is then sent as feed to the demethanizer. NGL is recovered at the bottom of the demethanizer, and the overhead vapors are mixed with boil off gas coming from the LNG storage container. These mixed vapors are condensed by cross exchanging with the LNG feed portion and then pumped to pipeline pressure and sent to the gas pipeline through the vaporizers.

Description

FIELD OF THE INVENTION

The present invention relates the heating value of liquefied natural gas (LNG). More particularly, the present invention relates to reducing the heating value of imported LNG by removing natural gas liquid products while condensing boil-off gas.

BACKGROUND OF THE INVENTION

Natural gas is a valuable, environmentally-friendly energy source. With gradually decreasing quantities of clean easily-refined crude oil, natural gas has become accepted as an alternative energy source. Natural gas may be recovered from natural gas reservoirs or as associated gas from crude oil reservoirs. Indeed, natural gas for use in the present process may be recovered from any process which generates light hydrocarbon gases.

Natural gas can be found all over the world. Much of the natural gas reserves found around the world are separate from oil and as new reserves are discovered and processed, growth in the LNG industry will continue. Countries with large natural gas reservoirs include Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Nigeria, Oman, Qatar, and Trinidad and Tobago.

LNG terminals exist in Japan, South Korea, and Europe as well as in the United States. LNG tankers can unload their cargo at dedicated marine receiving terminals which store and regasify the LNG for distribution to domestic markets. Onshore terminals can include docks, LNG handling equipment, storage tanks, a vaporizer system and interconnections to regional gas transmission pipelines and electric power plants. Offshore terminals typically regasify and pump the gas directly into offshore natural gas pipelines or may store natural gas in undersea salt caverns for later injection into offshore pipelines.

LNG is typically stored at cryogenic temperatures of about −162° C. and a vapor pressure at or near atmospheric pressure in double walled tanks or containers. The core containment for LNG is provided by the inner tank, while the outer tank is designed to provide a secondary containment, hold insulation and provide protection from adverse affects of the environment. Conventional vaporizer systems are used to warm and convert the LNG to usable gas. The LNG is warmed from approximately −160° C. in the vaporizer system converting it from a liquid phase to usable gas to that it can be transferred to a pipeline.

As the LNG is being offloaded from the ship to the cryogenic storage tank in an LNG receiving terminal, a portion of the liquefied natural gas is vaporized due to several heating factors such as pump heat, heat leak and flashing. These produced vapors are compressed and either used for fuel or re-condensed by heat exchanging with the LNG being pumped from the cryogenic storage tank in a dedicated BOG condenser. The re-condensed vapors output from the BOG condenser are then typically combined with the main LNG stream that is pumped to the vaporizers and then gas pipeline by LNG send out pumps.

Recently, consumers have been requiring strict specifications for the LNG being re-gasified and sent out of their LNG receiving terminals. These requirements include having the correct calorific value, fuel quality and composition (C2, C3 and heavier components). Since LNG liquefaction plants cannot be efficiently modified so as to meet the strict specifications, primarily due to the process operating conditions necessary to liquefy the natural gas, separation of LNG C2+ components is typically conducted in the LNG re-gasification terminal.

Natural gas liquid (NGL: refers to hydrocarbons found in natural gas that can be extracted or isolated as liquefied petroleum gas and natural gasoline) recovery at LNG re-gas terminals is done in a number of ways, but all require the addition of a number of complex rotating machinery items. For example, one method requires a compressor to compress lean C1 gas up to pipeline pressure while another requires that all LNG be pumped to an intermediate pressure (between that of the LNG tank pumps and send-out pumps) which adds a new step in the process.

The conventional process to capture BOG involves compressing the gas to a pressure equal to that of the LNG which is being pumped from the storage tanks. The BOG is combined with a stream of LNG in a dedicated condenser vessel where it is re-condensed and absorbed into the LNG. Another conventional process involves the compressing of BOG to pipeline pressure and combining it downstream of the vaporizers. This approach requires the compression of BOG to a high pressure.

There is a need to develop a new methodology that provides a better BOG handling and NGL recovery system while maintaining the flexibility to satisfy different customer requirements. The new methodology should also focus on reducing equipment capital costs as well as operating expenses, while at the same time providing reliable and safe operations.

SUMMARY OF THE INVENTION

The present invention achieves the advantage of a process and apparatus for reducing the heating value of imported LNG by removing liquid petroleum gas products with combined condensing of boil-off gas.

In an aspect of the invention, a process for reducing the heating value of LNG includes: splitting an LNG stream into a separations feed stream and a vaporization feed stream; cross heat-exchanging the separations feed stream with a combined boil-off gas and overheads stream; separating the separations feed stream into the overheads stream and a bottoms stream; and combining the combined boil-off gas and overheads stream with the vaporization feed stream.

Optionally, in the above process, a flowrate ratio between the separations feed stream and the vaporization stream is in the range of about 20:80 to 40:60.

Optionally, in the above process, the LNG stream pressure is in the range of about 75 to 125 psig.

Optionally, in the above process, the LNG stream is at a dew point temperature.

Optionally, in the above process, the separating is performed in a demethanizer.

Optionally, in the above process, the combined boil-off gas and overheads stream is formed by combining a boil-off gas stream with the separations feed stream before the separations feed stream is separated into the overheads stream and the bottoms stream.

Optionally, in the above process, the combined boil-off gas and overheads stream is formed by combining a boil-off gas stream with the overheads stream after the separations feed stream is separated into the overheads stream and the bottoms stream.

Optionally, in the above process, the overheads stream comprises at least about 98 mol % methane.

Optionally, in the above process, the cross heat-exchanging of the separations feed stream with the combined boil-off gas and overheads stream condenses at least a portion of the combined boil-off gas and overheads stream.

In another aspect of the invention, an apparatus for reducing the heating value of LNG includes: a pump for pumping an LNG stream; a flow control device for splitting the LNG stream into a separations feed stream and a vaporization stream; at least one heat exchanger for cross heat-exchanging the separations feed stream with a combined boil-off gas and overheads stream; and a separations column for separating the separations feed stream into the overheads stream and a bottoms stream.

Optionally, in the above apparatus, the flow control device controls a flowrate ratio between the separations feed stream and the vaporization stream within the range of about 20:80 to 40:60.

Optionally, in the above apparatus, the pump maintains the LNG stream at a pressure in the range of about 75 to 125 psig.

Optionally, in the above apparatus, the LNG stream is at a dew point temperature.

Optionally, in the above apparatus, the separations column is a demethanizer.

Optionally, the above apparatus further includes a manifold disposed upstream of the separations column for combining a boil-off gas with the separations feed stream.

Optionally, the above apparatus further includes a manifold disposed downstream of the separations column for combining a boil-off gas with the overheads stream.

Optionally, the above apparatus further includes a manifold disposed downstream from the heat exchanger for combining the combined boil-off gas and overheads stream with the vaporization stream.

Optionally, the above apparatus further includes a compressor for compressing the boil-off gas stream.

DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a flow diagram of an embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION

In the embodiment of the invention illustrated in FIG. 1, a liquefied natural gas is maintained at a select pressure in a container (B). Generally, the container is designed for a particular pressure, and the temperature of the LNG equilibrates to the bubble point temperature at the select pressure. However, it will be readily understood that storing LNG at a temperature below that of the bubble point is well within the range of current technology, and that the present process encompasses the full range of LNG storage temperatures The design of the container in which LNG is stored is not critical to the invention, and includes stationary storage located either on-shore or off-shore in an aquatic location. Alternatively, the LNG may be stored in a mobile container, located, for example, in a ship or on a truck, barge, train or the like.

The present process can be employed with LNG stored over the full range of possible storage pressure, including pressure from ambient pressure to a pressure of 1500 psig and above. In one embodiment, the LNG is stored at a pressure of about 5 psig or less. In actual practice, it is preferred to maintain the LNG at a storage pressure slightly above ambient pressure (e.g. 100-200 mbar gauge) to ensure acceptable pressure control.

During the process of the present invention, LNG at (1) is unloaded from an LNG carrier with on board pumps (A). The pressurized LNG at (2) is then transferred to the LNG container (B).

LNG (3) is transferred from the container (B) and pressurized with a pump (C). The pressurized LNG (4) output from the pump (C) is transferred to a heat exchanger (D), heated by cross-exchange to a temperature close enough not to produce any vapors (dew point temperature), and output as (5). The pressure of the LNG at (4) is preferably in the range of about 75 to 125 psig and the temperature change between (4) and (5) (across the heat exchanger (D)) is in the range of about +25 to about +30° C.

The heat exchanger (D) is a gas direct-contact type condenser such as a plate and fin exchanger in order to maximize heat transfer.

The heated pressurized LNG (5) is split into a separations feed stream (11) and a vaporization feed stream (6). The split in flow may be achieved by using a flow control device such a valve (not shown). The flowrate ratio is preferably in the range of about 20:80 to about 40:60 (20% to 40% for stream (11) and 80% to 60% for stream (6)). By varying the flow ratio between stream (11) and stream (6), the quantity of C2+ components in the pipeline gas can be controlled to meet specific market requirements. The separations feed stream (11) is further heated in a heat exchanger (H), which is the same type of heat exchanger as the heat exchanger (D), and output as a preheated LNG stream (12). The temperature change between (11) and (12) (across the heat exchanger (H)) is in the range of about +1 to about +5° C.

The present invention is also directed, at least in part, to a method for recovering BOG which is generated during LNG storage and handling, prior to the LNG vaporization process. Since LNG is maintained at a temperature below, and generally well below, ambient temperature, a small amount of LNG will vaporize during storage and handling as heat is absorbed through container walls. To protect against an over-pressure condition in the LNG container as the LNG vaporizer, the vaporized BOG must be handled. On account of its value as an energy source, and the environmental penalty if the BOG is vented to the atmosphere, it is desirable to recover and reprocess the vented BOG.

Thus, boil-off gas (21) evolved in the LNG container (B) is pressurized with a compressor (K) and output as (22). The compressor (K) is either a centrifugal or reciprocating type compressor.

The compressed boil-off gas (22) is then combined with the preheated LNG stream (12) via a manifold (not shown), and the combined stream (13) is transferred to a flash tank (I). The combined stream (13) is then flashed into a vapor stream (17) and a liquid stream (14). The flash tank (I) is a commonly used type low pressure surge drum or phase separator drum.

The liquid stream (14) is then transferred to a demethanizer column (J) and separated into an overheads stream (16) and an NGL bottoms stream (15). The NGL bottoms stream (15) is sent to additional processes.

The demethanizer column (J) is a reboiled absorber that uses a bottom heat source, such as a bottoms reboiler. Other examples of suitable bottom heat sources include a kettle reboiler, a thermosyphon reboiler, a plate-fin exchanger, an internal reboiler, a side reboiler, and combinations thereof. The demethanizer column (J) typically includes a stripping section and an absorption section within the same tower. In the demethanizer column (J), the rising vapors in a reboiler reflux stream are at least partially condensed by intimate contact with falling liquids from the liquid stream (14), thereby producing the overheads stream (16). The overheads stream (16) ha a methane concentration of at least about 98 mol %. The condensed liquids descend down the demethanizer column (J) and are removed as the NGL bottoms stream (15).

The overheads stream (16) is combined with the vapor stream (17) via a manifold (not shown) and output as a combined boil-off gas and overheads stream (18). The combined boil-off gas and overheads stream (18) is then transferred to the heat exchanger (H), cooled and partially condensed by cross exchanging with the LNG feed portion to the demethanizer (J), and output as (19). The temperature change between (18) and (19) (across the heat exchanger (H)) is in the range of about −3 to about −18° C.

The cooled overheads stream (19) is further cooled and condensed by cross exchanging with the LNG feed portion in the heat exchanger (D), and output as (20). The temperature change between (19) and (20) (across the heat exchanger(D)) is in the range of about −3 to about −10° C.

The cooled overheads stream (20) is then transferred to a flash tank (L) and flashed into a vapor stream (23) and a liquids stream (24). The vapor stream (23) is recycled back to the container (B), while the liquids stream (24) is transferred to a pump (M) and pressurized.

The vaporization feed stream (6) is combined, via a manifold (not shown), with a pressurized liquid stream (25) output from the pump (M), as (7).

The LNG (7) is then transferred to a flash tank (E) and flashes into a vapor stream (26) and an LNG stream (8). The LNG stream (8) is further pressurized with a pump (F) and output as (9). The LNG stream (9) is then vaporized in a vaporizer (G) and output as a gas (10).

Generally, the vaporization pressure will be set by the pipeline delivery pressure at (10), increased by some relatively small pressure differential to account for pressure losses across the vaporizer (G). The LNG is vaporized when the pressurized LNG (9) is passed across the vaporizer (G). Illustrative vaporizers include shell and tube heat exchangers, open rack vaporizers and the like. The vaporized LNG (10) is at pipeline delivery pressure, and available for sending to a pipeline delivery system or to another customer of natural gas. Generally the pipeline delivery pressure to which the natural gas is compressed is greater than 1000 psig. A pressure in the region of 1300 psig is illustrative.

The following tables are examples of a rich LNG case (Table 1) and a lean LNG case (Table 2). The methane concentration for the rich LNG case is in the range of about 85 to 89 mol %. The methane concentration for the lean LNG case is in the range of about 90 to 95 mol %.

	TABLE 1
	Rich LNG
	Stream No.	Temperature	Pressure
	(FIG. 1)	(° C.)	(bar)	(psia)
	1	−161	1.12	16.2
	2	−161	6.85	99.4
	3	−159	1.12	16.2
	4	−159	7.91	115
	5	−131	7.56	110
	6	−131	7.56	110
	7	−132	7.56	110
	8	−132	7.56	110
	9	−126	90.0	1305
	10	15.0	89.3	1295
	11	−131	7.56	110
	12	−127	7.41	107
	13	−127	7.41	107
	14	−127	7.41	107
	15	−13.3	7.56	110
	16	−108	7.00	102
	17	−127	7.41	107
	18	−110	7.00	102
	19	−125	6.80	98.6
	20	−132	6.50	98.6
	21	−159	1.12	16.2
	22	−64.0	7.56	110
	23	−132	6.50	94.3
	24	−132	6.50	94.3
	25	−132	7.56	110
	26	−132	7.56	110

TABLE 2
Lean LNG			Rich LNG
Stream No.	Temperature	Pressure	Stream No.	Temperature	Pressure
(FIG. 1)	(° C.)	(bar)	(psia)	(FIG. 1)	(° C.)	(bar)	(psia)
1	−161	1.12	16.2	14	−129	7.41	107
2	−161	6.85	99.4	15	−13.3	7.56	110
3	−160	1.12	16.2	16	−123	7.00	102
4	−159	7.91	115	17	−129	7.41	107
5	−130	7.56	110	18	−123	7.00	102
6	−130	7.56	110	19	−128	6.85	99.4
7	−131	7.56	110	20	−133	6.50	94.3
8	−131	7.56	110	21	−159	1.12	16.2
9	−124	90.0	1305	22	−66.2	7.56	110
10	15.0	89.3	1295	23	−133	6.50	94.3
11	−130	7.56	110	24	−133	6.50	94.3
12	−129	7.41	107	25	−132	7.56	110
13	−129	7.41	107	26	−131	7.56	110

Claims

1) A process for reducing the heating value of LNG, comprising:

splitting an LNG stream into a separations feed stream and a vaporization feed stream;

cross heat-exchanging the separations feed stream with a combined boil-off gas and overheads stream;

separating the separations feed stream into the overheads stream and a bottoms stream; and

combining the combined boil-off gas and overheads stream with the vaporization feed stream.

2. The process according to claim 1, wherein a flowrate ratio between the separations feed stream and the vaporization stream is in the range of about 20:80 to about 40:60.

3) The process according to claim 1, wherein the LNG stream pressure is in the range of about 75 to about 125 psig.

4) The process according to claim 1, wherein the LNG stream is at a dew point temperature.

5) The process according to claim 1, wherein the separations feed stream is separated into the overheads stream and the bottoms stream in a demethanizer.

6) The process according to claim 1, wherein the combined boil-off gas and overheads stream is formed by combining a boil-off gas stream with the separations feed stream before the separations feed stream is separated into the overheads stream and the bottoms stream.

7) The process according to claim 1, wherein the combined boil-off gas and overheads stream is formed by combining a boil-off gas stream with the overheads stream after the separations feed stream is separated into the overheads stream and the bottoms stream.

8) The process according to claim 1, wherein the overheads stream comprises at least about 98 mol % methane.

9) The process according to claim 1, wherein the cross heat-exchanging of the separations feed stream with the combined boil-off gas and overheads stream condenses at least a portion of the combined boil-off gas and overheads stream.

10) An apparatus for reducing the heating value of LNG, comprising:

a pump for pumping an LNG stream;

a flow control device for splitting the LNG stream into a separations feed stream and a vaporization stream;

at least one heat exchanger for cross heat-exchanging the separations feed stream with a combined boil-off gas and overheads stream; and

a separations column for separating the separations feed stream into the overheads stream and a bottoms stream.

11) The apparatus according to claim 10, wherein the flow control device controls a flowrate ratio between the separations feed stream and the vaporization stream within the range of about 20:80 to about 40:60.

12) The apparatus according to claim 10, wherein the pump maintains the LNG stream at a pressure in the range of about 75 to about 125 psig.

13) The apparatus according to claim 10, wherein the LNG stream is at a dew point temperature.

14) The apparatus according to claim 10, wherein the separations column is a demethanizer.

15) The apparatus according to claim 10, further comprising a manifold disposed upstream of the separations column for combining a boil-off gas with the separations feed stream.

16) The apparatus according to claim 10, further comprising a manifold disposed downstream of the separations column for combining a boil-off gas with the overheads stream.

17) The apparatus of claim 10, further comprising a manifold disposed downstream from the heat exchanger for combining the combined boil-off gas and overheads stream with the vaporization stream.

18) The apparatus of claim 10, further comprising a compressor for compressing the boil-off gas stream.