WO2009057179A2

WO2009057179A2 - Small-scale plant for production of liquified natural gas

Info

Publication number: WO2009057179A2
Application number: PCT/IT2008/000668
Authority: WO
Inventors: Luciano Ghergo; Alessia Arteconi; Fabio Polonara
Original assignee: G.P.T. S.R.L.
Priority date: 2007-10-30
Filing date: 2008-10-27
Publication date: 2009-05-07
Also published as: WO2009057179A3

Abstract

Plant (30) for the liquefaction of natural gas (NG), characterized in that gas comes from a low pressure reservoir, in particular, a pipeline ( 1 ) or a stranded well, and such gas (1) is joined to a low pressure recycle stream in a methane expansion cycle and it is compressed fairly by a methane compressor (C) that is integrated with a cooling system that pre-cools the unique combined stream of methane (Ia) and refrigerant (18a).

Description

Description Small-scale plant for production of liquified natural gas Technical Field

The present invention refers to the production of Liquid Natural Gas (LNG). Particularly, the invention pertains to a plant for the production of Liquid Natural Gas from low-pressure natural gas pipelines.

Background Art

At the present time, for what we know, there are no commercially viable Small-Scale

LNG production facilities anywhere in the world, where by "Small-Scale" we mean less than 10,000 liters/day.

Thus, any existing LNG-fueled fleet must depend on deliveries by tanker truck from larger-scale LNG plants or from LNG import terminals.

That condition increases the cost of the LNG to the end user, because the delivered price must include the substantial cost of transporting the LNG from the production or import location to the customer.

Those transportation costs tend to outweigh the lower production costs of large-scale LNG manufacture, where there is a large distance between the LNG source and the customer.

The customer must also maintain a large LNG storage tank so that deliveries can be spread out in time.

Such tanks produce "boil off' which is generally vented to the atmosphere, causing methane emissions and loss of product, further increasing the net cost of the LNG.

Heat gain to the storage tank, in the absence of on-site liquefaction, results in an LNG product that is not the ideal density for the vehicle's fuel tank. Re-liquefaction to avoid boil-off or to increase the product's density is not an option without an on-site LNG plant.

Other drawbacks to tanker-delivered LNG include the lack of competition in the industry, making the fleet owner excessively dependent on a single supplier. The quality of the delivered product may also vary, to the detriment of the fleet that uses the fuel. The alternative that is commonly used is on-site Compressed Natural Gas (CNG) production, using the local natural gas pipeline as the feed source. However, such CNG systems have severe limitations, including the following: the CNG, because it is not very dense, cannot be stored in any large quantities, so it must be made at a high capacity during the peak vehicle demand period. Similarly, the on- vehicle storage of CNG is limited by the need for heavy, high-pressure CNG tanks that store relatively little product, compared to the much denser LNG, and thus limit the travel range of the CNG vehicle.

Disclosure of the Invention

First purpose of the invention is to solve problems connected with the known state of the art by means of a plant that will yield cost-effective production of LNG with a Small-Scale LNG plant. Such a on-site Small-Scale LNG plant will allow natural gas fuelled fleets to produce, store, and dispense LNG at precisely their daily need, without depending on tanker-delivered LNG of varying quality, and without the need to opt for the less storable and less dense CNG.

A further advantage of the invention is that the LNG plant's average daily output can match the existing average daily fuel demand by the fleet. An increase in demand can be met by upgrading the LNG plant's production capacity, thus always keeping a balance between the plant's average daily output and the on-site customer's average daily demand.

According with the invention, those purposes are achieved by a production plant whose features are contained in the claims below, particularly in claim 1 and in each claim that is dependent, directly or indirectly, on claim 1. Such a plant can produce Liquid Natural Gas economically at a production rate of about 6,000-liters/day and with a capital investment no bigger than 1,000,000 euros. In comparison with the smallest LNG plant that we are aware of (in the state of Delaware in the US), that produces approximately 95,000 liters per day, there is a scale reduction of about 1/15. This clarifies what we mean with the expression "small-scale" plant abovementioned. That "small-scale" production can provide vehicle grade LNG to a medium-sized bus or truck fleet, without requiring that a portion of the plan's output be shipped to a second and third, off-site fleet. In short, each small-scale LNG plant will act as "appliance" that serves a single customer at a single location. The ability to economically produce vehicle-grade LNG will be achieved by two aspects of the invention: a) low capital costs, and b) high-efficiency.

The innovative LNG production cycle will yield approximately 84% LNG out of every unit of natural gas that is delivered to the plant from the local low-pressure pipeline, with only 16% of the natural gas used as fuel for the prime mover. The plant has several advantages. First of all the combination of relatively low capital cost and low fuel use (high- efficiency) will yield an operating cost and "price per liter" that will allow the LNG to be sold at a substantial discount to the market price of diesel, accounting for the energy content both fuels. That achievement - competitively priced LNG - vsdll allow natural gas to be more than just an "alternative fuel" but also an economically viable alternative fuel.

Obviously the production cost of the LNG will not include any tanker transport costs or any middlemen between the producer and the fleet operator.

Such on-site LNG plants can be developed under several business models, including a turnkey package that allows the fleet owner to fully own the equipment (thus fully controlling the fuel source), or several variations on the equipment builder leasing the plant, or merely providing the LNG at a contracted cost above the cost of production and equipment amortization.

Moreover any boil-off from the storage tank, or any vapour return from the vehicles that are fuelled can be re-liquefied in the on-site LNG plant. Subsequent economic advantages and positive involvements for the environment are evident and are not to be detailed further on.

Rrief description of the drawings

Other features and advantages of the invention will be pointed out in the following detailed description, based on the attached figure of a scheme aimed at illustrate and not limit the invention.

Detailed Description of the. Preferred Embodiments of the Invention

According to the attached figure, with (30) is indicated a plant to produce LNG from low-pressure pipeline gas (1) by means of an expansion cycle in a proper station (31). The plant is assumed set adjacent to the fleet that will use the LNG and produces LNG by pipeline natural gas at a pressure of 4 bar (or greater) and at a temperature of approximately 15°C.

The low-pressure natural gas is assumed with a chemical composition that is at least 90% methane, with some N2 and CO2. , but otherwise "clean" and dry, as is the case in Italy and elsewhere in Europe. In the event that the pipeline gas is not as clean, there are several known clean up systems that can be integrated with the cycle, none of which are a feature of the patent application.

The low-pressure (4 bar) pipeline stream (1) is separated into two partial streams (Ia, Ib): a first fuel stream (Ib) that provides fuel to a natural gas fired internal combustion engine (ENG), and a second fuel stream (Ia) that will be compressed and liquefied in order to produce the output LNG of the plant.

The plant (30) includes a multi-stage compressor with inter-cooling (in the described scheme are represented three compression stages) driven by an engine (ENG) and indicated with (C;C_1;C_2;C_3). The second partial stream (Ia) of natural gas that comes from pipeline (1) is sent to the second stage of the compressor (C_2). However, before reaching the second stage, it is mixed with a natural gas stream (2a) that comes from the first stage (C_l) of the compressor. Because of the streams (Ia, 2a) mixing, the resulting stream (3a), that will go to the second stage (C_2) of the compressor (C), is at about 20°C and 4 bar. Said resulting stream (3a) is sent thru a heat exchanger (32) that cools it up to about 2°C by heat transfer with a stream (18a) that, at about -35°C and 1.5 bar, flows thru the heat exchanger (32) recycling in the plant (30) and coming from the liquefaction station (31).

For the steps described above, the stream (3b) that goes into the second stage (C_2) of the compressor (C) has (for less than minor pressure drops) about the same pressure as the second partial stream (Ia) ed a lower temperature of about 2°C.

The attached figure shows clearly that the recycle stream (18b) that comes out the heat exchanger (32) is sent to the first stage (C_l) of the compressor (C); then, going through the first stage (C l), it is compressed and it comes out as a natural gas stream (2) at a pressure of 4 bar as the pressure of the second partial stream (Ia) and at the temperature of about 120°C, caused by heat produced during the compression inside the first stage (C l). The stream (2) that comes out the first stage (C l) of the compressor (C) flows through an inter-cooler (35) that cools it up to 26°C. This is the stream (2a) that is mixed with the second partial stream (Ia) that comes from the low-pressure pipeline gas (1). The heat exchanger (32) allows a cold recovery from the recycle stream ( 18a) at low pressure that leaves the liquefaction station (31 ) at the temperature of-35°C.

Coming to the stream (3b) that joints to stream (17a) and together they enter into the second stage (C_2) of the compressor (C), from the attached figure it is possible to see that it goes through the second stage (C_2) and comes out as stream (4) at a pressure of about 14 bar and a temperature of about 140°C. It flows through an inter-cooler (33), set between the second stage (C_2) and the third stage (C_3) of the compressor (C), where it is cooled up to 2°C, after that, as stream (5) it enters into the third stage (C_3) of the compressor (C) from which it comes out as stream (6) at a pressure of about 28 bar and a temperature of 65°C. The stream (6) flows through an after-cooler (34) from which it comes out as stream (8) at a temperature of-30°C and a pressure of about 28 bar.

The inter-cooler (33) and the after-cooler (34) are operatively associated with an ammonia absorption chiller fuelled by waste heat from the engine (ENG) that drives the compressor (C). According to the above description some important considerations follow. In fact, regarding the compressor (C), it can be implemented by using existing CNG compressors that in the commercial versions routinely provide up to 240 bar. In the plant (30), according to the invention, such a CNG compressor (C; C_l; C_2; C_3) will perform two functions. It will be both the feed gas (1 a) compressor (C; C l ; C_2; C_3) and the recycle (18a) compressor (C; C l; C_2; C_3). This is possible because the plant works on a cycle that is an "all methane" cycle, where the working fluid and the feed stream are both methane. Both streams (Ia e 18a) will be compressed simultaneously in a single CNG compressor.

When such a compressor (C) works on natural gas between an input pressure of about 4 bar to an output pressure of approximately 28 bar, that is at lower pressures of its capability, it will reduce the compressor's workload. The workload is that strictly necessary to bring the operating fluid to the optimal conditions for the gas (CNG) expansion in the expansion unit (31) that, as specified up ahead, is executed between the initial pressure of about 28 bar and the final pressure of about 1.5 bar. Said workload implies not only a low power requirement by the engine (ENG), but also reduce the "heat of compression" that is absorbed by the natural gas that flows through the compressor (C): all these aspects affect positively the global efficiency of the plant (30). It is to be noted that using compressed natural gas (CNG) and/or a standard CNG compressor to compress the NG in an expansion process in order to produce liquid natural gas (LNG) will allow existing CNG stations to be upgraded to LNG production in a easy and cost-effective way, by using the existing CNG compressors. Regarding the absorption chiller (AAC), it will be directly integrated with the compressor (C_1;C_2;C_3), with the inter-cooler (33) and with the after cooler (34). Such an integration, combined with the fact the absorption chiller (AAC) is fuelled by waste heat from engine (ENG), represents a contribution to the global efficiency of the plant (30), even if the use of absorption chilling is a well-established technology. In fact, the use of the absorption chiller (AAC) "powered" by the waste heat from the prime mover (ENG), recovers a significant portion of the approximately 67% of the energy content of the fuel used by the engine that is normally "wasted" by the engine's exhaust and water jacket. Coming back to the plant description, from the attached figure you can see that the compressed natural gas (CNG) stream (8), pre-cooled at -30°C and about 28 bar, is sent to a heat exchanger (36) where it will be further cooled and it will come out in two different streams (9, 16): the first stream (9) flows toward a section (28) of the liquefaction station (31) with a Joule-Thompson valve, the second stream (16) flows toward a section (27) of said liquefaction station (31) with a turboexpander (E). Particularly, after going through the heat exchanger (36), the first stream (9) that leaves the heat exchanger (36) that is at about at -110°C and at a pressure of 28 bar, is split in two partial streams (10,13).

The first stream (10) goes unchanged toward an heat exchanger (39) where it is sub- cooled from the initial temperature of-110°C to the final temperature of about-157°C. Said sub-cooling is achieved by heat transfer with the partial stream (13) split by it, that meanwhile it has been expanded by a Joule Thompson valve (40) and that after the valve has a temperature of-160°C and a pressure of 1.5 bar.

At this point the liquid phase of condensed methane comes out the sub-cooler (39) as stream (11) and goes through the valve (41) where the pressure is decreased from 28 bar to 4 bar. At the end it is stored into the tank (37) at a temperature of-157°C. The non liquified methane comes out the heat exchanger (39) as a gas phase stream (14) at a temperature of-158°C and a pressure of 1.5 bar.

Said stream (14) flows through a four- ways valve where also the vapour streams (22) and (19) arrive, coming respectively from the tank (37) and from the LNG fuelling station (43) near the plant (30). The stream (15) totally flowing from the valve (42) at the temperature of -157°C and at the pressure of 1.5 bar goes into the heat exchanger (36) and increases its temperature up to -35°C and it comes out from the heat exchanger (36) as recycle stream (18a) that goes toward the compression unit (29). The stream (16) flowing out from the heat exchanger (36) at the temperature of-75°C and pressure of 28 bar is expanded in the turboexpander (E) up to the temperature of- 140°C and the pressure of 3 bar. After the expansion the stream (16a) goes again through the cryogenic heat exchanger (36) and it comes out at temperature of about - 35°C as stream (16c).

The abovementioned stream (16c) is first warmed up 2°C into the heat exchanger (44) and then sent to the compressor (C4) driven by the turboexpander (E) so that its pressure becomes about 4 bar. After that the stream (17), coming out from the compressor (C4) at about 35⁰C and 4 bar, is cooled into the heat exchanger (44) by the stream (16c), pre-heated before it enters the compressor (C4). The stream (17a) that comes out from the heat exchanger (44) has been cooled down to 2°C and 4 bar. In these conditions the stream (17a) leaves the cryogenic unit (31) and goes toward the compression unit (29). Particularly this stream, joined with the stream (3b), goes into the second stage of the compressor (C_2).

It has to be noted that the cooling of the compressor inlet stream will result in approximately a 10% reduction in compressor power usage. This feature alone will increase the efficiency of the prime mover from 33% to 36.5%, or approximately 10 kW.

The chilling of the compressed feed gas will significantly reduce the stream's (Ia) heat content (enthalpy), compared to the heat content of the returning low-pressure stream

(18a).

That will happen because the feed gas will be compressed to nearly 400 psia, where its behaviour is "non-ideal" (similar to a liquid's behaviour), while the low-pressure recycle stream (18a) (at 1.5 bar) will behave in a nearly "ideal" manner. Those conditions will reduce the expander's refrigeration requirement by approximately 15%, reducing power demand by another 15 kW. The total power reduction achieved (10 kW + 15 kW = 20 kW) equals about 20%. At the scale of the plant (30) and with pipeline gas as the feed source, that power reduction is important. An advantage of the plant (30) per the invention is that it exploits the limitations of low-pressure methane compression-to-expansion, without using refrigerants such as N2, as in nitrogen expansion cycles; or "mixed refrigerants" as in MR cycles; or hydrocarbons, as in cascade cycles; and without the inefficiencies of high-pressure JT cycles.

Another advantage is that the CNG that goes to the heat exchanger (36) is pre-cooled at +/-28 bar and -30°C. That combination of pressure and temperature values allow for the use of a "plate fin" heat exchanger, rather than a more-expensive coil wound unit and yields a worthwhile amount of JT refrigeration as described in the next paragraph. Regarding the expansion section (28), the cold vapor + liquid stream (13) that comes from the J-T valve (40) is used to sub-cool the portion of the stream (10) that is still at- 110°C and 28 bar, cooling it to -157°C, so in the storage tank it allows to avoid any "flash" (vapor) formation. A further advantage of the plant (30) is that it doesn't need a cold box. It is possible thanks to the small dimensions of all the components being in the liquefaction station (31).

The invention so thought allows industrial applications. It can be modified with all the changes belonging to the invention idea. All details, moreover, can be substituted with technically equivalent elements.

Claims

1. Plant for the liquefaction of natural gas (NG), characterized in that gas comes from a low pressure reservoir, in particular, a pipeline (1) or a stranded well, and such gas (1) is joined to a low pressure recycle stream in a methane expansion cycle and it is compressed fairly by a methane compressor (C) that is integrated with a cooling system that pre-cools the unique combined stream of methane (Ia) and refrigerant (18a).

2. A plant, according to claim 1, characterized in that the cooling system is an ammonia absorption chiller (AAC).

3. A plant, according to claim 1, characterized in that the pre-cooling of the combined stream of methane (Ia) and refrigerant (18a) is performed into the inter- cooler (33) set between the second (C_2) and third stage (C_3) of the natural gas compressor.

4. A plant, according to claim 1, characterized in that the pre-cooling of the combined stream of methane (Ia) and refrigerant (18a) is performed into the after- cooler (34) of the natural gas multistage compressor (C).

5. A plant, according to claim 1, characterized in that the pre-cooling of the combined stream of methane (Ia) and refrigerant (18a) is performed by the heat recovery from the recycle stream (18a) that comes from the methane expansion cy- cle and the abovementioned pre-cooling is performed after the intercooler (35) set between the first (C_l) and second stage (C_2) of the natural gas compressor.

6. A plant, according to claim 1 through 4, characterized in that the pre-cooling of the combined stream of methane (Ia) and refrigerant (18a) is performed by an ammonia absorption chiller (AAC) fuelled by waste heat from engine (ENG) and the ammonia absorption chiller (AAC) is integrated with the inter-cooler (33) and the after-cooler (34) of the natural gas compressor (C).

7. A plant, according to claim 1 and 4, characterized in that the hot stream (17) that comes out the compressor (C4) driven by the turboexpander (E) is pre-cooled by the stream (16c) that comes out the main heat exchanger (36), so that it is sent to the compressor (C) for a further compression at low temperature.

8. A plant, according to claim 1 through 6, characterized in that a standard natural gas compression station (C) is used to produce liquid natural gas (LNG) and the compressor load is reduced because the cycle works at moderate pressures and a precooling of methane streams (Ia, 18a) is performed.

9. A plant, according to claim 8 , characterized in that the cycle works at pressure lower than 30 bar.