Configurations and methods for small scale LNG production

Abstract

A small scale natural gas liquefaction plant is integrated with an LNG loading facility in which natural gas is liquefied using a multi-stage gas expansion cycle. LNG is then loaded onto an LNG truck or other LNG transport vehicle at the loading facility using a differential pressure control system that uses compressed boil off gas as a motive force to move the LNG from the LNG storage tank to the LNG truck so as to avoid the use of an LNG pump and associated equipment as well as to avoid venting of boil off vapors into the environment.

Claims

1. A small scale LNG plant with integrated loading terminal, comprising: a refrigeration unit comprising a closed refrigeration cycle, wherein the refrigeration unit is configured to provide refrigeration content to a natural gas feed in an amount sufficient to produce LNG from the natural gas feed in a cold box; a LNG storage tank fluidly coupled to the cold box, wherein the LNG storage tank is configured to receive and store the LNG; a first boil off vapor conduit configured to provide a first boil off vapor from an LNG transporter to the cold box, and to transfer the first boil off vapor from the cold box to the LNG storage tank to thereby allow use of the first boil off vapor as a motive force to move the LNG out of the LNG storage tank to the LNG transporter; a second boil off vapor conduit configured to provide a second boil off vapor from the LNG storage tank to the cold box, and from the cold box to the natural gas feed; and a compressor that is configured to allow compression of at least one of the first boil off vapor or the second boil off vapor.

2. The plant of claim 1, further comprising a differential pressure controller configured to maintain a predetermined pressure differential between the LNG storage tank and the LNG transporter.

3. The plant claim 2, wherein the differential pressure controller is configured to allow liquefaction operation concurrent with filling operation of the LNG transporter.

4. The plant of claim 2, wherein the predetermined pressure differential is between 10-50 psi.

5. The plant of claim 1, wherein the refrigeration unit further comprises at least 3 exchanger passes configured to provide the natural as liquefaction refrigeration duty with a two stage nitrogen compression expander cycle.

6. The plant of claim 1, wherein the closed refrigeration cycle comprises a two stage turboexpander that is fluidly coupled with a two stage compression system, wherein the two stage turboexpander is configured to generate low level cooling, wherein the two stage compression system is configured to generate chilled gas feeding the turbo expanders while the power produced from the turbo expanders are used to reduce the gas compression energy requirement, and wherein the refrigeration cycle is configured to operate with a non-hydrocarbon refrigerant.

7. The plant of claim 1, wherein the refrigeration unit and storage tank are configured to provide an LNG production capacity of 10 to 200 tons per day.

8. The plant of claim 1, wherein the plant does not comprise a LNG pump configured to pass the LNG from the LNG storage tank to the LNG transport.

9. The plant of claim 5, wherein the refrigeration unit further comprises an exchange pass that is configured to recover refrigeration content from at least one of the first and second boil off vapors.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) FIG. 1 is one exemplary configuration according to the inventive subject matter.

(2) FIG. 2 is an exemplary graph illustrating the close temperature approach of the heat composite curves between the feed gas and the refrigeration circuit.

DETAILED DESCRIPTION

(3) The inventor discovered that a small scale LNG plant can be integrated with an LNG truck loading facility in a conceptually simple and cost-effective manner. In preferred aspects the small scale LNG plant has a capacity of typically between 10 to 200 tons, more typically between 20-80 tons, and most typically between 30 to 130 tons of LNG production per day by liquefaction of appropriate quantities of feed gas. For example, a small scale LNG plant with a capacity between 30 to 130 tons of LNG production per day will require between about 2 to 10 MMscfd of feed gas. In further particularly preferred aspects, the refrigeration process uses a non-hydrocarbon refrigerant (e.g., nitrogen, air, etc.) in a compression expansion cycle to so avoid the safety issues commonly associated with a hydrocarbon refrigeration system.

(4) The following description and FIG. 1 exemplarily illustrates various aspects of the inventive subject matter presented herein. Feed gas stream 1 is supplied to the small scale LNG liquefaction plant at a flow rate of 1.7 MMscfd at 100° F. and 453 psia with the following composition: 1.0 mol % N2, 0.1 mol % CO2, 96.5 mol % methane, 2 mol % ethane, and 0.5 mol % propane and heavier components. The gas is treated in a gas treatment unit 41 that typically includes an amine unit and a molecular sieve dehydration unit for removal of CO2 and water, forming a dried gas stream 2 which is dry and CO2 free. The dried gas stream 2 is combined with the recycle gas stream 11 and enters the cold box 51 which typically comprises at least five heat exchanger passes, 52, 53, 54, 55, and 56. The feed gas is chilled by nitrogen refrigeration in heat exchanger pass 52 forming a sub-cooled stream 3 at −223° F., which is then letdown in pressure in JT valve 71 forming stream 4. The flashed liquid at −227° F. is stored in storage tank 65 operating at 60 psia. The flashed gas stream 8 is recovered by recycling back to the exchanger pass 56 via valve 70. The refrigeration content of this recycle stream 9 is recovered in the cold box 51. Thus, it should be noted that the flashed stream 8 from the storage tank 65 is heated in the cold box 51. Stream 10 exiting the cold box 51 is compressed by compressor 68 to feed gas pressure forming recycle gas stream 11 prior to mixing with dried gas stream 2.

(5) The feed gas stream 2 is liquefied using two nitrogen expanders (57 and 60) and two nitrogen compressors (61 and 62). Nitrogen or air can be used in this cycle as long as the gas is dry. The hydrocarbon content is monitored as known in the art to detect any leakages and the unit can immediately shutdown during emergency.

(6) Stream 21 (31 MMscfd), from compressor 59 (coupled to expander 60) is fed to the nitrogen compressor 61 at 207 psia and 105° F. and is compressed to 260 psia, forming stream 22. The compressor discharge is cooled in ambient cooler 63 forming stream 23 that is split into two portions: stream 24 and 25. The split ratio of stream 24 to 23 is typically 50% to 50%, but it can vary from 25% to 70% depending on the feed gas composition and pressure. Stream 25 is cooled in heat exchanger pass 55 to about −42° F. forming stream 26, which is expanded to 169 psia in expander 60. The first expanded gas stream 27 is chilled to −85° F. which is routed to the mid section of the heat exchanger pass 54 to mix with the second expanded gas stream 79. Stream 24 is further compressed by nitrogen compressor 62 to 410 psia to form stream 28, cooled by ambient cooler 64 forming stream 29 and fed to heat exchanger pass 53. The high pressure nitrogen stream 29 is chilled to −158° F. forming stream 30, which is expanded to 169 psia by expander 57, forming the second expanded gas stream 79 at −225° F. This cold gas is used to liquefy the feed gas in heat exchanger pass 52. The second expanded gas stream 79 is mixed with the first expanded nitrogen stream 27 in heat exchanger pass 54, which provides additional chilling. Downstream of exchanger pass 54, the so warmed mixed stream 32 is compressed in compressor 58 forming stream 33, which is further compressed in compressor 59. This two step gas expander cycle is very efficient in achieving natural gas liquefaction as can be taken from the close temperature approaches of the heat composite curves between the feed gas and the refrigeration circuit as illustrated in FIG. 2.

(7) During conventional LNG truck loading operation, LNG is typically pumped using LNG pumps from the storage tank to the LNG trucks. This operation requires at least 2 hours time, as the LNG truck must be chilled from typically ambient temperature to cryogenic temperature. This operation also generates a significant amount of boil off vapors, which are in most cases vented to atmosphere and so present a substantial environmental concern.

(8) In contrast, and as is shown in FIG. 1, LNG is transferred from the LNG storage tank 65 to LNG truck 67 via streams 5, 6, and loading hose 66 by pressure differential, thereby allowing filling operation without the use of an LNG pump. LNG is transferred from a top outlet nozzle 98 using an internal pipe 99 inside the storage tank. This configuration avoids any bottom nozzles from the storage tank thus avoiding spillage of the storage tank inventory typically encountered in conventional storage tank design. Consequently, LNG pumps are not required. Flow controller 82 can be adjusted as necessary to deliver the flow quantity to the LNG truck. When the level in the storage tank drops to a low level, the level control 97 will stop flow in stream 5 at predetermined low level. Typically, the LNG storage tank 65 is configured with 30,000 gallons capacity, which is sufficient to load at least two LNG trucks, each with 10,000 gallons capacity. During LNG truck loading operation, valve 70 is closed, and valve 69 is open, allowing boil off vapor stream 7 to be vented from the truck to the cold box 51 as stream 9. Valve 69 controls the LNG truck vapor header at about 50 psig using the pressure controller 81, the lower pressure set-point of the LNG truck. With these valves operating in tandem, the boil off vapors during loading are recovered and venting to atmosphere is avoided.

(9) In order to provide the driving force to pressurize the LNG inventory from storage to the LNG truck, valve 84 is open providing high pressure gas 85 to the storage tank. Pressure differential controller 88 and pressure controller 83 are used to control the required flow rate. Typically, the differential can be set at 10 psi or higher pressure depending on the distance between the storage tank and the truck, and the LNG loading rate can be varied from 250 GPM to 500 GPM using flow controller 82. If necessary the differential pressure can be increased to increase the loading rate. Therefore, it should be appreciated that LNG pumping is not necessary, and that the loading system size and cost can be significantly reduced.

(10) While contemplated methods and plants presented herein may be have any capacity, it should be appreciated that such plants and methods are especially suitable for a small scale LNG plant having capacity of typically between 10 to 200 tons, more typically between 20-80 tons, and most typically between 30 to 60 tons of LNG production per day by liquefaction of appropriate quantities of feed gas. Consequently, contemplated plants and methods may be implemented at any location where substantial quantities of natural gas are available, and especially preferred locations include gas producing wells, gasification plants (e.g., coal and other carbonaceous materials), and at decentralized locations using gas from a natural gas pipeline. Thus, it should be recognized that the feed gas composition may vary considerably, and that depending on the type of gas composition, one or more pre-treatment units may be required. For example, suitable pre-treatment units include dehydration units, acid gas removal units, etc.

(11) It is further noted that use of a cold box with an inert gas is particularly preferred, especially where the liquefaction/filling station is in an urban environment. However, various other cryogenic devices are also deemed suitable, and alternative devices include those that use mixed hydrocarbon refrigerants. Moreover, and particularly where the storage tank has a somewhat larger capacity, it is contemplated that refrigeration content from the LNG may also be used to supplement refrigeration requirements.

(12) With respect to the differential pressure controller (dPC), it is noted that the dPC is preferably implemented as control device with a CPU, and may therefore be configured as a suitably programmed personal computer or programmable logic controller. It is also generally preferred that the dPC is configured such that the dPC controls operation of control vales to thereby maintain a predetermined pressure differential between the storage tank and the tank in the LNG transport vessel using pressure sensors and valves as is well known in the art. For example, control may be achieved by regulating pressure and/or flow volume of compressed boil off vapor from the compressor outlet en route to the storage tank, by regulating pressure and/or flow volume of boil off vapor from the tank in the LNG transport vessel, and/or by regulating pressure and/or flow volume of LNG from the storage tank to the tank in the LNG transport vessel. Thus, in at least some embodiments, the differential pressure controller will be configured to allow liquefaction operation concurrent with filling operation of the LNG transporter. Therefore, feeding of the natural gas to the liquefaction unit is done in continuous manner. However, discontinuous feeding and liquefaction is also contemplated.

(13) It should be noted that contrary to most known configurations, at least a portion of the boil off vapor from the storage tank and/or tank in the LNG transport vessel is not liquefied, but used as a motive fluid to move LNG from the storage tank to the tank in the LNG transport vessel. Consequently, the need for a LNG pump is eliminated. Moreover, it should be noted that the refrigeration content of the boil off vapor from the tank in the LNG transport vessel can be employed to supplement refrigeration requirements in the cold box. Thus, the boil off vapor is heated rather than cooled and reliquefied as known in most operations.

(14) It is still further contemplated that the storage tank may be modified in a manner such that LNG for export from the storage tank is drawn from a lower portion of the storage tank (e.g., sump or other location, typically below the center of gravity of the tank) through the vapor space of the tank to the filling line/loading hose, thereby avoiding problems associated with filling ports at the lower portion of the storage tank. Most typically, the tank will include an internal fill pipe that terminates at an upper portion of the tank to so allow connecting the internal fill pipe to a filling line/loading hose.

(15) Thus, specific embodiments and applications of small scale LNG production and filling have been disclosed. It should be apparent to those skilled in the art that many more modifications besides those already described are possible without departing from the inventive concepts herein. The inventive subject matter, therefore, is not to be restricted except in the scope of the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms “comprises” and “comprising” should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that the referenced elements, components, or steps may be present, or utilized, or combined with other elements, components, or steps that are not expressly referenced. Where the specification claims refers to at least one of something selected from the group consisting of A, B, C . . . and N, the text should be interpreted as requiring only one element from the group, not A plus N, or B plus N, etc.