US3331214A - Method for liquefying and storing natural gas and controlling the b.t.u. content - Google Patents

Description

my l' i957 R c. WOCTOR ETAL SLM METHOD FOR LIQUEFYING AND STORING NATURAL GAS AND CNTROLLING THE B L u CONTENT 2 Sheets-Sheet l Filed March 22, 1965 Y I JUEY N3 m57 R. c. PROC-rola ETAL 33319.23@

METHOD FOR LIQUEFYING AND STORING NATURAL GAS AND CONTROLLING THE B 12. LL. CONTENT Filed March 22, 1965 E mo :o mccanm IIAVAV wl llllllllllllllll Il ma?) r@ .S0 ...WAI

INVENTORS Russell C. PrOCfOr Roger W. Parrish ff BY o( z/M/a/V.,

E@ mf EEtSwOM ATTORNEY United States Patent O 3,331,214 METHQD FOR LIQUEFYING AND STORING NATURAL GAS AND CONTR B.t.u. CNTENT OLLING THE Russell C. Proctor, Leawood, Kans., and Roger W. Parrish, Independence, Mo., assignors to Conch Internationai Methane Limited, Nassau, Bahamas, a Bahamian comriied Mar. 22, 1965, ser. No. 441,768 9 claims. (ci. ca -2o) This invention relates to the storage of natural gas supplied from a pipeline, by converting it to liquid natural gas, and to the control of the B.t.u. `content of natural gas supplied back to the pipeline from said storage. The present invention relates to the same problem as is dealt with in the copending application of Bodle and Young, er. No. 282,727, assigned to the assignee of the present invention, over which it has the following advantages: (1) It eliminates the need for removing acid gases and water from the feed gas. (2) It reduces the number of heat exchanges needed for liquefaction. (3) It moves a greater proportion of hydrocarbon and CO2 at a llow pressure, after which the gas is recompressed to a high pressure for liquefaction of the entire stream. (4) It is simpler in construction and can be readily designed for construction into relatively small units which are suitable for skid mounting, and hence can be made transportable. An antifreeze agen-t which is injected to prevent riming is not lost, but adds its fuel value to the heavies used for B.t.u. control.

A recent development in the pipeline transportation of natural gas is the introduction of peak shaving, by which is meant the storage of surplus gas delivered by the pipelines during periods of low demand near the point of ultimate use, for addition to the local gas supply during periods of high use. For this purpose, the stored gas is preferably in liquid form, since this enables very large quantities of gas to be stored in a reasonable and relatively economica-l storage reservoir. One preferred form of such storage is to maintain the liquid in suitably insulated or underground containers at substantially atmosphe-ric pressure, and ,at its natural boiling point, which at this pressure is in the neighborhood of 258 F. Because natural gas is a mixture of loW molecular weight hydrocarbons and other substances, the exact boiling point of the mixture is a function of the composition. Since the stored liquid is boiling under these conditions due to heat leakage from the wanner surroundings, the boil-oit vapor contains a larger proportion of lighter constituents, and the residual stored liquid tends to gradually accumulate a larger and larger percentage of heavier hydrocarbons, whi-ch have a higher heating value than the lighter hydrocarbons. However, customer requirements call for a supply of gas at a constant or pre-agreed B.t.u. value, both for heat requirements and for proper operation of the gas-utilization equipment. It is a major object of the present invention to supply this need by providing means for automatically and continuously maintaining the B.t.u. value of the gas supplied from the storage pipeline at a constant yB.t.u. value.

Another object is to eliminate the need for removing carbon dioxide and Water from the feed gas, as this is accomplished easily as part of the present method.

Still another object is to separate outV a substantial proportion of the heavier hydrocarbons at a relatively low pressure, for use in reconstituting Ithe B.t.u. value of gas supphed fom the storage reservoir.

Still another object is to prevent riming and clogging of the lmes by water and CO2 which would otherwise tend t-o occur at the low temperatures employed.

rl`he above and other objects are achieved in accordance with the invention by initially compressing the natural gas stream from the transmission line only sufficiently so that upon cooling liquid containing hydrocarbons heavier than methane, CO2, and methanol or other suitable antifreeze agent is condensed; the methanol is added as necessary to prevent riming of the exchangers by water and CO2 which would tend to clog the system. The condensed liquid is then separated from the gas stream, while the uncondensed portion is recompressed to a suiciently higher pressure so that upon subsequent cooling it will liquefy, the LNG is then expanded into a suitable container. The methanol-water mixture and absorbed' CO2 are removed plus some heavy hydrocarbons; and these -can be disposed of into the boil-off line in order to control its B.t.u. and utilize its fuel value. The water-methanol mixture may be separated from the hydrocarbon liquid layer for later reconcentration |by distillation. The condensed heavy hydrocarbons are vaporized by passing Ithem in heat exchange with the initially compressed NG stream, and combined with gas vaporized from the stored LNG in the correct proportions to maintain the initial B.t.u. content of the gas in the transmission line. The amount of heavy hydrocarbons condensed is varied to maintain the B.t.u. balance by controlling the compressor interstage pressure or bypassing around la heat exchanger.

The specific nature of the invention, as well as other objects and advantages thereof, will clearly appear from a -description of a preferred embodiment, as shown in the accompanying drawings, in which:

F'lG. 1 is a highly simplified schematic flow chart showing the principle ofthe invention;

FIG. 2 is a more detailed flow chart showing a system in accordance with the invention; and

FIG. 3 is a flow chart of the vaporizer used in connec tion with the system of FIG. 2.

Referring -to FIG. 1, the transmis-sion line 2 is a main supply line for natural gas, typically at a pressure from -315 p.s.i.a. In accordance with the invention, the gas is taken from the transmission line in feeder line 3 and is compressed by compressor 4 to a suitable pressure, e.g., 350 pounds, which is however still a lower pressure than that required for the ultimate lquefac-tion of all the gas. The gas is then -cooled in heat exchanger 6 to 143 F. At this temperature and pressure, some of the higher hydrocarbons will begin to condense out of the gas, and are trapped in knock-out drum 7, together with water and methanol (if any is added) which sink to the bottorn as show-n at 8, and c-an be removed in line 8a, together with a certain amount of CO2, which becomes vdissolved in the methanol-water under these conditions, or can be added in line 8b -to Ithe ow in line 9a and thence to the transmission line 2. If the CO2 is present in a concentration of less than a few percent, substantially all of the CO2 will be removed by this step. The heavier hydrocarbons remain in layer 9, and are kept at `a suitable level in the knock-out drum by control apparatus as will be shown below. The lighter uncondensed hydrocarbons (together with a certain -percentage of the heavies) are passed in line 11 back through heat exchanger 6, warmed, and recompressed by compressor 12, then cooled again in passage through heat exchanger 6, from which they emerge as a liquid at a temperature of 143 F. and a pressure of approximately 660 p.s.i.a., `so that -upon expansion through valve 14 to atmospheric pressure in tank 16, most of the gas remains liquefied for storage in the tank 16. The flash and boil-off gases in tank 16 are passed through line 18 to heat exchanger 6, and lthen compresse-d by compressor 20 to the transmission line pressure, and fed into the transmission line. When a peak demand occurs and more gas is needed, it is taken from storage tank 16 through pump 32 on line 24 and vaporized in vaporizer plant 26, then supplied on lines 28 and 30 back to the transmission line. Line 9a returns the condensed enriching liquid in layer 9 back to return pipe 35 to maintain the B.t.u. level constant. To maintain the necessary temperature conditions in heat exchanger 6, external refrigeration is needed, as schematically indicated by external refrigerating circuit 40, described in more detail below.

FIGS. 2 and 3 show a more detailed flow sheet of the above system. In practice, an air-iin heat exchanger 4a is inserted after compressor 4 to cool the compressed gas by heat exchange with ambient air. Between compressor 4 and exchanger 4a, or at any other suitable point in this line, methanol is injected from container S by means of a suitable pump 5a, in order to prevent freezing of the CO2 and Water, Aand consequent riming of the pipes, especially in heat exchangers 6a and 6b. If the pipeline gas is adequately dry for the process, it may not be necessary Ito inject .the methanol. However, with the typical conditions shown, the methanol is necessary to inhibit the formation of gas yhydrates in the cooling of the gas yand the freezing of the CO2. The `gas at the outlet of exchanger 4a is at a temperature of 100 F. and a pressure of 350 p.s.i.a., and is now conducted in pipe 5 to successive stages of heat exchanger 6, identified in this case as 6a and 6b, from which it emerges at a temperature of 143 F. At this temperature and pressure, some of the heavier hydrocarbons will condense out of the gas, and these are trappe-d in knock-out drum 7, together with condensed water and methanol solution, which for-ms -a bottom layer `8, and can be drawn olf in line 8a to a burn pit for disposal or to a reconcentration apparatus, or alternatively can be sent back on line 8b for ultimate addition to the fuel line, thus utilizing the heat content of the methanol. The heavier hydrocarbons which are condensed form a layer 9 in knock-out drum 7, the level of which is maintained within desired limits by sensing device 10, which through control line 10a acts upon threeway valve 11, which is also controlled thereby to divert 1a portion of the stream in line 5 around t-he heat exchanger 6b so that there is not more hydrocarbon liquid made in knock-out drum 7 than is necessary for the enrichment of the boil-oli gas from the storage tank.

The uncondensed gas in drum 7 is returned in line 12 gas is admitted again to heat exchangers 6a and 6b and from which it emerges at a temperature of F., and is now admitted -to lsecond-stage feed-gas compressor 13 where it is compressed to 660 p.s.i.a. At this level, the gas is admitted again to heat exchangers 6a and 6b and is in` a fully liqueed condition as it emerges in line 14 at 143 F. and 660 p.s.i.a. The LNG is then admitted through the back-pressure control valve 16 to the storage tank 17 at atmospheric pressure and its temperature is reduced to approximately 258 F.

Boil-off and flash -gases from the `storage tank are cornpressed in single-stage 4centrifugal blower 18 `(to overcome the pressure drop in the heat exchanger) and are admitted to the boil-off compressors 20a and 2Gb at 20 F. for recompression to the transmission line pressure.

The -above-described process requires some additional refrigeration capacity to Ibe added to the heat exchangers, 4and this is supplied by a propane loop and an ethylene loop of refrigeration which will now be described.

The propane loop includes compressors 21a and 2lb (a two-stage reciprocating compressor) which compresses propane vapors from essentially atmospheric pressure to 260 p.s.i.a. where the propane vapor lis condense-d in heat exchanger 22 (air-fin type) for admission through valve 23 to storage tank 26 at +20 F. The temperature in the storage tank is maintained `at 20 F. by the interstage pressure between the two stages of compressor.

Propane leaving tank 26 goes through valve 27 to heat exchanger 6a and the propane liquid is flashed to its equilibrium temperature of 40 F. and superheated to 20 F. for return to the inlet of compressor 21a (first sta-ge).

The ethylene cycle also has a two-stage reciprocating compressor 29a and 29b with air-lin intercooling and aftercooling as shown at 31a and 31b respectively. After the ethylene vapors are cooled with air in heat exchanger 31b, -they are condensed by exchange against the propane circuit in heat ex-changer 6a. The liquid ethylene is stored at 28 F. in tank 33. This ethylene is admitted through valve 34 into heat exchanger `6b and valve 34 is controlled by temperature control on the outlet of the ethylene vapors leaving 6b, as indicated at 34a. These vapors are superheated in exchanger 6a to 20 F. for admission to the inlet of compressor 29a.

By compressing the feed gas to 350 p.s.i.a. in line 5 and with the injection of methanol as described, approximately of the CO2 is condensed and removed in knock-out drum 7. Assuming that the amount of CO2 in the feed gas was 1 mol percent, the CO2 in the gas being condensed at 660 p.s.i.a at the discharge of compressor 13, is well within the solubility limit of CO2 in liquid methane at this level of pressure and temperature, and there will therefore be no CO2 condensing out in heat exchangers 6a and 6b prior to the liquefaction of the gas for storage in tank 17.

It will at times be necessary or desirable not to add any net feed to the storage, and for this purpose a holding circuit is arranged which will now be described. During holding, the feed gas compressor 4 will be shut down, and the boil-off compressor will recirculate vapors from the tank through the holding circuit. This is done by closing valves 36 and 38, and opening valves 40 and 42, so that the boil-off vapors now circulate through line 43, and airn exchanger 4a. It will be seen that the exchanger 4a thus serves the dual purpose of being the air-fin cooler for the rst stage of compressor 4 under normal liquid operation and also serves as the after-cooler for compressors 20a and 20b during the holding operation. The boil-olf gases are free of contaminants such as CO2 and H2O vapor, and these gases are recirculated through heat exchanger 4a, and through compressor 13 to follow the same course as before. As an alternative to the three-way diversion valve 11, it is possible to control the hydrocarbon level in knock-out drum 7 equally Well by controlling a valve in the gas line 5 between exchangers 6a and 6b, which would accordingly change the discharge pressure on compressor 4 and consequently control the amount of condensed liquid in the knock-out drum by controlling this pressure, or alternatively controlling the pressure through adjusting the capacity of compressor 4 by unloading or bypassing.

Control of the liquid in the knock-out drum 7 is accomplished by controlling the discharge pressure on compressor 4 through a signal from the calorimeter 45 which reads the heating value of the boil-off and Hash gases admitted back to the transmission lines. The level of enriching liquid in the knock-out drum is controlled by a valve 12a in the gas line 12 controlling the discharge pressure on compressor 4.

It is expected that there would be some formation of solid CO2 in the valve 16 during operation, and an alternative route with a similar valve 16a is therefore provided 4so that these two valves can be cycled alternatively should the pressure drop across either valve increase because of the build-up of solid CO2 in the valve. This is accomplished by pressure control devices 46 and 48 so that when the valves are being cycled, the valve that is not in operation can be electrically derimed by conventional means (not shown).

FIG. 3 shows the vaporizer, which may be of any desired construction, but in one practical form consists of anindirect exchanger between LNG which comes from the tank in line 41, and isopentane in exchanger 42. The isopentane is circulated through a direct fired heater 43, by pump 44, and is heated to 300 F. in the heater. LNG is exchanged in exchanger 42 for admission to the pipeline. The primary advantage of this vaporizer is that the heat medium may be circulated by pump 44, the heater 43 started up, and control of the temperature of the isopentane leaving the heater 43 will modulate the lire in the heater. The thermal inertia of the total quantity of heat medium liquid is such that this control is easily maintained and it is not a critical operating procedure to start up the heater and circulate the isopentane. When LNG is admitted to exchanger 42, it may be started through the exchanger gradually, which will reduce the temperature of the heat medium liquid and bring up the tire as more and more LNG is admitted through the heat exchanger up to its designed capacity.

The LNG in the tank will have the same B.t.u. content as the incoming gas stream because the enriching separator will have stripped out sufiicient high B.t.u. components to maintain the boil-off stream at the same B.t.u. as the incoming stream.

Although the heavier hydrocarbons were condensed out in vessel 7 at a relatively low pressure (350 pounds), this is still higher than the initial pressure in line 2 (approximately 315 pounds maximum) by virtue of compressor 4, and therefore no additional pumping is required to return the heavies on line 9a into the main line 2.

It will be apparent that the embodiments shown are only exemplary and that various modications can be made in construction and arrangement within the scope of our invention as defined in the appended claims.

We claim:

1. A process for liquefying natural gas containing heavy hydrocarbons and CO2 for storage of the liquefied natural gas for use during peak load periods, which comprises (a) compressing the natural gas stream,

(b) injecting methanol into the natural gas stream,

(c) cooling the compressed natural gas stream containing methanol to a point at which sufficient of the heavy hydrocarbons and a portion of CO2 are condensed and the uncondensed level of CO2 will be well within the solubility range when further compressed and cooled,

(d) separating the liquid heavy hydrocarbons from the gas stream,

(e) vaporizing the liquid heavy hydrocarbons by passing it in heat exchange with the compressed natural gas stream containing methanol to effect in part the cooling of step (c),

(f) recompressing the gas stream from step (d), cooling it such that the stream is totally condensed at the increased pressure and flashing it to storage at substantially atmospheric pressure,

(g) using the gas boiling off from storage due to heat leak into the system together with the flash gas from the expansion in step (f) to effect in part the cooling in steps (c) and (f) and then recompressing the same and mixing with it the vaporized liquid from step (e) so as to adjust the B.t.u. content of the mixed stream to essentially that of the incoming stream, and

(h) passing said mixed stream to the'gas delivery line.

2. A process for liquefying or partially liquefying natural gas containing methane and heavier hydrocarbons and CO2 for storage of the liquefied natural gas for use during peak load periods, which comprises (a) compressing the natural gas stream,

(b) injecting an anti-freeze agent into the natural gas stream,

V(c) cooling the compressed natural gas stream containing the anti-freeze agent suiiiciently to cause a portion of the heavy hyd-rocarbons and CO2 to condense, and Ithen separating the portion of the hydrocarbons heavier than methane, CO2, and the anti-freeze agent,

(d) vaporizing the liquid heavy hydrocarbons so separated Iby passing it in heat exchangeswith the compressed natural gas stream containing the anti-freeze agent to eiect in part the cooling referred to in Step (C),

(e) recompressing the gas stream from step (c), cooling it such that the stream is totally condensed at the increased pressure and hashing it to storage at substantially atmospheric pressure,

(f) using the gas boiling 0H from storage due to heat leak into .the system together with the flash gas from the expansion in step '(e) to effect the cooling in steps (c) and (e) and then recompressing the same and mixing it with such a proportion of the vaporized liquid from step (d) as to adjust the B.T.U. content of the mixed stream to essentially that of the incoming stream, and

(g) passing said mixed stream to the gas delivery line.

3. A process for liquefying natural gas supplied by pipe linev and consisting mostly of methane, for storage and use during peak load periods, said natural gas containing less than one mol percent CO2 and some heavy hydrocarbons, which comprises (a) compressing the natural gas from the pipe line,

(b) cooling the compressed natural gas stream to a point at which the heavy hydrocarbons and CO2 are largely condensed,

(c) separating out a portion of the condensed heavier hydrocarbons and CO2,

(d) recompressing the uncondcnsed gas stream from step (b), cooling it below its liquefaction temperature and flashing it to substantially atmospheric pressure for storage,

(e) storing the liquefied natural gas in a reservoir, at a pressure and temperature such that some gas is normally boiling out of the liquid due to heat leak through the storage vessel,

(f) using said boil-oli gas from step (e) together with the Hash gas from the expansion of step (d), to eiect in part the above cooling steps (b) and (d),

(g) recompressing said boil-olf and liash gas and mixing with it vaporized heavier hydrocarbons from step (c) in such proportion as to adjust the B.t.u. content of the mixed stream to essentially that of the incoming stream, and

(h) passing said mixed stream back to the pipe line.

4. The process as claimed vin claim 1, including the steps of (a) withdrawing liquefied natural gas from said reservoir,

(b) heating said withdrawn liquefied natural gas by heat exchange interchange with a liquid heat exchange medium to convert It-he liqueiied natural gas to vapor, and

"(c) passing said vapor back to the pipe line.

5. The process as claimed in claim 4, wherein said liquid heat exchange medium is isopentane, including the step Iof circulating the heat exchange medium through a direct ired heater to raise its temperature to the order of 300 F.

6. The process 4as claimed in claim 5, wherein the isopentane is first heated up by the heater in starting the system and its temperature rise is used to control the operation of the heater, while LNG is admitted gradually to the heat exchanger to reduce the temperature of the heated isopentane and Ithereby increase the heat input to the heater.

7. The process as claimed in claim 1, including the following steps for use during holding periods when no NG is to be returned to the pipe line,

(a) diverting said mixed stream in step (h) of claim 1 from the gas delivery line and passing it through a heat exchanger to lower its temperature to ambient temperature,

(b) passing said stream from step (a) above through recompression and low-temperature heat exchange means to produce step (d) of claim 1, and recirculating said stream through steps (e) through (g) inclusive of claim 1.

8. The process as claimed in claim 1, in which the low-temperature heat exchange means is cooled by external refrigeration.

9. The process as claimed in claim 8, in which the lowtemperature heat exchange means is in two separate stages,

S the external refrigeration for the rst stage -being a propane refrigeration cycle, and lthe external refrigeration for the second stage being an ethylene refrigeration cycle.

References Cited UNITED STATES PATENTS 2,090,163 8/1937 Twomey 62-40 X 2,535,148 12/1950 Martin et al. 3,116,136 12/1963 Horton et al. 62-20 3,195,316 7/1965 Maher et al. 62,-52 3,257,813 6/1966 Tafreshi 62-23 3,285,719 11/1966 Bodle et al.

NORMAN YUDKOFF, Primary Examiner.

V. W. PRETKA, Assistant Examiner.

Claims (1)

1. A PROCESS FOR LIQUIFYING NATURAL GAS CONTAINING HEAVY HYDROCARBONS AND CO2 FOR STORAGE OF THE LIQUIEFIED NATURAL GAS FOR USE DURING PEAK LOAD PERIODS, WHICH COMPRISES (A) COMPRESSING THE NATURAL GAS STREAM, (B) INJECTING METHANOL INTO THE NATURAL GAS STREAM, (C) COOLING THE COMPRESSED NATURAL GAS STREAM CONTAINING METHANOL TO A POINT AT WHICH SUFFICIENT OF THE HEAVY HYDROCARBONS AND A PORTION OF CO2 ARE CONDENSED AND THE UNCONDENSED LEVEL OF CO2 WILL BE WELL WITHIN THE SOLUBILITY RANGE WHEN FURTHER COMPRESSED AND COOLED, (D) SEPARATING THE LIQUID HEAVY HYDROCARBONS FROM THE GAS STREAM, (E) VAPORIZING THE LIQUID HEAVY HYDROCARBONS BY PASSING IT IN HEAT EXCHANGE WITH THE COMPRESSED NATURAL GAS STREAM CONTAINING METHANOL TO EFFECT IN PART THE COOLING OF STEP (C),

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