KR20170083969A - Reducing refrigeration duty on a refrigeration unit in a gas processing system - Google Patents

Abstract

The liquefaction process of the present invention is configured to facilitate heat transfer in the heat exchanger during liquefaction of the natural gas feedstock. Wherein the liquefaction process comprises compressing a process stream primarily comprising methane to a first pressure, cooling the process stream to a first temperature, and cooling the process stream from the first pressure to a pressure lower than the first pressure Expanding the first product to a second pressure, withdrawing the first product from the process stream at the second pressure, and regulating the first product to be stored as liquefied natural gas (LNG).

Description

Reducing Cooling Duty in a Cooling Unit of a Gas Treatment System [0002]

Liquefied natural gas can facilitate transport and storage of hydrocarbons and related materials. In general, these processes greatly reduce the volume of gas. The resulting liquid is suitable for long-haul transport through pipelines and infrastructure. This is particularly economical to transport to overseas and / or to areas that are not accessible to the above pipeline infrastructure.

The subject matter of the present application is generally directed to a liquefaction process. Embodiments deal with the cooling requirements of a heat exchanger (or "cold box") needed to liquefy an incoming hydrocarbon feed into a liquefied product. In one application, embodiments include a fluid circuit for liquefying a natural gas feed with liquefied natural gas (LNG).

As will be discussed further below, the improvements provide many capabilities and / or advantages to the embodiments of the present invention. The fluid circuit may be responsible for a portion of the duty cycle of the primary cooling unit that cools the heat exchanger. This feature may allow embodiments to expand or increase the production of the LNG product to a level that generally surpasses the operation of certain equipment (e.g., a compressor) in the liquefaction system. Through the use of embodiments, the liquefaction system will be able to increase the production level by about 80% using a default or initial configuration, or for example increase the production from 450,000 gpd to about 800,000 gpd . In addition, liquefaction systems that supplement the cooling of the heat exchanger using embodiments can operate at a higher or equal efficiency, especially at a production level of less than 700,000 gpd, as compared to other auxiliary cooling systems (e.g., propane precooling) .

These production improvements may limit capital costs and / or operational costs. The liquefaction system comprising the fluidic circuit of the embodiments of the present application requires little design changes to the primary cooling system. This feature can eliminate the need to replace refrigerant and / or other components of the equipment, lines, controls, and / or the primary cooling system.

The embodiments may find use in various types of processing facilities. These facilities can be found on land and / or in the sea. In one application, embodiments may be integrated into and / or included as part of processing facilities located on land, typically on the coast (or in the vicinity). These processing facilities can process natural gas feedstocks from production facilities found both onshore and offshore. Terrestrial production facilities use pipelines to transport feedstock extracted from oilfields, which are full of gas fields and / or gas and have high oil reserves, and in some cases deep-sea wells, to a treatment facility. In the case of LNG treatment, the treatment facility can transform the feedstock into liquid using appropriately configured cooling equipment or "trains". In other applications, embodiments may be incorporated into a production facility on board a vessel (or similar floating vessel), also known as a floating liquid natural gas (FLNG) facility.

Briefly, reference is now made to the accompanying drawings in which:
1 shows a flow diagram of an exemplary embodiment of a process for liquefying a hydrocarbon feedstock to liquefied natural gas (LNG) for storage;
Figure 2 shows a flow diagram of an example of the process of Figure 1;
Figure 3 shows a schematic diagram of an exemplary embodiment of a system in which an incoming hydrocarbon feedstock can be liquefied into a product that meets specifications for liquefaction to liquefied natural gas (LNG);
Figure 4 shows a schematic diagram of an example of the system of Figure 3, which is capable of receiving an influent hydrocarbon feedstock having a high level of impurities;
Figure 5 shows a schematic diagram of a first configuration of the components forming the fluid circuit in the example of the system of Figure 3;
Figure 6 shows a schematic diagram of a second configuration of the components forming the fluid circuit in the example of the system of Figure 3;
Figure 7 shows a schematic diagram of an example of the system of Figure 3, which is capable of receiving an influent hydrocarbon feedstock having a high level of impurities;
Figure 8 shows a schematic view of an example of the system of Figure 7; And
Figure 9 shows a schematic view of an example of the system of Figure 7;
Where appropriate, like reference numerals refer to the same or corresponding components and units throughout the several views, wherein the several views are not drawn to scale unless otherwise specified. Embodiments disclosed herein may include elements that appear in one or more of the several figures above or in combinations of the several figures. Furthermore, the methods are merely exemplary and may be altered, for example, by rearrangement, addition, removal and / or modification of the individual stages.

Figures 1 and 2 show a flow diagram of an exemplary embodiment of a process 10 for liquefying an incoming hydrocarbon feedstock. As shown in Fig. 1, embodiments may include a step 12 for receiving a feedstock and a step 14 for forming a process stream from the feedstock, which mainly comprises methane at a concentration of 92% or more. The process 10 may also include a step 16 of compressing the process stream to a first pressure and a step 18 of cooling the process stream to a first temperature. The process 10 may further comprise a step 20 of inflating the process flow from the first pressure to a second pressure which is lower than the first pressure. The process 10 may include a step 22 of withdrawing a first flow from the process flow of the second pressure and a step 24 of regulating the first flow to be stored as liquefied natural gas (LNG). In one implementation, the process 10 may include a step 26 of compressing the process flow from the second pressure to an intermediate pressure between the first pressure and the second pressure. Thereafter, the process 10 may proceed to step 16 to further compress the process flow.

In the example of FIG. 2, the process 10 may include various steps to accommodate a higher level of impurities in the incoming hydrocarbon feedstock at step 14. The process 10 may include a step 28 of separating the feedstock into a first stream and a first bottoms product. Process 10 may also include a step 30 of introducing said first flow into said intermediate pressure process flow. In one embodiment, the process 10 includes the steps of distilling the first bottom product to form a second stream and a second bottom product, introducing the second stream into the process stream of the second pressure, 34 < / RTI > Process 10 may further comprise adjusting 36 the second bottom product to form liquefied petroleum gas (LPG).

Figure 3 shows a schematic diagram of an exemplary embodiment of a gas processing system 100 (also referred to as "system 100") for use in processing natural and similar hydrocarbon materials. The system 100 may include an expansion unit 102 and a cooling unit 104, each connected to a heat exchanger 106. Examples of heat exchanger 106 or "cold box" may be characterized by soldered aluminum fins ("plate-pin exchanger") and / or coils ("coil rewinder"). These devices can enable heat transfer by indirect contact between fluids. The fluids may include a refrigerant 108 that the cooling unit 104 circulates to the heat exchanger 106. Examples of refrigerant 108 may have a composition comprising one or more components including light hydrocarbons (e.g., methane, ethane, propane, etc.) and / or nitrogen. In one embodiment, the composition is consistent with a "mixed" refrigerant cycle.

The expansion unit 102 may be configured to reduce the duty cycle of the cooling unit 104 required to cool the heat exchanger 106. The configurations described above may be used in place of an auxiliary or supplemental cooling unit (e.g., a propane cooler) that is capable of supplemental cooling and / or precooling fluid in heat exchanger 106. The expansion unit 102 may include a fluid circuit 110 that circulates the fluid to the heat exchanger 106. For clarity, the fluid circulating in the fluid circuit 110 is identified as the process flow 112. An example of process flow 112 may have a composition that is primarily methane in liquid and / or vapor form. In one implementation, the fluid circuit 110 may be configured to extract the first product 114 from the process flow 112. The first product 114 may meet specifications for LNG. The system 100 can send the first product 114 from the heat exchanger 106 to the storage facility 116 or, if desired, to another post-liquefaction facility. In particular, through the use of the expansion unit 102, the production level range of the LNG product (e.g., the first product 114) in the system 100 can be extended. It is reasonable for the system 100 to be able to extend the production level of the LNG product from about 450,000 gpd to about 800,000 gpd.

The system 100 may operate on incoming natural gas and similar hydrocarbon streams. As shown in FIG. 1, the fluid circuit 110 may receive the flow as a feedstock 118 from a source 120. The source 120 may include pretreatment equipment for treating natural gas from a production facility (e.g., a wellhead, pipeline, etc.). As a result of the above processes, a "dry sweet gas" may be produced that has predominantly methane (e.g., a concentration of 84% (840,000 ppmV or greater) and water at a concentration of less than 0.0001% (1 ppmV). In the case of a composition where the level of impurities is significantly lacking, the fluid circuit 110 may be configured to circulate the feedstock 118 directly as process stream 112. These compositions may, for example, have a methane concentration of 98% (980,000 ppmV) or greater. However, at least one advantage of the expansion unit 102 is that it can be configured in such a way that impurities can be removed from the feedstock 118, either before or upstream of the fluid circuitry 110.

Figure 4 illustrates an example of a system 100 that can handle the composition of a feedstock 118 having a higher level of impurities. At a high level, the expansion unit 102 may include a pretreatment unit 122 upstream of the fluid circuit 110. The preprocessing unit 122 may receive the feedstock 118 from the source 120 via pipelines and / or other aspects. In one implementation, the preprocessing unit 122 may form a feed stream 124 and a second product 126. The system 100 may send the feed stream 124 to the fluid circuit 110 for use as a process stream 112. The second product 126 may be a derivative product useful in fuel. Such derivatized products may have compositions of hydrocarbon gases (e.g., propane, butane, etc.) and / or similar components. The composition may be consistent with a liquefied petroleum gas (LPG) product. The system 100 may be configured to send the above LPG product to the secondary system 128 for further processing and / or for storage in, for example, a tank.

Figure 5 shows a first configuration of components for implementing the fluid circuit 110. [ This first configuration forms an open loop for circulating the process flow 112 to the heat exchanger 106. The open loop preferably includes a turbo machine 130 having a turbo compressor 132 configured to operate in response to work from the turboexpander 134. [ The turbo compressor 132 may have an inlet 136 and an outlet 138 connected to the heat exchanger 106 and the methane compressor 140, respectively. 6, the turboexpander 134 may have an inlet 142 and an outlet 144. The inlet 142 and the outlet 144 may be provided in the turbo expander 134, as shown in FIG. The inlet 142 may be connected to the heat exchanger 106. The outlet 144 can be connected to a first separation unit 146, which itself is connected to a heat exchanger 106.

Beginning with the methane compressor (140), the fluid circuit (110) can use the feedstock (118) from the source (120) without any upstream processing. This first configuration may be useful in the case of inflowing natural gas with a low level of impurities. In one embodiment, the feedstock feedstock 118 is introduced into the methane compressor 140, typically at a temperature of about 80 ℉ to about 120.. The methane compressor 140 may be configured to receive an inlet pressure for the feedstock 118 above about 450 psig. However, it should be appreciated that the present invention may be configured such that the methane compressor 140 and the fluid circuitry 110, as needed, use the system 100 over a variety of applications to accommodate inlet pressure, which generally varies with the source 120 . This configuration can change the location (s) where the incoming feedstock 118 is introduced into the process stream 112 in the methane compressor 140.

The methane compressor 140 may be configured to change the temperature and pressure of the process stream 112. These configurations can flow the process stream 112 through one or more cooling devices (e.g., an air cooler). In this manner, the process flow 112 may exit the methane compressor 140 to a temperature of about 20 degrees Fahrenheit (about 20 degrees Fahrenheit) above the ambient temperature prevailing at the location of the system 100. In one embodiment, the methane compressor 140 may also pressurize the process stream 112 such that the process flow 112 (at 148) is at a pressure of 1200 psig. The pressure may be selected based on configuration considerations (e.g., flange rating) for the fluid circuit 110; For example, operating the system 100 at a pressure that does not exceed 1200 psig requires flanges rated below 600 lbs, potentially resulting in significant cost savings. Other temperatures and pressures for process flow 112 (at 148) may also be useful.

The system 100 may send the process flow 112 across the first pass of the heat exchanger 106 to further lower the temperature. The heat exchanger 106 is configured to allow the process stream 112 to enter the inlet 142 of the turboexpander 134 at a temperature of about -90 DEG F and / or otherwise in a range of about -70 DEG F to about -110 DEG F . Accordingly, the turboexpander 134 can reduce the pressure of the process stream 112. For example, process flow 112 may exit turbo expander 134 (at 150) as a mixed phase effluent (e.g., liquid and vapor). Process flow 112 (at 150) may have an outlet pressure to ensure efficient operation of system 100. An example of a turboexpander 134 is that the outlet pressure can operate to maintain an expansion ratio of 3 to 4 with the pressure of process flow 112 (at 148); The present application contemplates that, if desired, the outlet pressure can maintain the expansion ratio in the range of 3 to 10. In one example, the outlet pressure may range from about 285 psig to about 385 psig to regulate the operation of the methane compressor 140 to pressurize the process stream 112 to 1200 psig.

The fluid circuit 110 sends the process flow 112 from the turboexpander 134 to the first separation unit 146. Through the processing of process stream 112 in first separation unit 146, bottom product 152 and top product 154 can be obtained. These products 152 and 154 exit the bottom and top of the first separation unit 146, respectively, in liquid form and in vapor form. The liquid bottom product 152 passes through the second pass of the heat exchanger 106. The second pass reduces the temperature to regulate the liquid bottom product 152 to form a first product 114, typically at a temperature and / or at a temperature that is stored in the storage facility 116. The storage temperature may range from about -250 [deg.] F to about -270 [deg.] F.

The vapor overhead product 154 subsequently forms a process stream 112 that circulates the fluid circuit 110. In one implementation, the fluid circuit 110 passes the process flow 112 through the third pass of the heat exchanger 106. This third pass can reduce the temperature of the process stream 112 by discharging thermal energy to the fluid within one of the other passes of the heat exchanger 106. The system 100 may be configured such that the temperature of the process stream 112 at the inlet 136 of the turbo compressor 132 ranges from about 80 ℉ to about 120..

Turbo compressor 132 may press process flow 112. In one embodiment, the turbo compressor 132 is preferably operatively connected to the discharge (or first) pressure 148 of the methane compressor 140 and the discharge (or second) pressure 150 of the turboexpander 134, (At 156) at an intermediate pressure, e.g. This intermediate pressure may range from about 400 psig to about 600 psig. The fluid circuit 110 may send the intermediate pressure process stream 112 back to the methane compressor 140. As noted above, the fluid circuit 110 may introduce the feedstock 118 into the process stream 112 so that the resulting mixed stream exits the methane compressor 140 (at 148).

6 shows a second configuration of the components for implementing the fluid circuit 110. As shown in Fig. The methane compressor 140 includes a compression circuit 158 having a first end 160 and a second end 162 that are connected to the turbo compressor 132 and the heat exchanger 106, respectively. At a high level, the compression circuit 158 may be configured to increase the pressure without raising the temperature of the process stream 112 from the first end 160 to the second end 162. These functions may utilize various components (e.g., cooler, compressor, etc.). In one embodiment, the compression circuit 158 may include one or more coolers (e.g., a first cooler 164, a second cooler 166, and a third cooler 168). The coolers 164, 166, 168 may be air-cooled, but this does not limit the choice of any particular type or variation for these devices. The compression circuit 158 may also include one or more compressors (e.g., a first compressor 170 and a second compressor 172). The compressors 170 and 172 are disposed between adjacent coolers 164,166 and 168 to maintain and / or elevate the pressure of the process stream 112 (at 148) .

7 shows an example of a preprocessing unit 122 for use in the system 100. As shown in FIG. In one embodiment, the pretreatment unit 122 may include a second separation unit 174 coupled with the demethanizer unit 176. The second separation unit 174 may remove heavy hydrocarbons from the feedstock 118. This feature is useful to avoid problems with the system 100 due to freezing of impurities on the downstream side and / or in the reservoir, for example, the storage facility 116. Demethanizer unit 176 is capable of recovering light hydrocarbons (e.g., methane). Each unit 174 and 176 may be individually connected to the fluid circuit 110 at one or more locations such as the first location 178 and the second location 180. In the first location 178, Separator unit 174 is connected to the compression circuit 158 of the methane compressor 140. At the second location 180 the demethanizer unit 176 is connected to the turboexpander 134 and the first separation unit 146 Respectively.

The pretreatment unit 122 may remove impurities from the feedstock 118 on the upstream side of the fluid circuit 110. In use, the feedstock 118 may pass through the fourth pass of the heat exchanger 106. The fourth pass may lower the temperature of the feedstock 118 to a range of about-80 < 0 > F to about -110 < 0 > F. The cooled feedstock 118 enters the second separation unit 174 to remove impurities (e.g., heavy hydrocarbons). In one embodiment, the second separation unit 174 forms a first stream 182 and a first lower product 184 that exit the lower and upper portions of the second separation unit 174, respectively, in vapor and liquid form . Steam first stream 182 primarily comprises methane vapor, typically at a concentration of about 92% (920,000 ppmV) to about 97% (970,000 ppmV). The system 100 passes the vapor first stream 182 through the fifth pass of the heat exchanger 106 and into the compression circuit 158 at the first location 178. The fifth pass may increase the temperature of the steam first stream 182 to a range of about 80 ℉ to about 120..

The system 100 sends the first bottom product 184 to the demethanizer unit 176. In one embodiment, the demethanizer unit 176 is configured to form a second stream 186 and a second bottom product 188 that exit the lower and upper portions of the demethanizer unit 176 in liquid and vapor form, respectively, . Steam second stream 186 typically comprises methane vapor, typically at a concentration of about 92% (920,000 ppmV) to about 97% (970,000 ppmV). The system 100 may send the steam second stream 186 to substantially bypass the heat exchanger 106 and enter the fluid circuit 110 at the second location 180. The second bottom product 188 may form a second product 126 that is directed to the secondary system 128 and / or to processing at an additional facility downstream of the system 100.

Figure 8 illustrates an example of a system 100 having additional components that may be useful in regulating the pressure (and / or temperature) of the fluid. The system 100 may include one or more expansion valves (e.g., a first expansion valve 190, a second expansion valve 192, and a third expansion valve 194). J-T valves and similar devices may be suitable for use as valves 190, 192, and 194. The pretreatment unit 122 may include a reboiler 196 for boiling the second bottom product 188 from the demethanizer unit 176. Boiling produces steam that is sent back to demethanizer unit 176.

Figure 9 shows an example of a system 100 that also has additional components for accommodating specific production levels and / or other process changes as needed. The system 100 may include a third separation unit 198 that is upstream of the turboexpander 134 and interposed with the heat exchanger 106. Steam from the third separation unit 198 enters the turboexpander 134. The liquid from the third separation unit 198 is mixed with the effluent (at 150) from the turboexpander 134, preferably on the upstream side of the first separation unit 146.

The third separation unit 198 may be useful to prevent a mixed phase feed that may occur at a particular production level where the temperature of the inflow to the turboexpander 134 may fall below the bubble point. This embodiment alters the process so that a portion (at 150) of the vapor from the effluent can be added to the effluent resulting from the expansion and fed to the heat exchanger 106. Other embodiments may use an inflator recycle loop with a maximum pressure of about 700 psig and an inflation pressure of about 285 psig. At these pressures, steam from the second separation unit 174 may be fed directly to the turboexpander 134 bypassing the heat exchanger 106 to prevent elevated temperatures. In addition, this configuration can also eliminate the compression of steam.

In view of the foregoing, the embodiments are not inferior to other cooling techniques that may supplement any primary cooling, for example, as provided by the mixed-refrigerant cycle discussed herein.

As used herein, unless an element or function described in the singular and accompanied by an indefinite article explicitly states that a plurality of such elements or functions are excluded, a plurality of the above elements or functions may be excluded It should be understood that it does not. Also, reference to "one embodiment" should not be construed as excluding the existence of additional embodiments that also include the listed features.

This specification uses embodiments to disclose the embodiments, including the most preferred versions, and to enable any person skilled in the art to make use of the embodiments disclosed, wherein such embodiments include any device or system Use, and any accompanying method, and the like. The patentable scope of embodiments is defined by the claims, and may include other embodiments that come to the attention of those skilled in the art. It is to be understood that these other embodiments are intended to be encompassed within the scope of the following claims unless they have equivalent structural elements that have structural elements that do not differ from the literal representation of the claims or that do not substantially differ from the literal representations of the claims .

Claims (20)

As a liquefaction process,
Compressing the process flow to a first pressure;
Cooling the process stream to a first temperature;
Expanding the process flow from the first pressure to a second pressure lower than the first pressure;
Withdrawing the first product from the process flow of the second pressure; And
Adjusting the first product to be stored as liquefied natural gas (LNG)
≪ / RTI > The method according to claim 1,
Compressing the process flow from the second pressure to an intermediate pressure between the first pressure and the second pressure. 2. The liquefaction process of claim 1, wherein the process flow comprises the liquid at the first pressure. 4. The liquefaction process of claim 3, wherein the process flow comprises both vapor and liquid at the second pressure. 2. The liquefaction process of claim 1, wherein the first pressure and the second pressure form a ratio in the range of 3 to 10. < Desc / Clms Page number 13 > The method according to claim 1,
Further comprising forming the process stream from a feedstock having a methane concentration of at least 84%. The method according to claim 6,
Further comprising forming a first stream and a second stream, each comprising primarily methane vapor, from a feedstock, wherein the process stream comprises the first stream and the second stream. 8. The method of claim 7,
Introducing the first flow into the intermediate pressure process flow. 8. The method of claim 7,
Introducing the second flow into the process flow of the second pressure. 8. The method of claim 7,
Separating the feedstock into the first stream and the first bottoms product;
Further comprising distilling the first bottom product to form the second stream and the second bottom product. As a gas processing system,
heat transmitter;
A fluid circuit coupled to the heat exchanger, the process fluid passing through the heat exchanger,
The fluid circuit comprising:
Compressing the process flow to a first pressure;
Passing the process flow through the heat exchanger at the first pressure;
Expanding the process flow from the first pressure to a second pressure lower than the first pressure;
Withdrawing a first flow from the process flow of the second pressure; And
And to regulate the first flow to be stored as liquefied natural gas (LNG). 12. The method of claim 11,
And a cooling unit connected to the heat exchanger,
Wherein the cooling unit is configured to circulate the refrigerant in the heat exchanger. 12. The gas processing system of claim 11, wherein the fluid circuit is configured to receive a feedstock and to circulate the feedstock as a process stream. 14. The method of claim 13,
A pretreatment unit coupled to the fluid circuit and the heat exchanger,
A separation unit configured to receive the feedstock at a downstream side of the heat exchanger; And
A demethanizer unit connected downstream of the separation unit,
Further comprising a pre-processing unit,
Wherein the separation unit and the demethanizer unit are configured to respectively form a first flow and a second flow comprising methane vapor,
Wherein the process flow includes the first flow and the second flow. As a gas processing system,
heat transmitter; And
A fluid circuit coupled to the heat exchanger and configured to circulate a process flow to the heat exchanger,
The fluid circuit comprising:
A methane compressor connected to the heat exchanger;
A turbo compressor interposed between the methane compressor and the heat exchanger;
A turbo expander connected to the turbo compressor and the heat exchanger; And
And a first separator unit interposed between the turboexpander and the heat exchanger. 16. The method of claim 15 wherein the methane compressor is configured to press the process flow to a first pressure and the turboexpander is configured to expand the process flow to a second pressure, Is in the range of 3 to 10. < Desc / Clms Page number 13 > 17. The gas treatment system of claim 16, wherein the turbo compressor is configured to pressurize the process flow to an intermediate pressure between the first pressure and the second pressure. 18. The gas treatment system of claim 17, wherein the methane compressor is configured to pressurize the process flow from the intermediate pressure to a first pressure. 16. The method of claim 15,
A second separation unit connected to the heat exchanger and the methane compressor; And
And a demethanizer unit connected to the second separation unit and the first separation unit. 16. The method of claim 15,
Further comprising an expansion valve disposed downstream of the first separation unit and the heat exchanger.

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