Patent Application
20240003618
The present invention relates to a process for recovering liquefied natural gas (LNG) boil-off (BOG) from a storage vessel (also referred to as a storage tank).
In ocean tankers carrying cargoes of liquid natural gas (LNG), as well as land based storage tanks, a portion of the liquid is lost through evaporation as a result of heat leak through the insulation surrounding the LNG storage receptacle. Moreover, heat leakage into LNG storage containers on both land and sea causes some of the liquid phase to vaporize thereby increasing the container pressure. Regulations prohibiting tanker disposal of hydrocarbon-containing streams by venting or flaring within the vicinity of metropolitan areas coupled with an increased desire to conserve energy costs have led to incorporation of reliquefiers into the design of new tankers for recovering LNG BOG .
One existing approach to BOG reliquification has been the use of a compression cycle, in which the BOG is compressed to an elevated pressure, cooled, and expanded before being returned to the storage vessel. The equipment required to compress the BOG is large, which is not ideal on tanker or other floating applications due to space contraints. In addition, the BOG is circulated through portions of the system at high pressure, which creates an elevated risk of leaks of flammable gas.
U.S. Pat. No. 4,843,829 describes an LNG BOG reliquification process in which the predominantly methane BOG is compressed, then cooled sensibly by gaseous nitrogen in a closed loop nitrogen recycle refrigeration process, then condensed using boiling liquid nitrogen.
U.S. Pat. No. 6,192,705 describes an LNG boil-off gas reliquification process in which boil-off gas is condensed in an open loop methane refrigeration cycle where boil-off gas is warmed, compressed, cooled with ambient cooling then flashed to a low pressure to form liquid. In this case the BOG is warmed to ambient temperature before being compressed and cooled.
There is a need for an improved BOG liquification system that is capable of reliquifying BOG without the need for compressing the BOG or the need to subcool the BOG.
This Summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Detailed Description. This Summary is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter.
Several aspects of the systems and methods are outlined below.
The ensuing detailed description provides preferred exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration thereof. Rather, the ensuing detailed description of the preferred exemplary embodiments will provide those skilled in the art with an enabling description for implementing the preferred exemplary embodiments. Various changes may be made in the function and arrangement of elements without departing from the spirit and scope thereof.
Reference numerals that are introduced in the specification in association with a drawing figure may be repeated in one or more subsequent figures without additional description in the specification in order to provide context for other features.
The application includes a plurality of exemplary embodiments. Features that are present in more than one embodiment are represented by reference numerals that differ by a factor of 100. For example, the storage tank 101 of the embodiment of
The term “fluid flow communication,” as used in the specification and claims, refers to the nature of connectivity between two or more components that enables liquids, vapors, and/or two-phase mixtures to be transported between the components in a controlled fashion (i.e., without leakage) either directly or indirectly. Coupling two or more components such that they are in fluid flow communication with each other can involve any suitable method known in the art, such as with the use of welds, flanged conduits, gaskets, and bolts. Two or more components may also be coupled together via other components of the system that may separate them, for example, valves, gates, or other devices that may selectively restrict or direct fluid flow.
The term “conduit,” as used in the specification and claims, refers to one or more structures through which fluids can be transported between two or more components of a system. For example, conduits can include pipes, ducts, passageways, and combinations thereof that transport liquids, vapors, and/or gases.
The term “natural gas”, as used in the specification and claims, means a hydrocarbon gas mixture consisting primarily of methane.
The terms “hydrocarbon”, “hydrocarbon gas”, or “hydrocarbon fluid”, as used in the specification and claims, mean a gas/fluid comprising at least one hydrocarbon and for which such hydrocarbon(s) comprise at least 80%, and more preferably at least 90% of the overall composition of the gas/fluid.
In the claims, letters are used to identify claimed steps (e.g. (a), (b), and (c)). These letters are used to aid in referring to the method steps and are not intended to indicate the order in which claimed steps are performed, unless and only to the extent that such order is specifically recited in the claims.
Directional terms may be used in the specification and claims (e.g., upper, lower, left, right, etc.). These directional terms are merely intended to assist in describing exemplary embodiments, and are not intended to limit the scope thereof. As used herein, the term “upstream” is intended to mean in a direction that is opposite the direction of flow of a fluid in a conduit from a point of reference. Similarly, the term “downstream” is intended to mean in a direction that is the same as the direction of flow of a fluid in a conduit from a point of reference.
As used in the specification and claims, the terms “high-high”, “high”, “medium”, “low”, and “low-low” are intended to express relative values for a property of the elements with which these terms are used. For example, a high-high pressure stream is intended to indicate a stream having a higher pressure than the corresponding high pressure stream or medium pressure stream or low pressure stream described or claimed in this application. Similarly, a high pressure stream is intended to indicate a stream having a higher pressure than the corresponding medium pressure stream or low pressure stream described in the specification or claims, but lower than the corresponding high-high pressure stream described or claimed in this application. Similarly, a medium pressure stream is intended to indicate a stream having a higher pressure than the corresponding low pressure stream described in the specification or claims, but lower than the corresponding high pressure stream described or claimed in this application.
Unless otherwise stated herein, any and all percentages identified in the specification, drawings and claims should be understood to be on a weight percentage basis. Unless otherwise stated herein, any and all pressures identified in the specification, drawings and claims should be understood to mean gauge pressure.
As used in the specification and claims, the term “compression system” is defined as one or more compression stages. For example, a compression system may comprise multiple compression stages within a single compressor. In an alternative example, a compression system may comprise multiple compressors.
Unless otherwise stated herein, introducing a stream at a location is intended to mean introducing substantially all of the stream at the location. All streams discussed in the specification and shown in the drawings (typically represented by a line with an arrow showing the overall direction of fluid flow during normal operation) should be understood to be contained within a corresponding conduit. Each conduit should be understood to have at least one inlet and at least one outlet. Further, each piece of equipment should be understood to have at least one inlet and at least one outlet.
In this embodiment, the condensing heat exchanger 104 is a plate fin heat exchanger 134 located within in a vessel 136 containing boiling liquid nitrogen (LIN). In this embodiment, the condensing heat exchanger 104 is located above the storage tank 101. Alternatively, the condensing heat exchanger 104 could be located inside the storage tank 101, for example, on the surface of a heat exchanging coil containing boiling LIN.
A gaseous nitrogen (GAN) stream 106 is withdrawn from the condensing heat exchanger 104 and combined with an expanded GAN stream 108 to form a combined GAN stream 109. The combined GAN stream 109 is warmed to near ambient temperature in a heat exchanger 110 against a high pressure GAN stream 118 (described herein), forming a warmed GAN stream 112. Alternatively, the expanded GAN stream 108 could be combined with the GAN stream 106 after GAN stream 106 has been partly warmed in the heat exchanger 110. This is depicted by the broken line representing the alternate expanded GAN stream 108A.
The warmed GAN stream 112 is then compressed in a compressor 114 to form a compressed GAN stream 117. The compressed GAN stream 117 is then is cooled to near ambient temperature against cooling water or ambient air (not shown) in a heat exchanger 116 to form a high pressure GAN stream 118. Compressor 114 could optionally include multiple stages of compression with cooling water or air intercoolers (not shown).
The high pressure GAN stream 118 is cooled in the heat exchanger 110 against the combined GAN stream 109 to an intermediate temperature to form a high pressure cooled GAN stream 121. A portion 120 of the high pressure cooled GAN stream 121 is then expanded isentropically in an expander 122. Work produced by the expander 122 may be recovered as electrical energy in a generator, or the expander 122 could be mechanically coupled to the compressor 114 to provide part of the compression energy required to press the warmed GAN stream 112.
The remaining portion 123 of the high pressure cooled GAN stream 121 is then further cooled in heat exchanger 110 exiting as a cooled GAN stream 124, which has a temperature slightly warmer than the GAN stream 106. The cooled GAN stream 124 is flashed across a JT valve 126, forming two phase nitrogen stream 128, which is fed to the shell side of the condensing heat exchanger 104.
In this embodiment, the refrigeration duty for condensation of the BOG stream 100 is provided by nitrogen. In other embodiments, alternate refrigerants could be used, such as argon for example. It is preferable that the refrigerant comprise less than 5 mol % hydrocarbons. This improves safety by using a non-flammable refrigerant in portions of the system 138 that are operated under an elevated pressure. It is also preferable that the refrigerant have a purity of at least 90 mol % and, more preferably, at least 99%. For example, if the refrigerant is nitrogen, then it comprises preferably at least 90 mol % nitrogen. The preferred purity of the refrigerant enables the boiling of the refrigerant in the condensing heat exchanger 104 and compression of the refrigerant in the compression system 114 to be performed more efficiently.
In this embodiment, the condensation of the BOG stream 100 is performed at a substantially constant temperature. In this context, “substantially constant temperature” means that the temperature difference between the BOG stream 100 as it enters the condensing heat exchanger 104 and the partially condensed BOG stream 102 as it exits the condensing heat exchanger is preferably less than 2 degrees Celsius.
The heat exchanger 110 may also be used to condense a warm natural gas stream 130 to form a condensed natural gas stream 131. In addition, a supplemental LIN refrigeration stream 132 could optionally be directed to the cold end of the condensing heat exchanger 104.
It is important to note that, even in the embodiment shown in
For storage tanks 301 in which the LNG contains a substantial nitrogen fraction, the exemplary embodiment shown in
Another exemplary embodiment of the BOG re-condensing system 538 is shown in
When the boil-off rate is at the design capacity of the BOG re-condensing system 538, the pressure of the storage tank 501 (measured by PV2) is at the setpoint SP2 and valve 564 is fully or nearly fully open. If the boil-off rate decreases below the design capacity, the pressure in the storage tank 501 will begin to fall and the pressure controller 560 will respond by increasing the setpoint SP1 to the valve controller 562, which will respond by partly closing valve 564, thereby increasing the pressure of the boiling LIN and in turn increasing the LIN temperature which decreases the driving force for heat transfer and the cooling duty so that the tank pressure is maintained at the setpoint. The pressures downstream of 564 and upstream of the JT valve 526 drop because the valve is closing and the mass flowrate of nitrogen is decreasing, while the volumetric flowrate remains roughly the same, allowing compressor 514 to continue to operate at or near peak efficiency. The liquid level in the condensing heat exchanger 504 increases because the inventory of gaseous nitrogen in the system decreases due to the reduced pressures on both the suction and discharge circuits connected to 514, and in heat exchanger 510. This method of turndown reduces the mass flowrate and power consumption of the compressor 514 by reducing system gaseous inventory without loss of nitrogen refrigerant.
Conversely, if the boil-off rate increases, the pressure controller 560 will respond by increasing the setpoint to the valve controller 562, which will respond by opening valve 564, thereby increasing the pressure of the boiling LIN and decreasing the temperature of the LIN which increases the driving force for heat transfer and the cooling duty so that the storage tank 501 pressure is maintained at the setpoint SP2. The liquid level in 504 then decreases, bringing additional nitrogen inventory into circulation and raising the pressures in the system downstream of valve 564 and upstream of the JT valve 526.
As mentioned previously, the output OP2 of the pressure controller 560 is normally used as the setpoint SP1 of the valve controller 562. At boil-off rates above the design point, the cooling duty may be such that the power needed approaches the maximum power available from the motor 570 used to drive the compressor 514. To prevent motor overload, a power controller 572 is provided. The power controller 572 compares the power consumption of the motor PV3 to the user supplied setpoint SP3 (the maximum allowed power). If the boil-off rate is high and the power consumption PV3 approaches the setpoint SP3, the output OP3 from power controller 572 increases. This output OP3 is compared to the output OP2 from the pressure controller 560 in a selector block 574, which passes the larger value as a setpoint SP1 to the valve controller 562. If the output OP3 from the power controller 572 is greater than the output OP2 from the pressure controller 560, the power controller output OP3 will override the pressure controller output OP2 to prevent overload of the motor 570. In that case, the pressure in the storage tank 501 will exceed the setpoint SP2 and may activate pressure relief valves (not shown) and send excess BOG to flare or vent.
Another feature of the control system is to maintain a constant temperature difference between the temperatures of the combined GAN stream 109 entering the cold end of the heat exchanger 510 (measured at PV6) and the cooled GAN stream 524 exiting the cold end of the heat exchanger 510 (measured at PV7). This temperature difference PV4 is measured by FY and fed by signal PV4 to a temperature difference controller 566. The temperature difference controller 566 maintains the temperature difference PV4 at an operator supplied setpoint SP4 by manipulating the setpoint SP5 of a flow controller 568. The flow controller 568, in turn, controls the position of the JT valve, which controls the flow rate of nitrogen through the JT valve 526. If the temperature difference PV4 at the cold end of the heat exchanger 510 begins to exceed the setpoint SP4, the temperature difference controller 566 will decrease the setpoint SP5 to the flow controller 568. The flow controller 568 will, in turn, begin to close the JT valve 526, reducing the flow of the cooled GAN stream 524 which will reduce the temperature difference PV4.
In this exemplary embodiment, the expander 522 is equipped with flow control nozzles 576 that can be adjusted manually to change the flowrate and the outlet-inlet pressure difference across the expander 522 and the compressor 514 to improve efficiency.
Table 1 shows stream data for an example of a process conducted in accordance with the system of
The present invention has been disclosed in terms of preferred embodiments and alternate embodiments thereof. Of course, various changes, modifications, and alterations from the teachings of the present invention may be contemplated by those skilled in the art without departing from the intended spirit and scope thereof. It is intended that the present invention only be limited by the terms of the appended claims.
This application is a continuation of U.S. application Ser. No. 16/750,534 filed on Jan. 23, 2020, which is incorporated by reference herein in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16750534 | Jan 2020 | US |
| Child | 18219808 | US |
