Patent Grant
10544986
Liquefaction systems for cooling, liquefying, and optionally sub-cooling natural gas are well known in the art, such as the single mixed refrigerant (SMR) cycle, the propane pre-cooled mixed refrigerant (C3MR) cycle, the dual mixed refrigerant (DMR) cycle, C3MR-Nitrogen hybrid (such as AP-X™) cycles, the nitrogen or methane expander cycle, and cascade cycles. Typically, in such systems, natural gas is cooled, liquefied, and optionally sub-cooled by indirect heat exchange with one or more refrigerants. A variety of refrigerants might be employed, such as mixed refrigerants, pure components, two-phase refrigerants, gas phase refrigerants, etc. Mixed refrigerants (MR), which are a mixture of nitrogen, methane, ethane/ethylene, propane, butanes, and pentanes, have been used in many base-load liquefied natural gas (LNG) plants. The composition of the MR stream is typically optimized based on the feed gas composition and operating conditions.
The refrigerant is circulated in a refrigerant circuit that includes one or more heat exchangers and one or more refrigerant compression systems. The refrigerant circuit may be closed-loop or open-loop. Natural gas is cooled, liquefied, and/or sub-cooled by indirect heat exchange against the refrigerants in the heat exchangers.
Each refrigerant compression system includes a compression circuit for compressing and cooling the circulating refrigerant, and a driver assembly to provide the power needed to drive the compressors. The refrigerant compression system is a critical component of the liquefaction system because the refrigerant needs to be compressed to high pressure and cooled prior to expansion in order to produce a cold low pressure refrigerant stream that provides the heat duty necessary to cool, liquefy, and optionally sub-cool the natural gas.
A majority of the refrigerant compression in base-load LNG plants is performed by dynamic or kinetic compressors, and specifically centrifugal compressors, due to their inherent capabilities including high capacity, variable speed, high efficiency, low maintenance, small size, etc. Other types of dynamic compressors such as axial compressors and mixed flow compressors have also been used for similar reasons. Dynamic compressors function by increasing the momentum of the fluid being compressed. Positive displacement compressors may also be used, although they have much lower capacity than typical dynamic compressors, and function by reducing the volume of the fluid being compressed.
There are three main types of drivers that have been used for LNG service, namely gas turbines, steam turbines, and electric motors.
In some scenarios, the LNG production rate may be limited by the installed refrigerant compressor. One such scenario is when the compressor operating point is close to surge. —Surge is defined as an operating point at which the maximum head capability and minimum volumetric flow limit of the compressor are reached. An anti-surge line is an operating point at a safe operating approach to surge. An example of such a scenario for a C3MR cycle is at high ambient temperature where there is an increased load on the propane pre-cooling system causing the maximum head and thereby lowest allowable flow rate to be reached. Therefore, the refrigerant flow rate is limited, which then limits the refrigeration and LNG production rate.
Another scenario where the LNG production rate is limited by the installed refrigerant compressor is when the compressor is close to stonewall or choke. Stonewall or choke is defined as the operating point where the maximum stable volumetric flow and minimum head capability of the compressor are reached. An example of such a scenario is when the plant is fully loaded and is running at maximum LNG capacity. The compressor cannot take any more refrigerant flow through it and the plant is therefore limited by the compressor operation.
A further scenario where the LNG production may be limited by the installed refrigerant compressor is for large base-load facilities where the compressor operating points are limited by compressor design limits, such as the flow coefficient, the inlet Mach number, etc.
In some scenarios, the LNG production is limited by the available driver power. This can happen when the plant is operating at high LNG production rates. It can also happen for plants with gas turbine drivers at high ambient temperature due to reduced available gas turbine power.
Standard dynamic compressors utilized in the LNG industry comprise a single casing with one or more inlets and a single outlet. In case of multiple inlets, the casing also comprises chambers to mix the inlet streams with the discharge from previous compressor stages. For instance, a second compressor stage with two inlet streams would require a mixing chamber to mix the inlet stream with the discharge stream from the first compressor stage.
One approach to debottleneck the refrigerant compression system is to add a dynamic compressor, similar to one described above, such as a centrifugal compressor, with its driver at the discharge of the primary compressor. This helps build more head into the compression system for a scenario where the compressor is operating close to surge. Adding an additional dynamic compressor at the discharge of the primary compressor has limited benefits when the compressor is operating close to stonewall. Therefore, the addition of the additional dynamic compressor will not solve the problem of maximum flow constraint.
Another approach has been to add one or more dynamic compressors such as centrifugal compressors in parallel with the primary compressor. While this helps de-bottleneck the primary compressor to some extent, it may not be sufficient or efficient. This method debottlenecks the different compressor stages in the primary compressor by the same amount. However, certain stages may still be at their limits and may need further debottlenecking.
Overall, a single stage dynamic compressor in parallel with the primary compressor may lead to a suboptimal design. Therefore, what is needed is a compact and more efficient method of debottlenecking loaded compression systems in an LNG plant.
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.
Some embodiments provide, as described below and as defined by the claims which follow, comprise improvements to compression systems used as part of an LNG liquefaction processes. Some embodiments satisfy the need in the art by using a double flow compressor in parallel with the primary compression circuit in one or more of the refrigerant compression systems of an LNG liquefaction plant, thereby enabling the plant to operate under conditions that would otherwise limit plant capacity.
In addition, several specific aspects of the systems and methods are outlined below.
Aspect 1: A compression system operationally configured to compress a first stream of a first refrigerant having a first pressure to produce a first compressed refrigerant stream having a fully-compressed pressure, the compression system comprising:
at least one pre-cooling heat exchanger, each of the at least one pre-cooling heat exchangers being operationally configured to cool a hydrocarbon fluid by indirect heat exchange against the first refrigerant;
a primary compression circuit having a plurality of primary compressor stages and a plurality of a partially-compressed streams, each of the plurality of compressor stages having a suction side and a discharge side, each of the plurality of partially-compressed streams being in fluid flow communication with an outlet of one of the plurality of primary compressor stages and an inlet of another of the plurality of primary compressor stages, each of the plurality of partially-compressed streams having a pressure that is higher than the first pressure and lower than the fully-compressed pressure, the pressure of each of the plurality of partially-compressed streams being different than the pressure of every other of the plurality of partially-compressed streams, a final primary compressor stage of the plurality of primary compressor stages having an outlet that produces a first portion of the first compressed refrigerant steam;
a secondary compression circuit comprising a double flow compressor having a casing that defines an internal volume, a first inlet, a second inlet, and an outlet that produces a second portion of the first compressed refrigerant stream, the second portion of the first compressed refrigerant stream being in fluid flow communication with the first portion of the first compressed refrigerant stream, the casing further comprising a first compressor stage and a second compressor stage located in the internal volume, the first compressor stage having a first suction side, a first discharge side, at least one first impeller, and at least one first diffuser, the second compressor stage having a second suction side, a second discharge side, at least one second impeller, and at least one second diffuser, the first suction side being distal to the second suction side, and the first discharge side being proximal to the second discharge side;
a first side stream located downstream from and in fluid flow communication with a first pre-cooling heat exchanger of the at least one pre-cooling heat exchanger, the first side stream having a first side stream pressure and a first portion that is in fluid flow communication with a first partially-compressed first refrigerant stream of the plurality of partially-compressed streams to form a first mixed stream that is upstream from and in fluid flow communication with an inlet of a first primary compressor stage of the plurality of primary compressor stages, the first side stream having a second portion that is in fluid flow communication with the first inlet of the double-flow compressor; and
a second side stream downstream from and in fluid flow communication with a second pre-cooling heat exchanger of the at least one pre-cooling heat exchanger, the second side stream having a second side stream pressure and a first portion that is in fluid flow communication with a second partially-compressed first refrigerant stream of the plurality of partially-compressed streams to form a second mixed stream that is upstream from and in fluid flow communication with an inlet of a second primary compressor stage of the plurality of primary compressor stages, the second side stream having a second portion that is in fluid flow communication with the second inlet of the double flow compressor;
wherein the first inlet is located on the first suction side of the first compressor stage, the second inlet is located on the second suction side of the second compressor stage, and the outlet is located proximal to the first discharge side and the second discharge side.
Aspect 2: The compression system of Aspect 1, wherein the at least one first impeller consists of a first number of impellers, each having a first impeller geometry, the at least one second impeller consists of a second number of impellers, each having a second impeller geometry, the at least one first diffuser each having a first diffuser geometry, and the second at least one second diffuser having a second diffuser geometry; and
wherein the first compressor stage differs from the second compressor stage by at least one selected from the group of: (a) the first number of impellers is different from the second number of impellers, (b) the first impeller geometry is different from the second impeller geometry, and (c) the first diffuser geometry is different from the second diffuser geometry.
Aspect 3: The compression system of Aspect 2, wherein the first number of impellers is different from the second number of impellers.
Aspect 4: The compression system of Aspect 2, wherein the first number of impellers is greater than the second number of impellers.
Aspect 5: The compression system of any of Aspects 1-3, wherein the casing further comprises a mixing chamber that is proximal to the first and second discharge sides.
Aspect 6: The compression system of any of Aspects 1-4, wherein the first refrigerant is propane.
Aspect 7: The compression system of any of Aspects 1-6, wherein the compression system is further operationally configured to inter-cool the first refrigerant between at least two of the plurality of primary compressor stages of the primary compression circuit.
Aspect 8: The compression system of any of Aspects 1-7, further comprising a main heat exchanger operationally configured to further cool and liquefy the hydrocarbon fluid by indirect heat exchange between the hydrocarbon fluid and a second refrigerant after the hydrocarbon fluid has been cooled by the at least one pre-cooling heat exchanger.
Aspect 9: The compression system of Aspect 5, wherein the main heat exchanger is operationally configured to liquefy the hydrocarbon fluid and cool the second refrigerant as the hydrocarbon fluid and the second refrigerant flow through a coil wound tube side of the main heat exchanger by indirect heat exchange with the second refrigerant flowing through a shell side of the main heat exchanger.
Aspect 10: The compression system of any of Aspects 1-9, wherein the second refrigerant is a mixed refrigerant and the first refrigerant is a propane.
Aspect 11: The compression system of any of Aspects 1-10, wherein the driver assembly including a first driver for the primary compression circuit and a second driver for the secondary compression circuit, the first driver being independent of the second driver.
Aspect 12: The compression system of any of Aspects 1-11, further comprising a valve operationally configured to control a distribution of flow of the first refrigerant between primary compression circuit and the secondary compression circuit.
Aspect 13: The compression system of any of Aspects 1-12, wherein the first primary compressor stage has a first primary head-flow ratio and the first compressor stage of the double flow compressor has a first secondary head-flow ratio that is less than the first primary head-flow ratio.
Aspect 14: The compression system of any of Aspects 1-13, wherein the secondary head-flow ratio is 70-90% of the primary head-flow ratio.
Aspect 15: The compression system of any of Aspects 1-14, wherein the primary head-flow ratio is 50-95%.
Aspect 16: A compressor comprising:
a casing that defines an internal volume, a first inlet, a second inlet, and an outlet, the casing further comprising a first compressor stage and a second compressor stage located in the internal volume, the first compressor stage having a first suction side, a first discharge side, at least one first impeller, and at least one first diffuser, the second compressor stage having a second suction side, a second discharge side, at least one second impeller, and at least one second diffuser, the first suction side being distal to the second suction side, the first discharge side being proximal to the second discharge side; and
wherein the first inlet is located on the first suction side of the first compressor stage, the second inlet is located on the second suction side of the second compressor stage, and the outlet is located proximal to the first pressure side and the second pressure side;
wherein the at least one first impeller consists of a first number of impellers, each having a first impeller geometry, the at least one second impeller consists of a second number of impellers, each having a second impeller geometry, the at least one first diffuser each having a first diffuser geometry, and the second at least one second diffuser having a second diffuser geometry;
wherein the first compressor stage differs from the second compressor stage by at least one selected from the group of: (a) the first number of impellers is different from the second number of impellers, (b) the first impeller geometry is different from the second impeller geometry, and (c) the first diffuser geometry is different from the second diffuser geometry.
Aspect 17: The compressor of Aspect 16, wherein the first number of impellers is different from the second number of impellers.
Aspect 18: The compressor of Aspect 16, wherein the first number of impellers is greater than the second number of impellers.
Aspect 19: The compressor of any of Aspects 16-18, further comprising a mixing chamber that is proximal to the first discharge side, the second discharge side, and the outlet.
Aspect 20: The compressor of any of Aspects 16-19, wherein each of the at least one first impeller and each of the at least one second impeller are affixed to a first shaft.
Aspect 21: A method comprising:
a. compressing a first low pressure stream of a refrigerant and at least one side stream of the refrigerant in a primary compression sequence comprising a plurality of compressor stages to form a first partially-compressed primary stream at a first intermediate pressure and a fully-compressed primary stream at a final pressure, the final pressure being greater than the first intermediate pressure;
b. combining a first side stream of the at least one side stream with the first partially-compressed refrigerant stream;
c. separating a first slip stream from one selected from the group of: the first low pressure stream and the first side stream, the first slip stream having a first slip stream pressure;
d. compressing the first slip stream in a first secondary compressor stage to form a first compressed secondary stream;
e. separating a second slip stream from one of the at least one side stream, the second slip stream having a second slip stream pressure that is greater than the first slip stream pressure;
f. compressing the second slip stream in a second secondary compressor stage to the final pressure to form a second compressed secondary stream;
g. combining the first compressed secondary stream and the second compressed secondary stream with the fully-compressed refrigerant stream; and
h. cooling a hydrocarbon by indirect heat exchange with the refrigerant.
Aspect 22: The method of Aspect 21, wherein steps (a), (b), and (d) comprise:
a. compressing a first stream of a refrigerant and at least one side stream of the refrigerant in a primary compression sequence comprising a plurality of compressor stages to form a first partially-compressed refrigerant stream at a first intermediate pressure, a second partially compressed refrigerant stream at a second intermediate pressure, and a fully-compressed refrigerant stream at a final pressure, the final pressure being greater than the second intermediate pressure and the second intermediate pressure being greater than the first intermediate pressure;
c. separating a first slip stream from a first side stream of the at least one side stream, the first slip stream having a first slip stream pressure that is equal to the first intermediate pressure; and
d. separating a second slip stream from a second side stream of the at least one side stream, the second slip stream having a second slip stream pressure that is equal to the second intermediate pressure.
Aspect 23: The method of any of Aspects 21-22, further comprising:
Aspect 24: The method of any of Aspects 15-22, wherein step (g) comprises mixing the first compressed secondary stream and the second compressed secondary stream to form a mixed secondary stream, then combining the mixed secondary stream with the fully-compressed refrigerant stream.
Aspect 25: The method of any of Aspects 15-24, further comprising, performing steps (f) and (g) within a single compressor casing.
Aspect 26: The method of Aspect 25, further comprising, performing steps (f) and (g) within a single compressor casing of a double-flow compressor.
Aspect 27: The method of Aspect 26, wherein steps (f) and (g) further comprise:
f. compressing the first slip stream in a first secondary compressor stage having a first discharge side to the final pressure to form a first compressed side stream; and
g. compressing the second slip stream in a second secondary compressor stage, having a second discharge side that is proximal to the first discharge side, to the final pressure to form a second compressed side stream.
Aspect 28: The method of Aspect 26, wherein steps (f) and (g) further comprise:
f. compressing the first slip stream a first secondary compressor stage, comprising at least one first impeller having a first impeller geometry, to the final pressure, to form a first compressed secondary stream; and
g. compressing the second slip stream in a second secondary compressor stage, comprising at least one second impeller having a second impeller geometry that is different from the first impeller geometry, to the final pressure to form a second compressed secondary stream.
The ensuing detailed description provides preferred exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration. 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 their spirit and scope.
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.
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 to describe portions of the disclosed embodiments (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 of the claimed invention. 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.
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.
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 gas” or “hydrocarbon fluid”, as used in the specification and claims, means a gas/fluid comprising at least one hydrocarbon and for which hydrocarbons comprise at least 80%, and more preferably at least 90% of the overall composition of the gas/fluid.
The term “mixed refrigerant” (abbreviated as “MR”), as used in the specification and claims, means a fluid comprising at least two hydrocarbons and for which hydrocarbons comprise at least 80% of the overall composition of the refrigerant.
The terms “bundle” and “tube bundle” are used interchangeably within this application and are intended to be synonymous.
The term “ambient fluid”, as used in the specification and claims, means a fluid that is provided to the system at or near ambient pressure and temperature.
The term “compression circuit” is used herein to refer to the components and conduits in fluid communication with one another and arranged in series (hereinafter “series fluid flow communication”), beginning upstream from the first compressor or compressor stage and ending downstream from the last compressor or compressor sage. The term “compression sequence” is intended to refer to the steps performed by the components and conduits that comprise the associated compression circuit.
As used in the specification and claims, the terms “high-high”, “high”, “medium”, and “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.
As used herein, the term “cryogen” or “cryogenic fluid” is intended to mean a liquid, gas, or mixed phase fluid having a temperature less than −70 degrees Celsius. Examples of cryogens include liquid nitrogen (LIN), liquefied natural gas (LNG), liquid helium, liquid carbon dioxide and pressurized, mixed phase cryogens (e.g., a mixture of LIN and gaseous nitrogen). As used herein, the term “cryogenic temperature” is intended to mean a temperature below −70 degrees Celsius.
As used herein, the term “compressor” in intended to mean a device having at least one compressor stage contained within a casing and that increases the pressure of a fluid stream.
As used herein, the term “double flow compressor” is intended to mean a compressor having at least two compressor stages contained within a single casing and having at least two inlet streams and at least one outlet stream. In addition, the inlet streams are compressed separately and combined at the discharge to produce the outlet stream.
As used herein, the term “casing” is intended to mean a pressure-containing shell than defines an internal volume and which contains at least one compressor stage. When two or more pressure containing shells are connected by conduits, the arrangement is considered two or more casings.
As used herein, the term “compressor stage” is intended to mean a device that increases the pressure of a fluid and has a single inlet, a single outlet, and one or more impellers and their associated diffusers.
As used herein, the term “impeller” is intended to mean a rotating device that increases the pressure of the fluid entering it.
As used herein, the term “diffuser” is intended to mean a device located at the outlet of an impeller that converts at least a portion of the dynamic pressure of the fluid to static pressure. A diffuser may optionally include adjustable guide vanes, which can be moved to change the operating characteristics of the compressor stage with which the diffuser is associated.
Table 1 defines a list of acronyms employed throughout the specification and drawings as an aid to understanding the described embodiments.
The described embodiments provide an efficient process for the liquefaction of a hydrocarbon fluid and are particularly applicable to the liquefaction of natural gas. Referring to
The pre-treated feed stream 101 is pre-cooled to a temperature below 10 degrees Celsius, preferably below about 0 degrees Celsius, and more preferably about −30 degrees Celsius. The pre-cooled natural gas stream 105 is liquefied to a temperature between about −150 degrees Celsius and about −70 degrees Celsius, preferably between about −145 degrees Celsius and about −100 degrees Celsius, and subsequently sub-cooled to a temperature between about −170 degrees Celsius and about −120 degrees Celsius, preferably between about −170 degrees Celsius and about −140 degrees Celsius. MCHE 108 shown in
The term “essentially water free” means that any residual water in the pre-treated feed stream 101 is present at a sufficiently low concentration to prevent operational issues associated with water freeze-out in the downstream cooling and liquefaction process. In the embodiments described in herein, water concentration is preferably not more than 1.0 ppm and, more preferably between 0.1 ppm and 0.5 ppm.
The pre-cooling refrigerant used in the C3MR process is propane. As illustrated in
In the MCHE 108, at least a portion of, and preferably all of, the refrigeration is provided by vaporizing at least a portion of refrigerant streams after pressure reduction across valves or turbines.
A low pressure gaseous MR stream 130 is withdrawn from the bottom of the shell side of the MCHE 108, sent through a low pressure suction drum 150 to separate out any liquids and the vapor stream 131 is compressed in a low pressure (LP) compressor 151 to produce medium pressure MR stream 132. The low pressure gaseous MR stream 130 is typically withdrawn at a temperature at or near propane pre-cooling temperature and preferably about −30 degree Celsius and at a pressure of less than 10 bar (145 psia). The medium pressure MR stream 132 is cooled in a low pressure aftercooler 152 to produce a cooled medium pressure MR stream 133 from which any liquids are drained in medium pressure suction drum 153 to produce medium pressure vapor stream 134 that is further compressed in medium pressure (MP) compressor 154. The resulting high pressure MR stream 135 is cooled in a medium pressure aftercooler 155 to produce a cooled high pressure MR stream 136. The cooled high pressure MR stream 136 is sent to a high pressure suction drum 156 where any liquids are drained. The resulting high pressure vapor stream 137 is further compressed in a high pressure (HP) compressor 157 to produce high-high pressure MR stream 138 that is cooled in high pressure aftercooler 158 to produce a cooled high-high pressure MR stream 139. Cooled high-high pressure MR stream 139 is then cooled against evaporating propane in pre-cooling system 118 to produce a two-phase MR stream 140. Two-phase MR stream 140 is then sent to a vapor-liquid separator 159 from which an MRL stream 141 and a MRV stream 143 are obtained, which are sent back to MCHE 108 to be further cooled. Liquid streams leaving phase separators are referred to in the industry as MRL and vapor streams leaving phase separators are referred to in the industry as MRV, even after they are subsequently liquefied. The process of compressing and cooling the MR after it is withdrawn from the bottom of the MCHE 108, then returned to the tube side of the MCHE 108 as multiple streams, is generally referred to herein as the MR compression sequence.
Both the MRL stream 141 and MRV stream 143 are cooled, in two separate circuits of the MCHE 108. The MRL stream 141 is cooled and partially liquefied in the first two bundles of the MCHE 108, resulting in a cold stream that is let down in pressure to produce a cold two-phase stream 142 that is sent back to the shell-side of MCHE 108 to provide refrigeration required in the first two bundles of the MCHE. The MRV stream 143 is cooled in the first, second, and third bundles of MCHE 108, reduced in pressure across the cold high pressure letdown valve, and introduced to the MCHE 108 as stream 144 to provide refrigeration in the sub-cooling, liquefaction, and cooling steps. MCHE 108 can be any exchanger suitable for natural gas liquefaction such as a coil wound heat exchanger, plate and fin heat exchanger or a shell and tube heat exchanger. Coil wound heat exchangers are the state of art exchangers for natural gas liquefaction and include at least one tube bundle comprising a plurality of spiral wound tubes for flowing process and warm refrigerant streams and a shell space for flowing a cold refrigerant stream.
In this manner, refrigeration may be supplied at four temperature levels corresponding to four evaporator pressure levels. It also possible to have more or less than four evaporators and temperature/pressure levels. Any type of heat exchangers may be used for evaporators 171, 174, 177, and 178 such as kettles, cores, plate and fin, shell and tube, coil wound, core in kettle, etc. In case of kettles, the heat exchanger and vapor-liquid separators may be combined into a common unit.
Propane refrigerant 110 is typically divided into two streams, to be sent to two parallel systems, one to pre-cool the pre-treated feed stream 101 to produce the pre-cooled natural gas stream 105, the other to cool the cooled high-high pressure MR stream 139 to produce two-phase MR stream 140. For simplicity, only the feed pre-cooling circuit is shown in
The pre-cooling and liquefaction compressors shown in
There are two primary compression circuits in the embodiment shown in
The secondary low pressure side stream 113B is sent to a first secondary compressor stage 187 and the secondary medium pressure side stream 112B are sent to a second secondary compressor stage 188 to produce a first secondary compressed stream 186D and a second secondary compressed stream 186C, which are mixed to produce a secondary outlet stream 186B. The secondary outlet stream 186B is mixed with the primary outlet stream 186A to produce a compressed propane stream 115 at a pressure of about 2.5 to 30 bara. The compressed propane stream 115 is then cooled and condensed in condenser 117 of
A benefit of using the embodiment described in
The low pressure side stream 113 is split into a primary low pressure side stream 113A and a secondary low pressure side stream 113B. The primary low pressure side stream 113A is mixed with the medium pressure propane stream 180 to produce the medium pressure mixed stream 181, which is fed to the second compressor stage 116B to produce a high pressure propane stream 182 at a pressure of about 2-15 bara. A medium pressure side stream 112 is split into a primary medium pressure side stream 112A and a secondary medium pressure side stream 112B. The high pressure propane stream 182 combines with the primary medium pressure side stream 112A to produce a high pressure mixed stream 183, which is sent to the third compressor stage 116C to produce a high-high pressure propane stream 184 at a pressure of about 2.5-20 bara. The high-high pressure propane stream 184 then combines with high pressure side stream 111 to produce high-high pressure mixed stream 185, which is sent to the fourth compressor stage 116D to produce a primary outlet stream 186A.
The secondary low pressure side stream 113B is sent to a first secondary compressor stage 187 to produce a first secondary intermediate stream 113C, which is mixed with the secondary medium pressure side stream 112B to produce a second secondary intermediate stream 113D. The second secondary intermediate stream 113D is compressed in a second secondary compressor to produce a secondary outlet stream 186B. The secondary outlet stream 186B is mixed with the primary outlet stream 186A to produce a compressed propane stream 115 at a pressure of about 2.5 to 30 bara. The compressed propane stream 115 is then cooled and condensed in condenser 117 of
A benefit of this embodiment is that, similar to
An additional advantage of this embodiment is that the first secondary compressor stage 187 and the second secondary compressor stage 188 may be housed in a single compressor casing, which reduces equipment cost and the footprint of the facility.
In the embodiment shown in
An internal mixing chamber 710 is typically provided at the suction side 787A of the second secondary compressor stage 788 to allow for efficient mixing of the first secondary intermediate stream 113C with the secondary medium pressure side stream 112B to produce the secondary intermediate stream 113D.
The secondary low pressure side stream 113B and the secondary medium pressure side stream 112B are sent to a double flow compressor 190, which is comprised of two compression sections, the first secondary compressor stage 187 and the second secondary compressor stage 188. The secondary low pressure side stream 113B is compressed in the first secondary compressor stage 187 to produce a first secondary intermediate stream 113C. The secondary medium pressure side stream 112B is compressed in the second secondary compressor stage 188 to produce a second secondary intermediate stream 112C. The first and second secondary intermediate streams 112C, 113C (see
In an alternative embodiment, different side streams than those shown in
As noted above, a “double flow compressor” is a compressor having at least two stages contained within a single casing and having at least two inlet streams and at least one outlet stream. In addition, the two inlet streams are compressed separately and combined at the discharge to produce the outlet stream, as shown the double flow compressor 900 of
Double flow compressors of the prior art are symmetrical in nature and the two inlet streams are identical in flow, pressure, and temperature. As a result, the geometry and number of impellers in both compressor stages is aerodynamically identical. The geometry of the compressor stage comprises impeller geometry and diffuser geometry. Impeller geometry and diffuser geometry include, but are not limited to, the number of blades, length of blades, and blade angle. In the embodiments shown in
As is shown schematically in
A benefit of using the embodiment described in
Mixing inlet streams in
The dashed line in
The highest and lowest flowrates that a compressor stage is designed to handle are defined herein as Fmax and Fmin respectively. The highest and lowest head that a compressor is designed to handle are defined herein as Hmax and Hmin respectively. Hmax occurs at Fmin and is the surge operating point 12. Hmin occurs at Fmax and is the stonewall operating point 14. The ratio of Fmax to Fmin is defined as Fratio and the ratio of Hmax to Hmin is defined as Hratio. These operating points are identified in the graph of
Preferably, the compressor stages in the secondary compression circuit (whether they be a single compressor casing with multiple compressor stages or multiple compressor casings) possess a steeper head-flowrate curve than the primary compression circuit. An exemplary head-flow rate curve for compressor stage 187 of
A typical head-flow ratio for the compressor stages in the primary compression circuit, including compressor stage 116B, is in the range of 50-95%. The head-flow ratio of each compressor stage in the secondary compression circuit is preferably lower than (more preferably, 70-95% of) the head-flow ratio of the compressor stage in the primary compression circuit that is immediately downstream from the point at which the slip stream is separated from its side stream. For example, in
The benefit of providing a steeper head-flow ratio for the secondary compression circuit is that it makes it easier to operate the primary and secondary compression circuits. The compressor stages of the primary and secondary compression circuits are designed for different flowrates, but the overall pressure ratio is usually the same to ensure same conditions at the outlet. The two compressions circuits are not identical and the second compression circuit typically has a of much smaller capacity than the main compression circuit. For example, in a C3MR plant operating close to surge, as the ambient temperature reduces, the approach to surge increases and a lower flow rate through the secondary compression circuit is required. Designing the compression stages of the secondary compression circuit with a steep head-flow curve allows the flow to be varied as needed. Therefore, this improvement addresses the challenge of debottlenecking the main compression circuit in the most efficient way possible. This embodiment leads to lower capital cost, plot space, and makes the design more flexible to operational changes and easier to control.
In all the embodiments discussed herein, the primary compression circuit and the secondary compression circuit may include compressors of any type. In alternate embodiments, the secondary compression circuit may be in parallel with any number of compressor stages of the primary compression circuit. In most applications, it will be preferable to have the secondary compression circuit arranged in parallel with the compressors or compressor stages of the primary compression circuit that operate at a higher pressure than any of the compressors or compressor stages that are not arranged in parallel with the secondary compression circuit.
Although the embodiments discussed herein refer to the propane pre-cooling compressor of a C3MR liquefaction cycle, the inventive concepts disclosed herein are applicable to any other refrigerant type including, but not limited to, two-phase refrigerants, gas-phase refrigerants, mixed refrigerants, pure component refrigerants (such as nitrogen) etc. In addition, they can be applied to a refrigerant being used for any service utilized in an LNG plant, including pre-cooling, liquefaction or sub-cooling. They may be applied to a compression system in a natural gas liquefaction plant utilizing any process cycle including SMR, DMR, nitrogen expander cycle, methane expander cycle, cascade and any other suitable liquefaction cycle. Additionally, they may be applied to both open-loop and closed-loop liquefaction cycles.
Another exemplary embodiment is applicable to scenarios wherein the LNG production is limited by the available driver power, such as at high production rates or during high ambient temperature due to reduced available power for gas turbine drivers. In such cases, an additional driver may be provided to drive secondary compressors. This would increase the available power in the compression systems and, at the same time, provide a convenient way to distribute the additional power to the compression systems and debottleneck the limiting stages. This is especially beneficial when performing a retrofit design to increase the capacity of an existing LNG plant.
The embodiments described herein are applicable to any compressor design including any number of compressors, compressor casings, compressor stages, presence of inter or after-cooling, presence of inlet guide vanes, etc. Additionally, the speed of the compressors in the primary or secondary compression circuits may be varied to optimize performance. The secondary compression circuit may comprise multiple compressors or compressor stages in series or in parallel. Further, the methods and systems described herein can be implemented as part of new plant design or as a retrofit to debottleneck existing LNG plants.
The following is an example of the operation of an exemplary embodiment. The example process and data are based on simulations of a C3MR process in a plant that produces nominally 6 MTPA of LNG. This example specifically refers to the embodiment shown in
In this example, the plant performance is limited by the second and third compressor stages 116B and 116C of the propane compressor 116, which is a centrifugal compressor operating at the maximum head possible. A double flow compressor 900 is added as shown in
The secondary low pressure side stream 113B and the secondary medium pressure side stream 112B are sent to a double flow compressor 900 to produce two compressed secondary intermediate streams 112C, 113C, which are mixed within the double flow compressor to produce an secondary outlet stream 186B at 14.3 bara (207 psia) and 15,383 m3/hr (543,242 ft3/hr). The secondary outlet stream 186B is mixed with the primary outlet stream 186A to produce a compressed propane stream 115 at 14.3 bara (207 psia), 60 degrees C. (140.1 degrees F.), and 88,954 m3/hr (3,141,374 ft3/hr). The compressed propane stream 115 is then cooled and condensed in condenser 117. The overall LNG production of the plant increased by about 10% as compared to the same system without the double flow compressor 900. Therefore, the configuration of this example is successful in debottlenecking the propane compressor and resulted in improved plant capacity and efficiency.
An 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.
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