Patent Grant
10180282
A number of 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. In contrast, positive displacement compressors function by reducing the volume of the fluid being compressed. Positive displacement compressors such as reciprocating and screw compressors have typically not been preferred in base-load LNG service because of their lower flow capability that in turn leads to the need for many units, higher cost, and larger plot area.
There are four main types of drivers that have been used in LNG service, namely industrial gas turbines, aero-derivative 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 the anti-surge line. Surge is defined as an operating point at which the maximum head capability and minimum volumetric flow limit of the compressor are reached. The 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 specifications, 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.
One approach to debottleneck the refrigerant compression system is to add an additional dynamic compressor, 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 the anti-surge line, but 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 a secondary dynamic compressor such as a centrifugal compressor in parallel with the primary compressor. The secondary compressor is typically much smaller in capacity as compared to the primary compressor and this poses a challenge with respect to balancing the two parallel compressors and ensuring that the outlet pressure match up although the volumetric flow rates may not. The head versus capacity curve of a typical dynamic compressor is shown in
Furthermore, it is difficult to adjust the flow split between two parallel dynamic compressors with different flow characteristics (as described above) as operational conditions in the compression system change. For example, in a C3MR plant operating close to the anti-surge line, as the ambient temperature reduces, the approach to surge increases and a lower flow rate through the secondary compressor is required. Additionally, the parameters of the secondary compressor, such as speed, typically cannot be varied because such variation will result in a change in the outlet pressure, creating an imbalance with the primary compressor. Further, in scenarios wherein the primary compressor is a mixed refrigerant compressor, any variations in MR composition with changing feed composition and ambient conditions might lead to an imbalance of the two compressors. Many of these challenges are driven by the fact that both compressors are not identical and the second compressor is typically of much smaller capacity than the main compressor.
Overall, adding a lower capacity dynamic compressor in parallel with the primary compressor leads to an inflexible design that could be challenging to design and operate efficiently. Therefore, what is needed is a simpler 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.
Described 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. The disclosed embodiments satisfy the need in the art by using a positive displacement compressor in parallel with at least one dynamic compressor 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 of the present invention are outlined below.
Aspect 1—An apparatus for liquefying a hydrocarbon fluid comprising:
Aspect 2—The apparatus of Aspect 1, wherein the at least one compression stage of the primary compression circuit comprises a plurality of compression stages, each of the plurality of compression stages being a dynamic compressor, and each of the at least one compression stage of the secondary compression circuit is a positive displacement compressor.
Aspect 3—The apparatus of Aspect 2, wherein the compression system is further operationally configured to inter-cool the first refrigerant between at least two of the plurality of compression stages of the primary compression circuit.
Aspect 4—The apparatus of any of Aspects 1-3, wherein the primary compression circuit comprises a plurality of compression stages and the primary compression circuit comprises a second portion, at least one of the plurality of compression stages being located in the first portion and at least one of the plurality of compression stages being located in the second portion, the secondary compression circuit being arranged in parallel with only the first portion of the primary compression circuit, each of the at least one of the plurality of compression stages located in the first portion being operationally configured to operate at a higher pressure than all of the at least one of the plurality of compression stages located in the second portion.
Aspect 5—The apparatus of any of Aspects 1-4, further comprising a second 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 first heat exchanger.
Aspect 6—The apparatus of any of Aspects 1-5, wherein the first refrigerant is propane, a mixed refrigerant, or nitrogen.
Aspect 7—The apparatus of any of Aspects 5-6, wherein the second 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 second heat exchanger by indirect heat exchange with the second refrigerant flowing through a shell side of the second heat exchanger.
Aspect 8—The apparatus of Aspect 1, further comprising a second heat exchanger operationally configured to pre-cool the hydrocarbon fluid by indirect heat exchange between the hydrocarbon fluid and a second refrigerant before the hydrocarbon fluid is further cooled by the first heat exchanger.
Aspect 9—The apparatus of any of Aspects 1 and 8, wherein the second refrigerant is propane and the first refrigerant is a mixed refrigerant.
Aspect 10—The apparatus of any of Aspects 1 and 8-9, wherein the first heat exchanger is operationally configured to liquefy the hydrocarbon fluid and cool the first refrigerant as the hydrocarbon fluid and the first refrigerant flow through a coil wound tube side of the first heat exchanger by indirect heat exchange with the first refrigerant flowing through a shell side of the first heat exchanger.
Aspect 11—The apparatus 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 apparatus 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 apparatus of any of Aspects 1-12, wherein the dynamic compressor is a centrifugal compressor and the positive displacement compressor is a screw compressor.
Aspect 14—A method comprising:
Aspect 15—The method of Aspect 14, wherein step (a) further comprises compressing the first portion of the first refrigerant stream in a plurality of compression stages in the primary compression sequence.
Aspect 16—The method of any of Aspects 14-15, wherein step (a) further comprises compressing the first refrigerant stream in at least one of the plurality of compression stages of the primary compression sequence before splitting the first refrigerant stream into the first portion and the second portion.
Aspect 17—The method of any of Aspects 14-16, wherein step (a) further comprises cooling the first refrigerant stream between two of the plurality of compression stages.
Aspect 18—The method of any of Aspects 14-17, wherein step (a) further comprises removing a third portion of the first refrigerant from the first refrigerant stream before splitting the first refrigerant stream into the first portion and the second portion.
Aspect 19—The method of any of Aspects 14-18, wherein step (a) further comprises combining at least one first refrigerant side stream with the first refrigerant stream.
Aspect 20—The method of any of Aspects 14-19, wherein step (a) further comprises combining at least one of the at least one first refrigerant side stream with the first refrigerant stream before splitting the first refrigerant stream into the first portion and the second portion.
Aspect 21—The method of any of Aspects 14-20, wherein step (a) further comprises cooling the combined compressed refrigerant stream in at least one heat exchanger prior to producing the compressed first refrigerant stream.
Aspect 22—The method of any of Aspects 14-20, wherein step (a) further comprises further compressing the combined compressed refrigerant stream prior to producing the compressed first refrigerant stream.
Aspect 23—The method of any of Aspects 14-22, wherein the compressed first refrigerant stream is cooled and expanded prior to the indirect heat exchange in step (b).
Aspect 24—The method of any of Aspects 14-23, wherein step (a) further comprises splitting the first refrigerant stream into the first portion and the second portion, the first portion comprising at least 70% of the first refrigerant stream.
Aspect 25—The method of any of Aspects 14-24, further comprising:
Aspect 26—The method of an of Aspects 14-24, further comprising:
Aspect 27—The method of Aspect 26, wherein step (b) further comprises liquefying the hydrocarbon fluid and cooling a mixed refrigerant flowing through a coil wound tube side of a main heat exchanger by indirect heat exchange with the mixed refrigerant flowing through a shell side of the main heat exchanger to produce a hydrocarbon fluid product stream.
Aspect 28—A method comprising:
Aspect 29—The method of Aspect 28, wherein step (a) further comprises at least partially liquefying the hydrocarbon fluid.
The ensuing detailed description provides preferred exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration of the claimed invention. 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 of the claimed invention. Various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the claimed invention.
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 present invention (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 compression 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 the 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.
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 second 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
In order to debottleneck the fourth compression stage 116D, a positive displacement compressor 187 is provided in parallel to the fourth compression stage 116D. The high-high pressure mixed stream 185 splits into two: a primary compressor stream 185A and a secondary compressor stream 185B. Preferably more than 50% of the high-high pressure mixed stream 185 directed to the primary compressor stream 185A. More preferably, more than 70% of the high-high pressure mixed stream 185 directed to the primary compressor stream 185A. A proportional valve (not shown) or other suitable control device could be optionally provided to enable adjustment of the flow split between the primary compressor stream 185A and a secondary compressor stream 185B. In this embodiment, the propane compressor 116 is a dynamic or kinetic compressor, such as a centrifugal compressor, and the positive displacement compressor 187 is a screw compressor or a reciprocating compressor. In alternate embodiments, the positive displacement compressor 187 could consist of multiple stages and/or multiple compressors.
The outlet streams 186A and 186B from both compressors 116, 187 are combined to produce a compressed propane stream 115, which is sent to the condenser 117 of
The term “secondary” is used herein to identify fluid streams, compression circuits, compression sequences, and compressors that are arranged in parallel with at least a portion of a “primary” streams, compression circuits, compression sequences, and compressors. The term “secondary” is also used because the parallel use of a positive displacement compressor may be implemented as a retrofit to one or more dynamic compressors in existing LNG plants. Except as specifically stated herein, the terms “secondary” and “primary” are not intended to imply relative capacity or performance characteristics. In this embodiment, the secondary compression circuit consists of the secondary compressor stream 185B, the positive displacement compressor 187, and the outlet stream 186B.
The pressure of the compressed propane stream 115 determines the condensing temperature in the condenser 117, which, in turn, determines the pre-cooling temperature and impacts the overall efficiency of the LNG plant. To improve performance of embodiment of
The arrangement of this embodiment is advantageous when both the third and fourth compression stages 116C, 116D of the compressor 116 are limiting LNG production. The primary compression circuit includes at least one dynamic compressor, such as a centrifugal compressor, while the secondary compression circuit includes at least one positive displacement compressor, such as a screw compressor. In alternate embodiments, the secondary compression circuit may be provided in parallel with any number of compression stages. In most applications it will be preferable to have the secondary compression circuit arranged in parallel with the compressors or compression stages of the primary compression circuit that operate at a higher pressure than any of the compressors or compression stages that are not arranged in parallel with the secondary compression circuit.
As a further variation of
Although
In this embodiment, the MR refrigerant vapor stream 131 is split into two streams: a primary compressor stream 131A and a secondary compressor stream 131B. The primary compressor stream 131A is sent to the primary LP MR compressor 151 (part of the primary compression circuit) to produce outlet stream 190A. The secondary compressor stream 131B is sent to a secondary compressor 191 (part of the secondary compression circuit) to produce outlet stream 190B. Outlet streams 190A and 190B are combined to produce medium pressure MR stream 132, which is sent to the low pressure aftercooler 152 to produce cooled medium pressure MR stream 133. Separate aftercoolers (not shown) may also be employed if desired. The primary compression circuit includes at least one dynamic compressor, such as a centrifugal compressor, while the secondary compression circuit includes at least one positive displacement compressor, such as a screw compressor. In this embodiment, the secondary compression circuit begins at the secondary compressor stream 131B, includes the secondary compressor 191, and ends at the outlet stream 109B.
The benefits of this embodiment over prior art, in addition to all the benefits listed for previous embodiments, is that of MR composition flexibility. In a mixed refrigerant liquefaction process, the composition of the MR stream is typically varied during plant operation based on feed composition changes, ambient temperature changes, feed pressure changes, LNG production rate changes and so on in order to achieve desired heat exchanger cooling curves and overall process efficiency. Unlike dynamic compressors, positive displacement compressors are fairly insensitive to MR composition changes and therefore the split between the primary compression circuit and the secondary compression circuit can be adjusted as needed with MR composition changes without impacting the head.
In alternate embodiments, it would be possible to install the secondary compression circuit in parallel with any or all of the stage or compressors in the MR compression circuit. The secondary compression circuit can be added in parallel to the entire MR compression system or just the stages or compressors that are limiting. The secondary compressor 191 may be driven by any excess driver power available in the LNG plant or by a separate electric motor or any other source of power. In addition, in some embodiments, a portion of the refrigerant may be removed before splitting the refrigerant between the primary and secondary compression circuits.
Another exemplary embodiment of the invention 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 of the invention described herein are applicable to any compressor design including any number of compressors, compressor casings, compression stages, presence of inter or after-cooling, etc. Additionally, the secondary compression circuit may comprise multiple compressors or compression stages in series or in parallel. The invention is applicable to various types of positive displacement compressors such as reciprocating or piston-type compressors as well as rotary vane or screw compressors. The methods and systems associated with this invention 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 of the invention. The example process and data are based on simulations of a C3MR process similar to
In this example, the plant performance is limited by the fourth compression stage 116D of the propane compressor 116, which is a centrifugal compressor operating at the maximum head possible and is at the anti-surge line due to high ambient operating conditions. A screw compressor is added a parallel with the fourth compression stage 116D. Warm low pressure propane stream 114 enters the first propane compression stage 116A at 1.2 bara (17.4 psia), −36 degrees C. (−33 degrees F.) and a refrigerant flow rate of 102,826 m3/hr (3,631,266 ft3/hr), and exits at a pressure of 2.3 bara (33.4 psia), −10 degrees C. (14 degrees F.). It mixes with a low pressure side stream 113 at the same pressure and flow rate of 73,644 m3/hr (2,600,713 ft3/hr). The medium pressure mixed stream 181 enters the second propane compression stage 116B and is compressed to 4.2 bara (60.9 psia) and 9 degrees C. (48 degrees F.), which mixes with a medium pressure side stream 112 at the same pressure and flow rate of 62,780 m3/hr (2,217,055 ft3/hr). The high pressure mixed stream 183 enters the third compression stage 116C and is compressed to 7.5 bara (108.8 psia) and 29 degrees C. (84 degrees F.), which mixes with a high pressure side stream 111 at the same pressure and flow rate of 84,305 m3/hr (2,977,203 ft3/hr). The high-high pressure mixed stream 185 is split into the primary compressor stream 185A and the secondary compressor stream 185B. The flow rate of the secondary compressor stream 185B is 17,160 m3/hr (606,000 ft3/hr). Both streams are compressed to 22.8 bara (330.7 psia) to produce outlet streams 186A and 186B, which are combined to produce compressed propane stream 115 at 22.8 bara (330.7 psia) and flow rate of 166,694 m31 hr (5,886,743 ft3/hr).
The liquefaction system power requirement increased by 1.4% to account for additional power required to drive the screw compressor. In this case, this quantity of additional power was available in the LNG plant and was utilized to drive the secondary compressor. The overall LNG production of the plant increased by 3.9%. Therefore, the invention was successful in debottlenecking the propane compressor and resulted in improved plant capacity and efficiency.
The following is an example of the operation of an exemplary embodiment of the invention. The example process and data are based on simulations of a C3MR process similar to
This example is a similar operating scenario as EXAMPLE 1, the only difference being that both the third and fourth compression stages 116C and 116D of the propane compressor are bypassed using positive displacement compressor 187, which is a screw compressor in this example. Warm low pressure propane stream 114 enters the first propane compression stage 116A at 1.3 bara (18.9 psia), −35 degrees C. (−31 degrees F.) and flow rate of 108,070 m3/hr (3,816,450 ft3/hr) and exits at a pressure of 2.3 bara (33.4 psia), −10 degrees C. (14 degrees F.). It mixes with a low pressure side stream 113 at the same pressure and flow rate of 77,133 m3/hr (2,723,926 ft3/hr). The medium pressure mixed stream 181 enters the second propane compression stage 116B and is compressed to 4.2 bara (60.9 psia) and 9 degrees C. (48 degrees F.) and mixed with the medium pressure side stream 112 at the same pressure and flow rate of 65,111 m3/hr (2,299,373 ft3/hr). The high pressure mixed stream 183 is split into the primary compressor stream 183A and the secondary compressor stream 183B. The flow rate of 183B is 9,677 m3/hr (341,740 ft3/hr). The secondary compressor stream 183B is compressed in a positive displacement compressor 187 (which is a reciprocating compressor in this example) 189 to 22.8 bara (330.7 psia). Primary compressor stream 183A is compressed in the third compression stage 116C to 7.5 bara (108.8 psia) and 29 degrees C. (84 degrees F.) and mixed with a high pressure side stream 111 at the same pressure and flow rate of 68,011 m3/hr (2,401,786 ft3/hr). The high-high pressure mixed stream 185 enters the fourth compression stage 116D and is compressed to 22.8 bara (330.7 psia). Outlet streams 188A and 188B are combined to produce compressed propane stream 115 at 22.8 bara (330.7 psia) and flow rate of 159,207 m3/hr (5,622,342 ft3/hr).
In this case, the liquefaction system power requirement increased by 3% in order to drive the secondary compressor (positive displacement compressor). This quantity of additional power was available in the LNG plant and was utilized to drive the secondary compressor. The overall LNG production of the plant increased by 2%. Therefore, the invention was successful in debottlenecking the propane compressor and lead to improved plant capacity during high ambient conditions.
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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