Patent Application
20210156613
The present disclosure relates to methods and systems for managed pressure natural gas liquids (NGL) and nitrogen recovery in the hydrocarbon production field. In particular, the present disclosure relates to methods and systems featuring any one of a variety of NGL plants and any one of a variety of nitrogen rejection units operatively connected by a managed pressure sub-system so that the NGL plant and the nitrogen rejection plant may each be operated more efficiently, and/or with reduced capital expenditure.
Natural gas passing through transmission lines (conduits) frequently has an upper limit on the allowable nitrogen concentration therein, which typically ranges from a maximum of 2.0 to 4.0 mole percent nitrogen in the natural gas. Therefore, producers of natural gas containing higher concentrations of nitrogen must install facilities to reduce the nitrogen concentration in the natural gas to acceptable levels.
The removal of nitrogen from natural gas can be costly both with respect to CAPEX and OPEX (i.e., capital and operating expenditures). Some natural gas producers install a cryogenic nitrogen rejection unit, or cryogenic NRU, in series with other gas processing units such as a cryogenic NGL recovery unit.
More typically, the cryogenic NRU is installed sequentially with the cryogenic NGL recovery process and the natural gas feed is first cooled down from ambient temperature to cryogenic temperature to recover a natural gas liquid (C2+) stream and a C1 and lighter stream that is lean in C2+ components. The C1 and lighter stream that is lean in C2+ components is warmed back up to ambient temperature, compressed, and then fed to the NRU where it is cooled down from ambient temperature to cryogenic temperature to remove (or reject) the nitrogen and form a nitrogen-lean C and lighter stream that is lean in C2+ components. This is followed by warming up the nitrogen-lean C and lighter stream that is lean in C2+ components back up to ambient temperature. In some cases, the order of the unit operations is reversed such that the nitrogen rejection step is first and the step of forming a natural gas liquid (C2+) stream and a C1 and lighter stream that is lean in C2+ components is performed second.
It is advantageous to integrate the nitrogen rejection process into the cryogenic NGL recovery process such that cooling down the natural gas feed to cryogenic temperature, and then warming up the natural gas product to ambient temperature is only done once rather than twice as when the units are installed in series. This has the potential to save OPEX in the form of reduced energy consumption for refrigeration by only needing to cool down the natural gas one time and reduced CAPEX by reducing the size of the refrigeration compression equipment that must be installed.
One of the more common methods for cryogenic NGL recovery is to use the Gas Subcooled Process (GSP) or variants thereof, of which the main equipment includes a refrigeration system which is typically propane-based, a turboexpander, a “subcooler” heat exchanger, and a demethanizer column. If only propane and heavier (C3+) components are being recovered in the NGL recovery unit, the “demethanizer” column is a “deethanizer” column. The demethanizer, as described herein could also describe a deethanizer if the NGL Recovery unit is operating in ethane rejection mode. The term “C2+ components” or “C2+ hydrocarbons” as described herein could also describe “C3+ components” or “C3+ hydrocarbons”, particularly if the NGL recovery unit column is operating as a deethanizer.
If an NRU is to be integrated into a GSP NGL recovery process or other such cryogenic process that includes a demethanizer, it is advantageous to send cold demethanizer overhead directly to the NRU, before the demethanizer overhead (predominantly C1 natural gas product) is warmed back up to ambient temperature. After the nitrogen is removed from the natural gas to acceptable levels, the natural gas product can then be warmed up to ambient temperature and compressed to pipeline transmission pressure. In this manner, the natural gas liquids (C2+) and nitrogen are removed from the natural gas to form a predominantly C1 natural gas product in one cycle of cooling down the feed natural gas and reheating the predominantly C1 natural gas product.
One of the challenges in such a configuration for an integrated GSP and NRU plant is that normally it is desirable to operate the demethanizer at a pressure lower than the distillation column within the NRU. In the apparent configuration, in order to integrate the GSP and NRU, the demethanizer column must be operated at a pressure higher than desired for the GSP unit, such that the demethanizer overhead stream feeding the NRU is at sufficient pressure to feed the NRU column.
The methods and systems of the present disclosure address this issue allowing the demethanizer to be operated at more optimum pressure, which is usually lower than, but could also be equal to, or just above the operating pressure of the NRU column.
The methods and systems of the present disclosure therefore operatively connect the natural gas liquids recovery and nitrogen rejection units while allowing the demethanizer column and the NRU column to each operate at its' optimum pressure, providing cost savings in both reduced capital expenditures and reduced operating expenditures when compared to sequential natural gas recovery and NRU units.
Various efforts in this area may be exemplified by U.S. Pat. Nos. 9,487,458; 9,726,426; and 9,816,752. However, none of these documents mention a pressure management sub-system operatively connecting an NGL recovery unit and an NRU, as taught by the present disclosure.
As may be seen, current practice may not be adequate for all circumstances, and may result in higher demethanizer pressures, which result in higher power requirements, and/or lower natural gas recovery. There remains a need for more robust managed pressure methods and systems. The methods and systems of the present disclosure are directed to these needs.
In accordance with the present disclosure, methods and systems are described which reduce or overcome many of the faults of previously known methods and systems. The methods and systems of the present disclosure allow the nitrogen rejection unit to be integrated, i.e., operatively connected, into the natural gas liquids recovery unit with little or no negative impact on the operation of the natural gas liquids recovery unit. The methods and systems of the present disclosure result in reduced refrigeration horsepower in the nitrogen rejection unit versus the sequential natural gas liquids recovery and nitrogen rejection unit processing, resulting in lower capital expenditures and operating expenditures versus sequential natural gas liquids recovery and nitrogen rejection units.
A first aspect of the disclosure are methods, one method embodiment comprising (or consisting essentially of, or consisting of):
(a) routing one or more raw natural gas streams to a natural gas processing plant, the natural gas processing plant comprising an NGL recovery unit including a demethanizer column, and an NRU including a distillation column, the one or more raw natural gas streams comprising (or consisting essentially of, or consisting of) methane, C2+ hydrocarbons, and nitrogen, the nitrogen having a concentration greater than about 3-4 mole percent;
(b) removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form the reject nitrogen stream and the product natural gas;
(c) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a pressure management sub-system (PMSS) comprising a separator, a pump and an expansion valve, comprising:
In certain embodiments the raw natural gas stream may be routed to the NGL recovery unit prior to the NRU, while in certain other embodiments the raw natural gas stream may be routed to the NRU prior to the NGL recovery unit. In certain embodiments the NGL recovery unit may comprise a gas-subcooled process (GSP), wherein the raw natural gas is routed through one or more heat exchangers to produce one or more subcooled raw natural gas feed streams to the demethanizer column. In certain embodiments the PMSS may comprise one or more redundant components, for example, two or more pumps arranged in parallel flow relationship, or two or more separators arranged in parallel flow relationship. In certain embodiments, components of the PMSS may be arranged in series flow relationship, for example, two or more separators arranged in series, where liquid separated from upstream separators is caused to flow into a downstream separator. Embodiments with mixed parallel and series flow are also contemplated, for example, an arrangement of four separators where first and second separators are arranged in parallel with each other, third and fourth separators are arranged in parallel with each other, and where the first is in series with the third, and the second is in series with the fourth. In certain embodiments, cooling and condensing of the demethanizer overhead in the NRU and reheating of the cold natural gas product from the NRU can take place in one heat exchanger, whereas in other embodiments one or both of these heat exchanges can take place in two or more heat exchangers. Embodiments are also contemplated where the demethanizer overhead and/or the cold natural gas product can also exchange heat with other streams in the NRU, and such heat exchange can occur in one or more heat exchangers within the NRU.
A second aspect of the disclosure are systems, one system embodiment comprising (or consisting essentially of, or consisting of):
(a) an NGL recovery unit including a demethanizer column;
(b) an NRU including a distillation column; and
(c) a pressure management sub-system (PMSS) operatively and fluidly connected to the NGL recovery unit and the NRU, the PMSS comprising at least first through seventh conduits (inclusive), a separator, a pump, and an expansion valve, and further comprising:
The term “NGL recovery unit” is to be interpreted to include, but is not limited to, gas subcooled processes (GSP) and non-gas subcooled processes, and “NGL recovery unit” can also refer to other processes, such as but not limited to, the Recycle Split Vapor (RSV) process and the CryoPlusm process. As used herein, “natural gas product” means a composition consisting essentially of methane and having from about 2 to about 4 mole percent nitrogen therein, that is substantially devoid of C2+ hydrocarbon components, substantially devoid of water (H2O) and may be substantially devoid of CO2. As used herein “nitrogen rejection unit” and NRU mean a unit employing cryogenic separation techniques, unless otherwise specified to include other separation techniques, such as membrane separation and adsorption media separation. As used herein “pressure management sub-system” or PMSS means a component or combination of components (as detailed herein) operatively and fluidly connecting one or more NGL recovery units to one or more NRUs, and functioning to raise pressure of a distillation column in an NRU to be above, equal, or just below the pressure of a demethanizer column in an NGL recovery unit, or reduce a pressure of a demethanizer column in an NGL recovery unit to be below, equal, or just above a pressure of a distillation column in an NRU. As used herein a “receiver” is a pipeline, storage tank, underground storage cavern, tank truck, or any combination thereof.
In certain embodiments a logic device may be provided to control the pressure management sub-system, and the logic device may be configured to be operated and/or viewed from a Human/Machine Interface (HMI) wired or wirelessly connected to the logic device. Certain embodiments may include one or more audio and/or visual warning devices configured to receive communications from the logic device upon the occurrence of a pressure rise (or fall) in a sensed pressure above (or below) a set point pressure, or a change in concentration of one or more sensed concentrations or temperatures, or both, above one or more set points. The occurrence of a change in other measured parameters outside the intended ranges may also be alarmed in certain embodiments. Other measured parameters may include, but are not limited to, liquid flow rate, vapor flow rate, multiphase fluid flow rate, gas flow rate, and density of any of these.
Certain method and system embodiments of this disclosure may comprise starting up or shutting down one, more than one, or all operational equipment of a NGL recovery unit, a PMSS, and/or an NRU using one or more logic devices and the pressure management sub-system (for example as dictated by a client, law, or regulation), and in the case of shutting down, upon the occurrence of an adverse event. As used herein, the term “operational equipment” includes, but is not limited to, compressors, expanders, heat exchangers, separators, conduits, pumps, valves, and columns. “Adverse event” may include, but is not limited to, the presence of explosive vapors, H2S, and/or pressure inside one or more operational equipment components considered unsafe, and which the pressure management sub-system is designed to shutoff above a maximum set point pressure (which may be independently set for each operational unit or conduit). In certain embodiments this may correspond with the detection of pressure by the pressure management sub-system above a maximum set point pressure. “Non-adverse event” time periods are interchangeable with “safe operating conditions” and “safe working conditions.”
Certain method and system embodiments of this disclosure may operate in modes selected from the group consisting of automatic continuous mode, automatic periodic mode, and manual mode. In certain embodiments the one or more operational equipment may include prime movers selected from the group consisting of pneumatic, electric, fuel, hydraulic, and combinations thereof.
In certain embodiments, pressure (P) and/or temperature (T) may be sensed inside the demethanizer column, the NRU distillation column, separators, expander exits, expansion valve inlet and outlets, and the like. Different pressure management sub-systems within a set of pressure management sub-systems may have different sensor strategies, for example, a mass flow sensor for one pressure management sub-system sensing mass flow inside the pressure management sub-system, another sensing mass flow inside a second pressure management sub-system. All combinations of sensing T, P, and/or mass flow inside and/or outside one or more pressure management sub-systems are disclosed herein and considered within the present disclosure.
Pressure management sub-systems may include pressure management components and associated components, for example, but not limited to pressure control devices (backpressure valves), pressure relief devices (valves or explosion discs), expansion valves, pipes, conduits, vessels, towers, tanks, mass flow meters, temperature and pressure indicators, heat exchangers, pumps, compressors, and expanders. With respect to “pressure management”, when referring to a PMSS, the managed pressure may, in some embodiments, be from about 100 psia (690 kPa) or less to about 1,200 psia (8,275 kPa) or greater; alternatively greater than about 200 psia (1,380 kPa); alternatively greater than about 300 psia (2,070 kPa); alternatively greater than about 400 psia (2,760 kPa), or greater than about 500 psia (3,450 kPa). For example, managed pressures may range from about 200 to about 800 psia (about 1,380 to about 5,520 kPa); or from about 250 to about 750 psia (about 1,725 to about 5,175 kPa); or from about 300 to about 700 psia (about 2,070 to about 4,830 kPa); or from about 250 to about 500 psia (about 1,725 to about 3,450 kPa); or from about 200 to about 450 psia (about 1,380 to about 3,105 kPa); or from about 300 to about 600 psia (about 2,070 to about 4,140 kPa); or from about 400 to about 600 psia (about 2,760 to about 4,140 kPa); or from about 300 to about 500 psia (about 2,070 to about 3,450 kPa); or from about 400 to about 800 psia (about 2,760 to about 5,520 kPa); or from about 500 to about 700 psia (about 3,450 to about 4,830 kPa). All ranges and sub-ranges (including endpoints) between about 100 psia (about 690 kPa) and about 1,200 psia (about 8,275 kPa) are considered explicitly disclosed herein. As used herein with respect to pressure, “about” means +/−10 psia (+/−69 kPa) for pressure point values equal to or below 300 psia (2,070 kPa), and +/−50 psia (+/−345 KPa) above 300 psia (2,070 KPa).
These and other features of the methods and systems of the present disclosure will become more apparent upon review of the brief description of the drawings, the detailed description, and the claims that follow. Methods of making natural gas products using one of the systems of the present disclosure are considered within the present disclosure. It should be understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting essentially of” are explicitly disclosed herein, and vice versa. It should be further understood that wherever the term “comprising” is used herein, other embodiments where the term “comprising” is substituted with “consisting of” are explicitly disclosed herein, and vice versa. Moreover, the use of negative limitations is specifically contemplated; for example, certain sensors may trigger audible alarms but not visual alarms, and vice versa. In certain embodiments the refrigerant may not include more than a trace of CO2. As another example, a pressure management sub-system may be devoid of a pump, or may be devoid of a separator.
The manner in which the objectives of this disclosure and other desirable characteristics can be obtained is explained in the following description and attached drawings in which:
Itis to be noted, however, that the appended drawings of
In the following description, numerous details are set forth to provide an understanding of the disclosed apparatus, combinations, and processes. However, it will be understood by those skilled in the art that the apparatus, systems, and processes disclosed herein may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. All technical articles, U.S. published and non-published patent applications, standards, U.S. patents, U.S. statutes and regulations referenced herein are hereby explicitly incorporated herein by reference, irrespective of the page, paragraph, or section in which they are referenced. Where a range of values describes a parameter, all sub-ranges, point values and endpoints within that range or defining a range are explicitly disclosed herein. All percentages herein are by weight unless otherwise noted.
As mentioned herein, one of the challenges in operating NGL recovery units and NRU units that are operably connected is that normally it is desirable to operate the demethanizer column of the NGL recovery unit at a pressure lower or perhaps equal to or just slightly above the distillation column within the NRU. In configurations considered outside of those presently disclosed, in order to operatively connect the GSP and NRU, the demethanizer column must be operated at a pressure higher than desired for the GSP unit, such that the demethanizer column overhead stream feeding the NRU is at sufficient pressure to feed the NRU distillation column after passing through intervening equipment such as heat exchangers and control valves. The methods and systems of the present disclosure address this issue by allowing the demethanizer column to be operated at more optimum pressure, which is usually lower than operating pressure of the NRU distillation column. Methods and systems of the present disclosure therefore operatively connect the natural gas liquids recovery and nitrogen rejection units while allowing the demethanizer column and the NRU distillation column to each operate at its' optimum pressure, providing cost savings in both reduced capital expense and reduced operating expense when compared to sequential natural gas recovery and NRU units.
Methods and systems of the present disclosure enable virtually any NGL recovery process (whether using GSP or not) and NRU combination to potentially more efficiently produce natural gas product, with potentially minimal to no modifications to the NGL recovery unit or the NRU. In certain embodiments, all that may be required to form one embodiment of a PMSS are additional conduits and valves, and perhaps an expansion (Joule-Thompson, or “JT”) valve.
As described in more detail herein with reference to the various drawing figures, methods and systems of the present disclosure may be comprised of two main process units or “plants” operatively connected by a pressure management sub-system (PMSS). The first process unit or plant is termed a natural gas liquids (NGL) recovery unit, which functions to remove C2+ (or C3+) and heavier components from raw natural gas, producing a C2+ (or C3+) and heavier predominantly liquid composition, and a predominantly gas composition comprised predominantly of Ct and lighter components, including nitrogen, argon, helium, and the like. The NGL recovery unit need not be a GSP; any NGL recovery process may be used with any embodiment of the present disclosure described herein, as long as the method or process includes a demethanizer or deethanizer operating (or in the case of systems, configured to operate) at temperatures below ambient; ambient temperature may range from about 32° F. to about 100° F. (0° C. to about 38° C.), or from about 50° F. to about 77° F. (10° C. to about 25° C.). The second process unit or plant is termed a nitrogen rejection unit (NRU), which functions to remove nitrogen, argon, helium, and the like from the predominantly gas composition comprised predominantly of Ct and lighter components, including nitrogen, argon, helium, and the like, using a distillation column, producing a distillation column overhead composition comprised predominantly of nitrogen, argon, helium, and the like, and a bottoms composition comprised predominantly of methane, plus minor amounts of C2+ heavier components and minor amounts of nitrogen, argon, helium, and the like. As a convenience, for the remainder of this document, the overhead composition comprised predominantly of nitrogen, argon, helium, and the like will simply be referred to as the “nitrogen composition”, “nitrogen stream”, or “nitrogen reject stream”, while the bottoms composition comprised predominantly of methane, plus minor amounts of C2+ heavier components and minor amounts of nitrogen, argon, helium, and the like will simply be referred to as the “methane product”, or the “product natural gas”, or the “methane product gas.” In other words, the gas that will have a nitrogen concentration suitable for “natural gas transmission lines.” Moreover, if only propane and heavier are being recovered in the NGL recovery unit, the “demethanizer column” herein may be deemed a deethanizer column; therefore, in all instances herein where the terms “demethanizer” and “demethanizer column” are used, this includes the terms “deethanizer” and “deethanizer column.” The location of the NGL recovery unit relative to the NRU is determined based on the desired application for the system. Factors such as process control, terrain, availability and size of line pipe or other conduits, availability and size of separators, pumps, and expansion valves, and desired pressures and pressure control mode, among others, can impact the placement of the NGL recovery unit and the NRU, and the configuration of the PMSS.
In certain methods and systems of this disclosure, the nitrogen molar concentration of the demethanizer overhead may be below about 20 mole percent, or below about 15 mole percent, or below about 10 mole percent, or below about 9 mole percent, or below about 8 mole percent, or below about 7 mole percent, or below about 6 mole percent, or below about 5 mole percent, or below about 4 mole percent, and the nitrogen molar concentration of the product natural gas may range from about 2 to about 4 mole percent, or from about 2.0 to about 4.0 mole percent. For example, studies have shown that the residue gas (demethanizer overhead) contained 6.2 mole percent nitrogen and the natural gas residue downstream of the integrated natural gas liquids recovery and nitrogen rejection unit contained 3.0 mole percent nitrogen.
The pressure of the available raw natural gas and the specific configuration of the PMSS largely define the type of managed pressure operation capabilities of each method and system embodiment. Redundancy of components in the PMSS may allow for extended service periods and mitigates risk of downtime due to component failure. An example would be a pressure control device plugging with frozen material, or a pump failure, or a separator taken out of service for inspection. In this case, isolating the failed or to be inspected component and enabling another one allows for continued operations, and enables evaluation and/or modification of the operational parameters to minimize the risk of failure of the new or parallel components in use.
The methods and systems of this present disclosure may be used for new greenfield applications, where one or both of the NGL recovery unit and the NRU are custom designed together to be operatively and fluidly connected during operation. It is also contemplated to design the NGL recovery unit and NRU to be able to operate in dual modes, where in the first mode the NGL recovery unit is integrated with the NRU, and the second mode where one or both of the units may operate independently from each other, in other words, where either one or both of the NGL recovery unit and the NRU may operate without requiring the other unit to be in operation.
Advantageously, most of the components of methods and systems of the present disclosure may alternatively be sourced from existing pieces of equipment used in the oil and gas industry. Some of the components of the systems of the present disclosure may be based on existing equipment, some of which may require modification to reconfigure the equipment for integrated operation between the NGL recovery unit and the NRU. The installation of methods and systems of the present disclosure on the NGL recovery unit and/or the NRU are expected to require minimal interfacing. It may be possible to design a retrofitted system that requires no modifications to the demethanizer or NRU distillation column, although the designer may consider modest changes, for example, substituting packing, grids, or other new internals for existing internals. New equipment to complete the integration of the NGL recovery unit and NRU may include components of the PMSS, new components in the NGL recovery unit, new components in the NRU, and/or a completely new NGL recovery unit or NRU.
Methods and systems of the present disclosure may be operated using hydraulic, electric, geothermal, pneumatic, or combustion power, or combination of one or more of these. One possible configuration may employ electric power to operate a motor for a pump of the PMSS (which motor may be variable speed or non-variable speed) and combustion power to operate the NGL recovery unit compressor(s) and NRU compressor(s). In certain embodiments, expanders and compressors may share a shaft. Power supplies may have redundant and/or back up power supply. In certain embodiments, electric power may require installation of an additional battery unit, possibly including solar panels for backup power. In certain embodiments, a plant may have one or more hydrocarbon-powered electric generators, and these units may provide electric power, and backup power may be provided by an uninterruptible power supply (UPS) battery system.
Certain embodiments may include 1) low power electric connections for data transmission for sensors (e.g., pressure, temperature, mass flow indicators, among others); and 2) electric cable to provide power for operating valves and components of the PMSS NGL recovery unit, and NRU. With respect to data connection/integration, in certain embodiments control signals for the components of the systems of the present disclosure, as well as parameters measured or captured by the system's sensors (e.g., pressures, temperatures, fluid flow rates and density, and the like) may be transmitted to and from an operator room or control room from and to the PMSS, the NGL recovery unit, and the NRU.
Referring now to the drawing figures,
The NGL recovery unit heat exchangers 38 and 30 in embodiments 300, 400, and 500 as illustrated schematically in
In each of embodiments 300, 400, and 500, NRU 6 includes an NRU distillation column 26; an NRU first heat exchanger 12; an NRU feed conduit 21 feeding to a near bottom location 50 of NRU distillation column 26; an NRU distillation column bottoms conduit 20 routing NRU distillation column bottoms to an expansion valve 22; an expanded NRU bottoms conduit 24; a nitrogen product conduit 52; refrigeration compressors 62, 64 and associated intercooler and aftercooler; an NRU second heat exchanger 65; an NRU third heat exchanger 66; an NRU column reboiler 68; a refrigerant vessel 70; and a side condenser 48 in addition to an overhead condenser 49, however, side condenser 48 is not necessary in all embodiments. Side condenser 48 may be advantageous in that it may reduce load on refrigeration compressor(s) 62, 64.
Each embodiment 300, 400, and 500 illustrated schematically in
The refrigeration loop illustrated schematically in
The NRU heat exchangers 12, 48, 49, 65, 66, and 68 and refrigerant vessel 70 in embodiments 300, 400, and 500 as illustrated schematically in
Importantly, embodiments 300, 400, and 500 differ in the details of PMSS 8 in order that demethanizer column 28 may operate at a pressure lower than, equal to, or just above the NRU distillation column 26 pressure. In embodiment 300, PMSS 8 features the addition of a conduit 10 allowing demethanizer column 28 overhead to be routed to NRU first heat exchanger 12, a separator vessel 14, and conduit 18 to route condensed demethanizer overhead (NRU feed) to a pump 16. The addition of separator vessel 14 and pump 16 to NRU 6, as well as conduits 10, 18 and 19, allow for demethanizer column 28 to operate at a pressure below, equal to, or just above that of NRU distillation column 26. NRU distillation column bottoms stream, which is low in nitrogen, is routed through bottoms conduit 20 so that it may be partially revaporized and cooled by passing through expansion valve 22, and conduit 24 routes the expanded stream through NRU first heat exchanger 12 and then conduit 25 routes the stream back to the NGL recovery unit 4 (the gas subcooled process in this example) as a cold stream for subcooler (heat exchanger) 30. Conduit 19 allows any uncondensed demethanizer overhead from separator 14 to bypass the NRU distillation column 26 by blending the stream with the expanded NRU distillation column bottoms upstream of NRU first heat exchanger 12. In sum, as illustrated schematically in
Process conditions and overall material balance for an example of Embodiment 300 illustrated schematically in
In certain alternative embodiments of the methods and systems of the present disclosure, a different natural gas recovery process may be used if the process includes a demethanizer or deethanizer that operates at temperatures below ambient.
Embodiment 400 differs from embodiment 300 by the following features. A separator vessel 54 is positioned at an outlet of NGL recovery unit expander 42, allowing an expander outlet vapor portion (separated out by separator vessel 54) to be routed through a conduit 43 to NRU first heat exchanger 12 then via conduit 21 to feed NRU 6 at near bottom location 50 of NRU distillation column 26. NRU distillation column 26 bottoms, with the reduced nitrogen content, is expanded across expansion valve 22 via conduit 20 and reheated in NRU first heat exchanger 12 via conduit 24 and is returned to NGL recovery unit 4 and fed via conduit 60 to demethanizer column 28 at middle feed location 46 where expander 42 outlet normally feeds demethanizer column 28. An expander outlet liquid stream (separated out by separator vessel 54) is routed through a conduit 58 and also fed to middle feed location in demethanizer 28 by joining with the expanded NRU distillation column bottoms at a point in conduit 60, bypassing NRU 6 altogether. In the integrated NGL recovery unit/NRU disclosed herein for embodiment 400, the expander outlet pressure may be higher than the normal expander outlet pressure of an NGL recovery unit that is not operatively connected to an NRU. The combined middle feed in conduit 60 is returned to demethanizer column 28 at similar conditions to a demethanizer column 28 “idle feed” with no NRU, allowing NGL recovery unit 4 to operate very closely to operations with no NRU. However, the middle feed to demethanizer column 28 is reduced in nitrogen such that the demethanizer column 28 overhead residue has a nitrogen content that meets pipeline specifications. In sum, expander 42 feeds separator vessel 54 which is upstream of demethanizer column 28. Conduit 56 routes separator vessel 54 vapors to NRU distillation column 26 after further cooling in the NRU, and conduit 58 routes separator vessel 54 bottoms to demethanizer column 28. Bottoms from NRU distillation column 26 are fed back to demethanizer column 28 after expansion and reheating in the NRU, where the stream joins with the liquid from separator vessel 54, entering demethanizer column 28 as the middle feed.
Process conditions and overall material balance for embodiment 400 illustrated schematically in
Embodiment 500 differs from embodiments 300 and 400 by the following features. As illustrated schematically in
Process conditions and overall material balance for embodiment 500 illustrated schematically in
Embodiment 700 includes two separator vessels (14, 15) serving a single pump 16. Embodiment 700 allows NGL recovery unit 4 and NRU 6 to be used with an additional separator expansion or flash stage. Separator vessels 14 and 15 may operate in conjunction with each other, for example separator vessel 14 at a relatively high to moderate pressure, while separator vessel 15 operates at a moderate to low pressure. Alternatively, separator vessels 14, 15 may be configured with suitable valving and piping so that they may be used in series or parallel flow arrangement. Alternative embodiments may be considered where separator vessels 14 and 15 feed two or more pumps, in series and/or parallel configuration, and the pumps may be arranged to be common to separators 14 and 15 or, alternatively, one or more pumps may be dedicated to separator 14 and one or more pumps may be dedicated to separator 15.
Any known type of NGL recovery unit and NRU may be employed in practicing the methods and systems of the present disclosure. Suitable NGL recovery units and components typically used therewith include those described in U.S. Pat. Nos. 4,157,904; 4,617,039; 4,718,927; 4,895,584; 5,771,712; 5,799,507; 6,182,469; 6,278,035; 6,311,516; 7,544,272; 9,487,458; and 9,726,426; and NRUs discussed in U.S. Pat. Nos. 5,141,544; 5,257,505; 5,375,422; 8,794,031; 9,003,829; 9,816,752; 9,487,458; and 9,726,426.
Any known type of mass flow meter may be employed in practicing the methods and systems of the present disclosure. Suitable mass flow meters and components typically used therewith include the coriolis flow and density meters currently commercially available from Emerson (under the trade designation ELITE Peak Performance Coriolis Flow and Density Meter) and other suppliers. Any known type of pressure relief component (PRV, burst disc, or other) may be employed in practicing the methods and systems of the present disclosure. Suitable pressure relief components include those currently commercially available from Anderson Greenwood (USA) or from Expro, London (U.K.) under the trade designation PRV MAX. Any known type of expansion valve may be employed in practicing the methods and systems of the present disclosure, including those currently commercially available from Samson Controls Inc. USA. Suitable separators include those commercially available from ASME Section VIII coded pressure vessel manufacturers. Any known type of cryogenic pump may be employed in practicing the methods and systems of the present disclosure, including positive displacement, centrifugal, horizontal, vertical pumps, and pumps operated with variable speed motors. Suitable pumps include those currently available from CryoStar (France) or Nikkiso (Japan). Suitable conduits and components typically used therewith include currently commercially available pipe from Hydrocarbon Processing Industry (HPI) manufacturers such as Tenaris (Luxumbourg).
During certain methods of the present disclosure, one or all of T, P, mass flow rate, gas or vapor concentrations (or percentages of set point values) inside and/or outside the pressure management sub-system(s) may be displayed locally on one or more Human Machine Interfaces (HMI), such as a laptop computer having a display screen having a graphical user interface (GUI), or handheld device, or similar, either inside or outside (or both) of pressure management sub-system. In certain embodiments the HMI may record and/or transmit the data via wired or wireless communication to another HMI, such as another laptop, desktop, or hand-held computer or display. These communication links may be wired or wireless.
The NGL recovery unit, NRU, and PMSS may be made of metals, except where rubber or other polymeric seals may be employed. Suitable metals include stainless steels, for example, but not limited to, 306, 316, as well as titanium alloys, aluminum alloys, and the like. High-strength materials like C-110 and C-125 metallurgies that are NACE qualified may be employed. (As used herein, “NACE” refers to the corrosion prevention organization formerly known as the National Association of Corrosion Engineers, now operating under the name NACE International, Houston, Tex.) Use of high strength steel and other high strength materials may significantly reduce the wall thickness required, reducing weight. Threaded connections may eliminate the need for 3rd party forgings and expensive welding processes—considerably improving system delivery time and overall cost. It will be understood, however, that the use of 3rd party forgings and welding is not ruled out for system components described herein and may actually be preferable in certain situations. The skilled artisan, having knowledge of the particular application, pressures, temperatures, and available materials, will be able design the most cost effective, safe, and operable system components for each particular application without undue experimentation.
One or more control strategies may be employed, as long as the strategy includes measurement of NGL recovery unit demethanizer column pressure and NRU distillation column pressure, as well as measurements to be able to determine product purities and flow rates achieved, and those measurements (or values derived from those measurements) may be used in controlling the systems and/or processes described herein. A pressure process control scheme may be employed, for example in conjunction with the pressure control devices and mass flow controllers. A master controller may be employed, but the disclosure is not so limited, as any combination of controllers may be used. Programmable logic controllers (PLCs) may be used.
Control strategies may be selected from proportional-integral (PI), proportional-integral-derivative (PID) (including any known or reasonably foreseeable variations of these), and may compute a residual equal to a difference between a measured value and a set point to produce an output to one or more control elements. The controller may compute the residual continuously or non-continuously. Other possible implementations of the disclosure are those wherein the controller comprises more specialized control strategies, such as strategies selected from feed forward, cascade control, internal feedback loops, model predictive control, neural networks, and Kalman filtering techniques.
Method embodiment 800 further comprises removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a reject nitrogen stream and the product natural gas, Box 804.
Method embodiment 800 further comprises (Box 806) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising a separator, a pump and an expansion valve, comprising:
Method embodiment 900, illustrated schematically in
Method embodiment 900 further comprises removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a reject nitrogen stream and the product natural gas, Box 904.
Method embodiment 900 further comprises (Box 906) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising a separator and an expansion valve, comprising:
Method embodiment 950, illustrated schematically in
Method embodiment 950 further comprises removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a reject nitrogen stream and the product natural gas, Box 954.
Method embodiment 950 further comprises (Box 956) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising an expansion valve but no separator, comprising:
Pressure management sub-systems may be built to meet ISO standards, Det Norske Veritas (DNV) standards, American Bureau of Standards (ABS) standards, American Petroleum Institute (API) standards, and/or other standards. It may be possible to route a raw natural gas stream to an NRU first, to form a nitrogen reject stream and a reduced nitrogen natural gas stream, and then route the reduced nitrogen natural gas stream to an NGL recovery unit in order to form the natural gas product and an NGL product stream; however, in such embodiments the PMSS may require a completely different arrangement of one or more pumps, separators, and conduits than explained herein.
The electrical connections, if used (voltage and amperage) will be appropriate for the zone rating desired of each system. In certain embodiments one or more electrical cables may be run and connected to an identified power supply at the work site to operate the HMI, NGL recovery unit, NRU, and PMSS. Certain embodiments may employ a dedicated power supply. The identified or dedicated power supply may be controlled by one or more logic devices so that it may be shut down. In exemplary embodiments, systems of the present disclosure may have an electrical isolation (lockout) device on a secure cabinet.
In embodiments where connection to one or more remote HMI units is desired, this may be achieved by an intrinsically safe cable and connection to allow system components to operate in the required zoned area. If no remote access is required, power to operate the HMI, NGL recovery unit, NRU, and PMSS may be integral to the apparatus, such as batteries, for example, but not limited to, Li-ion batteries. In these embodiments, the power source may be enclosed allowing it to operate in a zoned area (Zone 0 (gases) in accordance with International Electrotechnical Commission (IEC) processes). By “intrinsically safe” is meant the definition of intrinsic safety used in the relevant IEC apparatus standard IEC 60079-11, defined as a type of protection based on the restriction of electrical energy within apparatus and of interconnecting wiring exposed to a potentially explosive atmosphere to a level below that which can cause ignition by either sparking or heating effects. For more discussion, see “AN9003—A User's Guide to Intrinsic Safety”, retrieved from the Internet Jul. 12, 2017, and incorporated herein by reference.
In certain embodiments, internal algorithms in the logic device, such as a PLC, may calculate a rate of increase or decrease in pressure inside the PMSS and/or the NGL recovery unit, and/or the NRU. This may then be displayed or audioed in a series of ways such as “percentage to shutdown” lights or sounds, and the like on one or more GUIs. In certain embodiments, an additional function within an HMI may be to audibly alarm when the calculated pressure rate of increase or decrease reaches a level set by the operator. In certain embodiments this alarm may be sounded inside the pressure management sub-system, outside the pressure management sub-system, as well as remote from the pressure management sub-system, for example in a local or remote control room.
Pressure management sub-systems, conduits therefore, separators, pumps, logic devices, sensors, expansion and non-expansion valves, and optional safety shutdown units should be capable of withstanding long term exposure to probable liquids and vapors, including hydrocarbons, acids, acid gases, fluids (oil-based and water-based), solvents, brine, anti-freeze compositions, hydrate inhibition chemicals, and the like, typically encountered in hydrocarbon processing facilities and cryogenic processing facilities.
In alternative embodiments, the pressure management sub-system may be enclosed within a frame or cabinet, and/or truck-mounted, and/or ship-mounted. Moreover, the various components (such as separators) need not have specific shapes or specific conduit routing as illustrated in the drawings, but rather the pressure management sub-system separators could take any shape, such as a box or cube shape, elliptical, triangular, prism-shaped, hemispherical or semi-hemispherical-shaped (dome-shaped), or combination thereof and the like, as long as the separator performs the desired separation. The conduit and column cross-sections need not be round, but may be rectangular, triangular, round, oval, and the like. It will be understood that such embodiments are part of this disclosure and deemed with in the claims. Furthermore, one or more of the various components may be ornamented with various ornamentation produced in various ways (for example stamping or engraving, or raised features such as reflectors, reflective tape), such as facility designs, operating company designs, logos, letters, words, nicknames (for example LINDE, and the like). Components of the NGL recovery unit, NRU and/or PMSS may include optional hand-holds, which may be machined or formed to have easy-to-grasp features for fingers, or may have rubber grips shaped and adorned with ornamental features, such as raised knobby gripper patterns.
Thus the methods and systems described herein afford ways to perform natural gas recovery and nitrogen rejection therefrom safely and economically.
Embodiments disclosed herein include:
A: A method comprising (or consisting essentially of, or consisting of):
(a) routing one or more raw natural gas streams to a natural gas processing plant, the natural gas processing plant comprising an NGL recovery unit including a demethanizer column, and an NRU including a distillation column, the one or more raw natural gas streams comprising (or consisting essentially of, or consisting of) methane, C2+ hydrocarbons, and nitrogen, the nitrogen having a concentration greater than about 3 mole percent, or greater than about 4 mole percent;
(b) removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a nitrogen reject stream and the product natural gas; and
(c) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising a separator, a pump, and an expansion valve, comprising:
B: A method comprising (or consisting essentially of, or consisting of):
(a) routing one or more raw natural gas streams to a natural gas processing plant, the natural gas processing plant comprising an NGL recovery unit including an expander upstream of a demethanizer column, and an NRU including a distillation column, the one or more raw natural gas streams comprising (or consisting essentially of, or consisting of) methane, C2+ hydrocarbons, and nitrogen, the nitrogen having a concentration greater than about 3 mole percent, or greater than about 4 mole percent;
(b) removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a reject nitrogen stream and the product natural gas; and
(c) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising a separator and an expansion valve, comprising:
C: A method comprising (or consisting essentially of, or consisting of):
(a) routing one or more raw natural gas streams to a natural gas processing plant, the natural gas processing plant comprising an NGL recovery unit including an expander upstream of a demethanizer column, and an NRU including a distillation column, the one or more raw natural gas streams comprising (or consisting essentially of, or consisting of) methane, C2+ hydrocarbons, and nitrogen, the nitrogen having a concentration greater than about 3 mole percent, or greater than about 4 mole percent;
(b) removing a majority of the C2+ hydrocarbons using the NGL recovery unit and a sufficient amount of the nitrogen using the NRU to form a product natural gas, wherein the removing step comprises removing the majority of the C2+ hydrocarbons from the raw natural gas to form an NGL stream rich in C2+ hydrocarbons and a residue stream, followed by removing the sufficient amount of the nitrogen from the residue stream to form a reject nitrogen stream and the product natural gas; and
(c) operating the demethanizer column at a pressure lower than, equal to, or just above the NRU distillation column by managing a pressure relationship between the demethanizer column and the NRU distillation column using a PMSS comprising an expansion valve but no separator, comprising:
D: A system comprising (or consisting essentially of, or consisting of):
(a) an NGL recovery unit including a demethanizer column;
(b) an NRU including a distillation column; and
(c) a pressure management sub-system (PMSS) operatively and fluidly connected to the NGL recovery unit and the NRU, the PMSS comprising at least first through seventh conduits (inclusive), a separator, a pump, and an expansion valve, and further comprising:
E: A system comprising (or consisting essentially of, or consisting of):
(a) an NGL recovery unit including a demethanizer column;
(b) an NRU including an NRU distillation column; and
(c) a pressure management sub-system (PMSS) operatively and fluidly connected to the NGL recovery unit and the NRU, the PMSS comprising first through ninth conduits
F: A system comprising (or consisting essentially of, or consisting of):
(a) an NGL recovery unit including a demethanizer column;
(b) an NRU including a distillation column; and
(c) a pressure management sub-system (PMSS) operatively and fluidly connected to the NGL recovery unit and the NRU, the PMSS comprising at least first through seventh conduits (inclusive) and an expansion valve, and further comprising:
Each of the embodiments A, B, C, D, E, and F may have one or more of the following additional elements in any combination:
Element 1. Methods and systems wherein the raw natural gas stream may be routed to the NGL recovery unit prior to the NRU.
Element 2. Methods and systems wherein the raw natural gas stream may be routed to the NRU prior to the NGL recovery unit.
Element 3. Methods and systems wherein the NGL recovery unit may comprise a gas-subcooled or related process, wherein the raw natural gas may be routed through one or more heat exchangers to produce one or more sub-cooled raw natural gas feed streams to the demethanizer column.
Element 4: Methods and systems wherein the PMSS may comprise one or more redundant components, for example, two or more expansion valves arranged in parallel flow relationship, or two or more pumps arranged in parallel flow relationship, or two or more separators arranged in parallel flow relationship.
Element 5: Methods and systems wherein the PMSS may be arranged in series flow relationship, for example, two or more separators arranged in series, where liquid separated from upstream separators is caused to flow into a downstream separator.
Element 6: Methods and systems with mixed parallel and series flow are also contemplated, for example, an arrangement of four separators where first and second separators are arranged in parallel with each other, third and fourth separators are arranged in parallel with each other, and where the first is in series with the third, and the second is in series with the fourth.
Element 7: Methods and systems wherein the separator and pump are sized sufficiently so that the demethanizer column operates at a pressure lower than, equal to, or just above the NRU distillation column.
Element 8: Methods and systems wherein the NGL recovery unit includes at least one raw natural gas cooling heat exchanger and at least one separator for forming at least one sub-cooled raw natural gas stream feed to the demethanizer column.
Element 9: Methods and systems wherein one or more components comprises one or more redundant components in the pressure management sub-system.
Element 10: Methods and systems configured to operate in modes selected from the group consisting of automatic continuous mode, automatic periodic mode, and manual mode.
Element 11: Methods and systems wherein one or more operational equipment are selected from the group consisting of pneumatic, electric, fuel, hydraulic, geothermal, and combinations thereof.
Element 12: Methods and systems comprising an HMI including a display with an interactive graphical user interface.
Element 13: Methods where the method described in Embodiment A (a first separator and pump downstream of demethanizer) is combined with the method described in Embodiment B (a second separator upstream of the demethanizer).
Element 14: Systems where the system described in Embodiment D (a first separator and pump downstream of demethanizer) is combined with the system described in Embodiment E (a second separator upstream of the demethanizer).
Element 15: Methods where the method described in Embodiment A (a first separator and pump downstream of demethanizer) is combined with the method described in Embodiment C (expander outlet bypasses the demethanizer).
Element 16: Systems where the system described in Embodiment D (a first separator and pump downstream of demethanizer) is combined with the system described in Embodiment F (expander outlet bypasses the demethanizer).
Element 17: Systems and methods wherein the demethanizer column is selected from a column configured to operate only as a demethanizer column, a column configured to operate alternatively as a demethanizer or a deethanizer, and a column configured to operate only as a deethanizer (which also removes methane).
In sum, at least three systems and methods are presented, including a first system comprising:
(a) a natural gas liquids (NGL) recovery unit;
(b) a nitrogen rejection unit (NRU); and
(c) a pressure management sub-system (PMSS) operatively and fluidly connecting the NGL recovery unit and the NRU, the PMSS comprising a set of conduits, individual members of the set of conduits fluidly connecting:
In certain first systems the set of conduits may comprise:
A method of producing a natural gas product using the first system may comprise:
A second system comprises:
(a) a natural gas liquids (NGL) recovery unit;
(b) a nitrogen recovery unit (NRU); and
(c) a pressure management sub-system (PMSS) operatively and fluidly connecting the NGL recovery unit and the NRU, the PMSS comprising a set of conduits, individual members of the set of conduits fluidly connecting:
Certain second systems may comprise:
A method of producing a natural gas product using the second system may comprise:
A third system comprises:
(a) a natural gas liquids (NGL) recovery unit;
(b) a nitrogen rejection unit (NRU); and
(c) a pressure management sub-system (PMSS) operatively and fluidly connected to the NGL recovery unit and the NRU, the PMSS comprising a set of conduits, individual members of the set of conduits fluidly connecting:
Certain third systems may comprise:
A method of producing a natural gas product using the third system may comprise:
From the foregoing detailed description of specific embodiments, it should be apparent that patentable systems, combinations, and methods have been described. Although specific embodiments of the disclosure have been described herein in some detail, this has been done solely for the purposes of describing various features and aspects of the methods and systems and is not intended to be limiting with respect to their scope. It is contemplated that various substitutions, alterations, and/or modifications, including but not limited to those implementation variations which may have been suggested herein, may be made to the described embodiments without departing from the scope of the appended claims. For example, one modification would be to take an existing NGL recovery unit/NRU combination and modify it to include a pressure management sub-system of this disclosure. Certain methods and systems of this disclosure may be devoid of certain steps, components and/or features: for example, systems devoid of NRU distillation unit feed pumps; systems devoid of demethanizer feed separators; systems devoid of low-strength steels; systems devoid of threaded fittings; systems devoid of welded fittings; methods devoid of a separation step upstream of the demethanizer methods devoid of a pump upstream of the NRU distillation column.
This application is entitled to and claims the benefit of earlier filed provisional application Ser. No. 62/654,684, filed Apr. 9, 2018, under 35 U.S.C. § 119(e), which earlier filed provisional application is incorporated by reference herein in its entirety.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2019/026300 | 4/8/2019 | WO | 00 |
| Number | Date | Country | |
|---|---|---|---|
| 62654684 | Apr 2018 | US |
