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WO2018201095A1 - Système et procédé de production d'électricité par réduction de pression de gaz naturel - Google Patents

Système et procédé de production d'électricité par réduction de pression de gaz naturel Download PDF

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Publication number
WO2018201095A1
WO2018201095A1 PCT/US2018/030026 US2018030026W WO2018201095A1 WO 2018201095 A1 WO2018201095 A1 WO 2018201095A1 US 2018030026 W US2018030026 W US 2018030026W WO 2018201095 A1 WO2018201095 A1 WO 2018201095A1
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WO
WIPO (PCT)
Prior art keywords
process gas
flow
pressure
inlet
turboexpander
Prior art date
Application number
PCT/US2018/030026
Other languages
English (en)
Inventor
Andrew Brash PEARSON
Original Assignee
Anax Holdings, Llc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Anax Holdings, Llc filed Critical Anax Holdings, Llc
Publication of WO2018201095A1 publication Critical patent/WO2018201095A1/fr
Priority to US16/663,151 priority Critical patent/US20200059179A1/en

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Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C6/00—Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas-turbine plants for special use
    • F02C6/18—Plural gas-turbine plants; Combinations of gas-turbine plants with other apparatus; Adaptations of gas-turbine plants for special use using the waste heat of gas-turbine plants outside the plants themselves, e.g. gas-turbine power heat plants
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F01—MACHINES OR ENGINES IN GENERAL; ENGINE PLANTS IN GENERAL; STEAM ENGINES
    • F01D—NON-POSITIVE DISPLACEMENT MACHINES OR ENGINES, e.g. STEAM TURBINES
    • F01D15/00—Adaptations of machines or engines for special use; Combinations of engines with devices driven thereby
    • F01D15/10—Adaptations for driving, or combinations with, electric generators
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F02—COMBUSTION ENGINES; HOT-GAS OR COMBUSTION-PRODUCT ENGINE PLANTS
    • F02C—GAS-TURBINE PLANTS; AIR INTAKES FOR JET-PROPULSION PLANTS; CONTROLLING FUEL SUPPLY IN AIR-BREATHING JET-PROPULSION PLANTS
    • F02C1/00—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid
    • F02C1/02—Gas-turbine plants characterised by the use of hot gases or unheated pressurised gases, as the working fluid the working fluid being an unheated pressurised gas

Definitions

  • the present disclosure relates to the production of electricity using the expansion of compressed natural gas coupled with waste heat recovery from industrial processes. More specifically, the present disclosure relates to the production of electricity from a reduction in the pressure of the natural gas at a site in the pipeline distribution system for natural gas.
  • Natural gas is obtained from wells drilled into in rock formations deep underground, where natural gas is found alone and in association with other hydrocarbon fuels such as petroleum and coal deposits.
  • natural gas from such wells is cleaned, typically compressed, and is then distributed by a system of natural gas pipelines to the industrial and residential sites of use of the natural gas as a fuel. Since the natural gas in the distribution pipeline is typically at a higher pressure than the pressure needed at the site of use, a pressure let down station is usually situated between the sites of use and the high pressure pipeline distribution system as a facility where the pressure of the natural gas can be reduced before the natural gas is delivered to where it will be used.
  • the process of reducing the pressure of the natural gas at a pressure let down station provides an opportunity to recover useful energy without the combustion of the natural gas. It is desirable have an alternative to combustion, since complete combustion produces carbon dioxide a greenhouse gas and incomplete combustion can release methane, also a greenhouse gas, that is a major component of natural gas. From one perspective, the recovery of energy from the pressure differential between the natural gas in the distribution pipeline system and the natural gas downstream of the site of a pressure let down station can be regarded as the recovery of "waste heat," energy that would otherwise be unavailable for use.
  • Pressure, volume and temperature (T) are related by the ideal gas laws that state, for example that
  • ⁇ (gamma) is the index of compression (or expansion) and k is a constant value.
  • Enthalpy is a useful concept because the form of the energy is not specified, so heat energy, potential energy and work energy are all subject to the same rules and can be treated the same way.
  • the enthalpy is given relative to a datum point so care must be taken in comparing different calculations done at different times by different people to ensure that they used the same datum. It is usual to consider the enthalpy per mass of the gas, sometimes called the specific enthalpy, which is measured in BTU per pound, or in the metric system, in kJ per kg.
  • the Joule-Thompson effect causes the outlet gas to cool, typically by about 5 °F per 100 psi pressure drop.
  • the pressure of natural gas is reduced from 930 psig to 120 psig, a 810 psi (55.8 Bar) pressure drop, the gas might drop from an inlet temperature of 60 °F (15.6 °C) to about 9.4 °F (-12.6 °C).
  • Natural gas at a temperature of 9.4 °F (-12.6 °C) is too cold for onward transmission, so pressure let down stations typically incorporate some form of heating, often just taking a small portion of the natural gas and burning it to heat a water bath which is used to warm up the gas flow either before or after expansion.
  • a system is disclosed that provides at least two turboexpanders operatively linked to a generator that generates electrical power from the reduction of the pressure of a natural gas stream wherein the system reduces the pressure of the natural gas stream in at least two pressure reduction stages, and wherein heat is added to the natural gas stream by the system to adjust the temperature before each pressure reduction stage.
  • the generator is a permanent magnet generator.
  • an apparatus comprises a first stage turboexpander having a common shaft, an inlet configured to receive a flow of a process gas, wherein the process gas flow is characterized by a flow rate, a pressure and a temperature, and an outlet; a second stage turboexpander mounted with the first stage turboexpander on the common shaft, having an inlet configured to receive the flow of the process gas discharged from the outlet of the first stage turboexpander and an outlet; a generator mounted with the first stage turboexpander and the second stage turboexpander on the common shaft; and a pressurized housing that encloses the first stage turboexpander, the second stage turboexpander, the generator and the common shaft.
  • the generator is configured to produce electricity when the common shaft rotates as a result of the process gas flowing from the inlet of the first stage turboexpander to the outlet of the second stage turboexpander.
  • the generator is a permanent magnet generator.
  • common shafts can be provided with at least one bearing.
  • the at least one bearing is an oil-free bearing.
  • the at least one bearing is a gas bearing operated by a regulated flow of filtered process gas.
  • the at least one bearing is a magnetic bearing, and in some implementations an active magnetic bearing.
  • the common shaft is provided with at least two journal bearings.
  • the common shaft is provided with at least one thrust bearing.
  • Magnetic bearings can be provided with gap sensor electronics and power amplifiers that supply current to electromagnets within the magnetic bearings.
  • the process gas is heated by a first heat exchanger before it is received by the inlet of the first stage turboexpander. In certain implementations, the process gas is heated by a second heat exchanger before it is received by the inlet of the second stage turboexpander. In certain implementations, the process gas is heated by a heat exchanger after it leaves the outlet of the second stage turboexpander. In certain
  • the process gas is heated by a first or second heat exchanger before it is received by the inlet of the second stage turboexpander. In certain implementations the process gas is heated by a first, second or third heat exchanger after it leaves the outlet of the second stage turboexpander.
  • the ratio of the pressure of the process gas flow at the first stage turboexpander inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.2 to about 3.9. In certain implementations, in use, the ratio of the pressure of the process gas flow at the inlet of the first stage turboexpander to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.2 to about 1.8. In certain implementations, in use, the ratio of the pressure of the process gas flow at the first stage turboexpander inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.8 to about 2.8.
  • the ratio of the pressure of the process gas flow at the inlet of the first stage turboexpander to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 2.8 to about 3.9. In certain implementations, the ratio of the pressure of the process gas flow at the inlet of the first stage turboexpander to the pressure of the process gas flow at the outlet of the first stage turboexpander is about 1.1 to about 1.6. In certain implementations, in use, the ratio of the pressure of the process gas flow at the inlet of the second stage turboexpander to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.1 to about 1.6.
  • the pressure of the process gas at the inlet of the first stage turboexpander is about 100 psig (6.9 Bar) to about 800 psig (55.2 Bar). In certain implementations, the pressure of the process gas at the outlet of the second stage
  • turboexpander is about 40 psig (2.8 Bar) to about 450 psig (31.0 Bar).
  • the pressure of the process gas at the inlet of the first stage turboexpander is about 120 psig (8.3 Bar) to about 180 psig (12.4 Bar) and the pressure of the process gas at the outlet of the second stage turboexpander is about 40 psig (2.8 Bar) to about 80 psig (5.5 Bar).
  • the pressure of the process gas at the inlet of the first stage turboexpander is about 300 psig (20.7 Bar) to about 350 psig (24.1 Bar) and the pressure of the process gas at the outlet of the second stage turboexpander is about 80 psig (5.5 Bar) to about 180 psig (12.4 Bar).
  • the pressure of the process gas at the inlet of the first stage turboexpander is about 700 psig (48.3 Bar) to about 800 psig (55.2 Bar) and the pressure of the process gas at the outlet of the second stage turboexpander is about 200 psig (13.8 Bar) to about 450 psig (31.0 Bar).
  • the power generated by the apparatus is about 50k W to about 500kW. In certain implementations the power generated by the apparatus is about 50kW to about lOOkW. In certain implementations the power generated by the apparatus is about lOOkW to about 200kW. In certain implementations the power generated by the apparatus is about 200kW to about 300kW. In certain implementations the power generated by the apparatus is about 300kW to about 500kW.
  • the flow rate of the process gas at the inlet of the first stage turboexpander is typically about 2.0 kg/sec (6,018 scfm, 264 lb/min) to about 2.5 kg/sec (7,523 scfm, 330 lb/min).
  • the flow rate of the process gas at the inlet of the first stage turboexpander is typically about 3.1 kg/sec (9,328 scfin, 409 lb/min) to about 3.8 kg/sec (11,434 scfin, 502 lb/min).
  • the flow rate of the process gas at the inlet of the first stage turboexpander is typically about 4.9 kg/sec (14,744 scfin, 647 lb/min) to about 6.0 kg/sec (18,054 scfin, 792 lb/min).
  • the apparatus is configured to operate with a flow rate of the process gas at the inlet of the first stage turboexpander of about 4.5 kg/sec (13,541 scfin, 594 lb/min) to about 6.5 kg/sec (19,539 scfin, 858 lb/min).
  • the apparatus is configured to operate with a flow rate of the process gas at the inlet of the first stage turboexpander of about 5 kg/sec (15,045 scfin, 660 lb/min) to about 6 kg/sec (18,054 scfin, 792 lb/min). It is evident that the mass flow rates quoted are proportionate to the generating capacity and the examples cited can be configured to suit other generating capacities within the scope of the invention.
  • a system comprising a system inlet configured to receive a flow of a process gas, wherein the process gas flow is characterized by a flow rate, a pressure and a temperature; a first heat exchanger having a process gas inlet configured to receive the flow of the process gas from the system inlet, a process gas outlet, a secondary fluid inlet and a secondary fluid outlet, wherein the secondary fluid is
  • a flow rate, a pressure and a temperature characterized by a flow rate, a pressure and a temperature; a first stage turboexpander having a common shaft, an inlet configured to receive the flow of the process gas from the first heat exchanger process gas outlet and an outlet; a second heat exchanger having a process gas inlet configured to receive the flow of the process gas from the first stage turboexpander outlet, a process gas outlet, a secondary fluid inlet and a secondary fluid outlet; a second stage turboexpander mounted with the first stage turboexpander on the common shaft, having an inlet configured to receive the flow of the process gas from the process gas outlet of the second heat exchanger and an outlet; a generator mounted with the first stage turboexpander and the second stage turboexpander on the common shaft; a pressurized housing that encloses the first stage turboexpander, the second stage turboexpander, the generator and the common shaft; and a system controller.
  • the system is mounted in a frame configured for commercial transportation.
  • the system controller further comprises at least one sensor selected from the group consisting of a sensor that is configured to detect the flow rate of the process gas, a sensor that is configured to detect the pressure of the process gas, a sensor that is configured to detect the temperature of the process gas, a sensor that is configured to detect the flow rate of the secondary fluid, a sensor that is configured to detect the pressure of the secondary fluid, and a sensor that is configured to detect the temperature of the secondary fluid.
  • the system controller further comprises at least one actuator selected from the group consisting of a hydraulic actuator, an electric motor, a pneumatic actuator and an electrical relay.
  • the system controller further comprises control electronics including a programmable logic controller.
  • the system controller further comprises a computer comprising a microprocessor, a visual display, nonvolatile memory, RAM memory, and at least one user input device selected from a touch screen, a keypad, a keyboard, a mouse, a touch pad, track pad and a track ball.
  • the computer is connected to a local network by Ethernet or a wireless connection, and to the Internet.
  • the ratio of the pressure of the process gas flow at the system inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.2 to about 3.9. In certain implementations, in use, the ratio of the pressure of the process gas flow at the system inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.2 to about 1.8. In certain
  • the ratio of the pressure of the process gas flow at the system inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 1.8 to about 2.8. In certain implementations, in use, the ratio of the pressure of the process gas flow at the system inlet to the pressure of the process gas flow at the outlet of the second stage turboexpander is about 2.8 to about 3.9.
  • the pressure of the process gas at the system inlet is about 120 psig (8.3 Bar) to about 750 psig (51.7 Bar). In certain implementations, the pressure of the process gas at the outlet of the second stage turboexpander is about 80 psig (5.5 Bar) to about 450 psig (31.0 Bar).
  • the system is configured to operate with a flow rate of the process gas at the system inlet of about 4 kg/sec (12,039 scfin, 528 lb/min) to about 7 kg/sec (21,063 scfin, 924 lb/min).
  • the system is configured to operate with a flow rate of the process gas at the system inlet of about 4.5 kg/sec (13,541 scfin, 594 lb/min) to about 6.5 kg/sec (19,449 scfin, 858 lb/min). In certain implementations with a generating capacity of 250k W of electrical output power, the system is configured to operate with a flow rate of the process gas at the system inlet of about 5 kg/sec (15,045 scfin, 660 lb/min) to about 6 kg/sec (18,054 scfin, 792 lb/min).
  • the ratio of the inlet gas pressure to the inlet gas pressure of the system is less than 2 and the number of pressure reduction stages is at least two. In certain implementations, the pressure ratio of the system is less than 1.9. In certain implementations, the pressure ratio of the system is less than about 1.7. In certain implementations, the pressure ratio of a pressure reduction stage is less than about 1.7. In certain implementations, the pressure ratio of a pressure reduction stage is less than about 1.3. The ability of the system to generate electricity with a system pressure reduction of less than about 2 using at least two pressure reduction stages reduces the amount of heat that must be applied to the natural gas stream before each pressure reduction stage.
  • the system accepts a nominal inlet pressure of about 750 psig (51.7 Bar), being able to tolerate inlet pressures of about 900 psig (62 Bar) to about 600 psig (41.4 Bar) and an outlet pressure of about 450 psig (31 Bar), having a system pressure ratio of 1.67.
  • the system accepts a nominal inlet pressure of about 350 psig (24.1 Bar) and an outlet pressure of about 80 (5.5 Bar) psig, having a system pressure ratio of 4.38.
  • the system accepts a nominal inlet pressure of about 300 psig (20.6 Bar) and an outlet pressure of about 180 (12.4 Bar) psig, having a system pressure ratio of 1.67.
  • the system includes two pressure reduction stages provided by two turboexpanders, each of which is operatively connected to a generator.
  • a turboexpander and the generator are mounted on the same shaft assembly.
  • two turboexpanders and a generator are mounted on the same shaft assembly.
  • the generator is a permanent magnet generator.
  • the present disclosure provides systems for power generation, the systems comprising a first heat exchanger, a first turboexpander, one or more second heat exchangers, one or more second turboexpanders, one or more third heat exchangers, one or more third turboexpanders, and at least one electrical generator operatively coupled to one or more of the first turboexpander, the one or more second turbo expanders, and the one or more third turboexpanders.
  • the present disclosure provides methods for generating power, the methods comprising receiving a first flow of a process gas, heating the first flow of process gas with a first heat exchanger to generate a second flow of the process gas, expanding the second flow with a first turboexpander to generate a third flow of the process gas, heating the third flow of the process gas with one or more second heat exchangers, each second heat exchanger generating a fourth flow of the process gas, expanding the one or more fourth flows of the process gas with one or more second turboexpanders, each second turboexpander generating a fifth flow of the process gas, and producing electrical energy with at least one electrical generator operatively coupled to one or more of the first turboexpander and the one or more second turboexpanders.
  • the methods can further comprise heating the one or more fifth flows with one or more third heat exchangers, each third heat exchanger generating a sixth flow of the process gas, expanding the one or more sixth flows with one or more third turboexpanders, each third turboexpander generating a seventh flow of the process gas, and wherein the at least one electrical generator is operatively coupled to one or more of the first turboexpander, the one or more second turboexpanders, and the one or more third turboexpanders.
  • the methods can further comprise providing each of the first, second, and third heat exchangers with a supply flow of a heat-transfer fluid.
  • the heat-transfer fluid can be provided at a temperature of less than about 250°F, less than about 200°F, less than about 150°F, less than about 130°F, less than about 110°F, or less than about 90°F.
  • FIG. 1A is a schematic diagram of an implementation of the disclosed system 10, showing the path of a process gas from a process gas inlet SO passing through a first heat exchanger 410, a first stage turboexpander 110, a second heat exchanger 420, a second stage turboexpander 210, to a process gas outlet 60, where the first stage turboexpander 110 and the second stage turboexpander 210 are operatively coupled to a generator 310 by a shaft assembly 340, wherein, in use, the flow of the process gas through the system 10 from the process gas inlet SO to the process gas outlet 60 produces an electrical output 80.
  • FIG. IB is a block diagram of an implementation of a system controller 500, showing the system controller 500 operatively connected to a first stage turboexpander 110, a second stage turboexpander 210, a generator 310, a DC / AC converter 380, a first heat exchanger 410, a second heat exchanger 420, a valve system 600 and a sensor system 700.
  • FIG. 2 is a schematic section view of an implementation of a disclosed turboexpander and generator unit 100 wherein a first stage turboexpander 110 and a second stage turboexpander 210 are operatively coupled to a generator 310 by a common shaft assembly 340.
  • FIG. 3 A is a top view of an implementation of a disclosed turboexpander and generator unit 100 including a first stage turboexpander 110, a second stage turboexpander 210, a generator 310, a first stage turboexpander inlet 101 C, a first stage turboexpander outlet 101 D, a second stage turboexpander inlet 10 IB, a second stage turboexpander outlet 101A, and a gas bearings inlet 101F.
  • FIG. 3B is a side view of an implementation of a disclosed turboexpander and generator unit 100 showing a first stage turboexpander outlet 101D, a terminal box 370, a terminal box cover 372, a second stage turboexpander outlet 101 A, and a gas bearings inlet 101F.
  • FIG. 3C is a perspective view of an implementation of a disclosed turboexpander and generator unit 100 showing a first stage turboexpander outlet 10 ID, a first stage turboexpander housing 120, a terminal box 370, a terminal box cover 372, a gas bearings inlet 101F, and a second stage turboexpander housing 220.
  • FIG. 3D is perspective view of an implementation of a disclosed turboexpander and generator unit 100 including a second stage turboexpander outlet 101 A, a second stage turboexpander housing 220, a second stage turboexpander inlet 101B, a terminal box 370, a terminal box cover 372, a gas bearings outlet 101E, a first stage turboexpander inlet 101C, and a first stage turboexpander housing 120.
  • FIG. 4 is a schematic diagram of an implementation of the present disclosure, showing an exemplary system 1000.
  • FIG. 5 is a schematic diagram of an implementation of the present disclosure, showing an exemplary system 1001.
  • a "turboexpander” is a radial or axial flow turbine through which a relatively high pressure gas is expanded to produce work.
  • ' ⁇ working fluid refers to natural gas that has been processed and transported in a natural gas distribution pipeline system and which is available for use by the disclosed system and apparatus. Typically, certain components of the gas that is obtained from the wellhead are removed before the natural gas is introduced into a pipeline system. Examples of the typical chemical composition of pipeline natural gas are provided in Table 1, below.
  • secondary fluid refers to a fluid that is used to heat or cool the process gas or the control electronics.
  • the secondary fluid is supplied to a heat exchanger to heat the process gas.
  • the secondary fluid is water or an aqueous solution.
  • the secondary fluid can be an aqueous solution of an antifreeze additive, such as propylene glycol, ethylene glycol, glycerol, or combinations thereof.
  • an antifreeze additive such as propylene glycol, ethylene glycol, glycerol, or combinations thereof.
  • a heat-transfer fluid can be provided for use in heat exchangers as part of a heating circuit and can be any fluid suitable for transferring heat to a process gas, including but not limited to oils and aqueous solutions.
  • the heat-transfer fluid can be a dielectric fluid, including but not limited to one or more perfluorinated carbons, including but not limited to FLUORINERlTM (3M Company, St. Paul, MN), synthetic hydrocarbons, including but not limited to polyalphaolefins (PAO), or combinations thereof.
  • two distinct heat-transfer fluid circuits are provided, with a first heat-transfer fluid circuit provided for cooling the control electronics and a second heat- transfer fluid circuit provided for heating the process gas.
  • heat that is removed from the control electronics can be used in the heating of the process gas by transferring heat between the first and second heat-transfer circuits.
  • An apparatus comprising a process gas system inlet, a process gas system outlet, at least two turboexpanders (a centrifugal or axial flow turbine through which a high pressure process gas is expanded to produce work), and at least one electrical generator operatively coupled to the at least two turboexpanders wherein electrical energy is produced by using the pressure difference between the process gas system inlet and the process gas system outlet.
  • the process gas is natural gas in a natural gas distribution pipeline system.
  • an implementation of the disclosed system is placed at a site between a high pressure location in a natural gas distribution pipeline and a lower pressure location, such as a pressure let down station (also termed a "city gate” station), in order to recover energy from the reduction in pressure required to provide the natural gas at a pressure suitable for consumers.
  • a pressure let down station also termed a "city gate” station
  • the apparatus comprises a first stage turboexpander operatively coupled to the electrical generator, wherein the first stage turboexpander has a first process gas inlet and a first process gas outlet, an electrical generator operatively coupled to the first stage turboexpander, a second stage turboexpander operatively coupled to the electrical generator, wherein the second stage turboexpander has a second process gas inlet, and a second process gas outlet and control circuitry.
  • the system includes a first heat exchanger effective to adjust the temperature of the process gas supplied to the first process gas inlet.
  • the associated system includes a second heat exchanger effective to adjust the temperature of the process gas supplied to the second process gas inlet.
  • the operative coupling between the first stage turboexpander and the electrical generator is a mechanical coupling.
  • the operative coupling between the second stage turboexpander and the electrical generator is a mechanical coupling.
  • the first stage turboexpander and the magnets of the electrical generator are mounted on a common shaft.
  • the first stage turboexpander, the magnets of the electrical generator and the second stage turboexpander are mounted on a common shaft.
  • the first heat exchanger is controlled to keep the temperature of the process gas at the first process gas inlet and the temperature of the process gas at the first process gas outlet within a predetermined range. In certain implementations, the first heat exchanger is controlled to keep the temperature difference of the process gas at the first process gas inlet compared to the first process gas outlet within a predetermined range. In certain implementations of the disclosed system, the second heat exchanger is controlled to keep the temperature of the process gas at the second process gas inlet and the temperature of the process gas at the second process gas outlet within a predetermined range. In certain implementations of the disclosed system, the second heat exchanger is controlled to keep the temperature difference of the process gas at the second process gas inlet compared to the second process gas outlet within a predetermined range.
  • the process gas from the upstream natural gas supply network is passed through a first heat exchanger which transfers heat from a secondary fluid to the process gas and raises the temperature of the process gas to a suitable temperature for the process gas inlet of the first stage turboexpander, for example, typically 130-150 °F (54.4-65.6 °C) in certain implementations.
  • the process gas passes through the first stage of expansion, dropping the pressure to an intermediate level as some of the enthalpy is used to produce electricity, thereby cooling the process gas.
  • This cooled process gas then passes through a second heat exchanger, which raises the gas temperature, for example, back to 130-150 °F (54.4-65.6 °C).
  • the second stage of expansion in the second stage turboexpander brings the temperature of the process gas back down to a temperature configured to further distribution, extracting enthalpy and lowering the pressure to the corresponding value.
  • the low pressure warm gas from the second stage turboexpander outlet in certain implementations at a temperature of at least 50 °F (10 °C), is fed into the downstream distribution network.
  • the secondary fluid is an aqueous solution.
  • the secondary fluid comprises propylene glycol.
  • the secondary fluid is a 30% aqueous solution of propylene glycol.
  • the secondary fluid is heated by a suitable source of heat, such as a supply of warm water, waste heat generated by an electrical circuit, waste heat generated by a gas engine or a gas re-heater.
  • a suitable source of heat such as a supply of warm water, waste heat generated by an electrical circuit, waste heat generated by a gas engine or a gas re-heater.
  • the source of heat for the secondary fluid or heat-transfer fluid is a low-grade waste heat source that provides a heat source with temperature less than about 450°F.
  • the source of heat can be an ultra-low-grade waste heat source that provides a heat source with temperature less than about 250°F.
  • the source of heat can be a very-low-grade waste heat source that provides a heat source with temperature less than about 200°F, less than about 190°F, less than about 180°F, less than about 170°F, less than about 160°F, less than about 150°F, less than about 140°F, less than about 130°F, less than about 110°F, less than about 100°F, or less than about 90°F.
  • Variations in process gas pressure at the system inlet are handled automatically by a control system which varies the turbine speed to match the process gas flow requirements and maximizes the recovered energy. If the demand for natural gas downstream of the disclosed system is higher than the flow rate provided by the disclosed system, then a bypass valve is opened to direct additional process gas to the downstream network. If the pressure differential across the pressure let down station is too high, leading to an electrical overload condition in the disclosed system, then the inlet regulator valve of the disclosed system will adjust the gas flow to maintain the optimal operating pressure differential across the disclosed system. This combination of inlet regulation, bypass and active control of the heat input permits the disclosed system to adapt automatically to enable the unit to operate over a wide range of inlet and outlet conditions.
  • FIG. 1 A is a schematic diagram of an implementation of the disclosed system 10, showing the path of a process gas from a process gas inlet 50 passing through a first heat exchanger 410, a first stage turboexpander 110, a second heat exchanger 420; a second stage turboexpander 210, to a process gas outlet 60, where the first stage turboexpander 110 and the second stage turboexpander 210 are operatively coupled to a generator 310 by a shaft assembly 340, wherein, in use, the flow of the process gas through the system 10 from the process gas inlet 50 to the process gas outlet 60 produces an electrical output 80.
  • the turbine blades and nozzles of the disclosed turboexpanders are designed taking into consideration the typical chemical composition of pipeline natural gas.
  • the chemical compositions of two reported analyses of pipeline natural gas with a range are presented in Table 1, below.
  • Methane is the major component of pipeline natural gas, which also contains amounts of ethane, propane, butanes, hexane, nitrogen and carbon dioxide.
  • the turbine blades and nozzles of the disclosed turboexpanders are designed employed models using the compositions listed as "Nominal" or ''Model ' ' as the composition of pipeline natural gas.
  • the turbine blades and nozzles of the disclosed turboexpanders are designed to accommodate efficient function when the first stage turboexpander and the second stage turboexpander are mounted on a common shaft assembly.
  • FIG. IB is a block diagram of an implementation of a system controller 500, showing the system controller 500 operatively connected via actuators and sensors to a first stage turboexpander 110, a second stage turboexpander 210, a generator 310, a DC / AC voltage converter 380, a first heat exchanger 410, a second heat exchanger 420, a valve system 600 and a sensor system 700.
  • the sensor system 700 includes measurement of the rpm of the common shaft of the turboexpander and generator apparatus, temperature sensors, pressure sensors and flow meters.
  • actuators include pneumatic actuators for air pressure controlled valves and electrical relays.
  • the process gas enters the process gas inlet 401C of the first heat exchanger 410 acting as a preheater to warm the process gas using heat provided by a secondary fluid flowing from the secondary fluid inlet 202B to the secondary fluid outlet 202A of the first heat exchanger 410.
  • a suitable secondary fluid is an aqueous solution.
  • the secondary fluid comprises propylene glycol.
  • the secondary fluid is a 30% aqueous solution of propylene glycol.
  • the process gas flows from the process gas outlet 40 ID of the first heat exchanger 410 to the process gas inlet 101C of the first stage turboexpander 110.
  • the flow rate and pressure of the process gas are controlled in the disclosed system by valves and regulators in the system upstream of the process gas inlet 401C by structures and methods known to one of skill in the art.
  • the temperature, flow rate and pressure of the process gas are further adjusted by the first heat exchanger 410.
  • the process gas leaves the first stage turboexpander 110 though the process gas outlet 10 ID and flows to the process gas inlet 402B of the second heat exchanger 420 that act as an interheater to warm the process gas between the first stage turboexpander 110 and the second stage turboexpander 210 in order to adjust the temperature, flow rate and pressure of the process gas.
  • the process gas entering the process gas inlet 402B of the second heat exchanger 420 is warmed by heat provided by a secondary fluid flowing from the secondary fluid inlet 202D to the secondary fluid outlet 202C of the second heat exchanger 420.
  • a suitable secondary fluid is an aqueous solution.
  • the secondary fluid comprises propylene glycol. In some implementations, the secondary fluid is a 30% aqueous solution of propylene glycol.
  • the process gas flows from the process gas outlet 402A of the second heat exchanger 420 to the process gas inlet 101B of the second stage turboexpander 210. Upon exiting the process gas outlet 101A of the second stage turboexpander 210, the process gas flows to the system process gas outlet 30.
  • FIG. 2 is a schematic section view of an implementation of a disclosed turboexpander and generator unit 100 wherein a first stage turboexpander 110 and a second stage turboexpander 210 are operatively coupled to a generator 310 by a common shaft assembly 340.
  • the turboexpander and generator unit 100 is enclosed by a pressurized housing comprising the first stage turboexpander housing 120, the generator housing 320 and the second stage turboexpander housing 220.
  • the disclosed turboexpander and generator unit 100 is enclosed by a pressurized housing comprising the first stage turboexpander housing 120, the generator housing 320 and the second stage turboexpander housing 220.
  • turboexpander and generator system is sealed within a hermetic pressure casing and is configured to withstand system inlet pressures up to 97S psig (67.2 Bar), enabling it to be used in the main backbone of a natural gas distribution network.
  • a high pressure turboexpander and generator system is disclosed that is configured to provide a system outlet pressure about of 450 psig (31 Bar), and is configured to accept a system inlet pressure that is nominally about 750 psig (51.7 Bar), but varying between about 600 psig (41.4 Bar) and about 900 psig (62.1 Bar).
  • turboexpander and generator system can be configured to accept lower system input pressures.
  • the disclosed turboexpander and generator system is configured to provide a high ratio between the system inlet pressure and the system outlet pressure, typically a system inlet pressure of about 350 psig (24.1 Bar) and a system outlet pressure of about 80 psig (5.5 Bar).
  • the disclosed turboexpander and generator system is configured to a lower ratio between the system inlet pressure and the system outlet pressure, typically a system inlet pressure of about 300 psig (20.7 Bar) and a system outlet pressure of about 180 psig (12.4 Bar).
  • first stage turboexpander 110 process gas that has been pre-heated by the first heat exchanger, or preheater, 410 (FIG. 1A) flows into the first stage turboexpander inlet 101C, which is defined by the generator housing 320, past the first stage turbine 124 and flows out through the first stage turboexpander outlet 10 ID, which is defined by the first stage turboexpander housing 120, to the second heat exchanger, or interheater, 420 (FIG. 1A).
  • the first stage turbine 124 is connected by the first stage turbine shaft 140 to the shaft assembly 340.
  • the first stage journal bearing 130 is a gas bearing.
  • the first stage journal bearing 130 is supplied with a regulated flow of filtered process gas.
  • first stage journal bearing 130 is a magnetic bearing.
  • the magnetic bearing can be an active magnetic bearing. The use of gas bearings or magnetic bearings provide the advantage of avoiding lubricant contamination of the process gas that is delivered to the consumer.
  • process gas that has been reheated by the second heat exchanger, or interheater, 420 flows into the second stage
  • turboexpander inlet 101B which is defined by the second stage turboexpander housing 220, past the second stage turbine 224 and flows out through the second stage turboexpander outlet 101 A, which is defined by the second stage turboexpander housing 220.
  • the second stage turbine 224 is connected by the second stage turbine shaft 240 to the shaft assembly 340.
  • the second stage journal bearing 230 and the thrust bearing 330 are gas bearings.
  • the second stage journal bearing 230 and the thrust bearing 330 are supplied with a regulated flow of filtered process gas.
  • second stage journal bearing 230 and the thrust bearing 330 can be magnetic bearings.
  • the magnetic bearings can be active magnetic bearings.
  • the first stage journal bearing 130 and the second stage journal bearing 230 can be magnetic bearings, and the thrust bearing 330 can be omitted because axial stabilization is provided by the magnetic journal bearings 130/230.
  • the generator 310 is coupled to the first stage turbine shaft 140 and the second stage turbine shaft 240 by the shaft assembly 340.
  • the rotation of the shaft assembly 340 and the interaction of the permanent magnets 350 and the stator 324 produces an electrical current that flows through the power feed-through 360 that is makes electrical connections within the tenninal box 370 (FIG. 3A - FIG. 3D).
  • FIG. 3A is a top view of an implementation of a disclosed turboexpander and generator unit 100 including a first stage turboexpander 110, a second stage turboexpander 210, a generator 310, a first stage turboexpander inlet 101 C, a first stage turboexpander outlet 101D, a second stage turboexpander inlet 101B, a second stage turboexpander outlet 101A, and a gas bearings inlet 101F.
  • the gas bearings inlet 101F can be omitted.
  • an electrical connection to active magnetic bearings 130/230 can be provided.
  • 3B is a side view of an implementation of a disclosed turboexpander and generator unit 100 showing a first stage turboexpander outlet 101D, a terminal box 370, a terminal box cover 372, a second stage turboexpander outlet 101 A, and a gas bearings gas inlet 101F.
  • the gas bearings inlet 101F can be omitted.
  • FIG. 3C is a perspective view of an implementation of a disclosed turboexpander and generator unit 100 showing a first stage turboexpander outlet 101D, a first stage
  • turboexpander housing 120 a terminal box 370, a terminal box cover 372, a gas bearings inlet gas 101F, and a second stage turboexpander housing 220.
  • gas bearings inlet 101F can be omitted.
  • FIG. 3D is perspective view of an implementation of a disclosed turboexpander and generator unit 100 including a second stage turboexpander outlet 101 A, a second stage turboexpander housing 220, a second stage turboexpander inlet 101B, a terminal box 370, a terminal box cover 372, a gas bearings gas outlet 101E, a first stage turboexpander inlet 101C, and a first stage turboexpander housing 120.
  • the gas bearings outlet 101E can be omitted.
  • FIG. 4 is a schematic diagram of an implementation of the present disclosure, showing an exemplary system 1000.
  • System 1000 can be used for power generation and includes three stages of pre-heating and turboexpansion.
  • a first heat exchanger (1100A) can include a first process-gas-heating inlet (1102 A), a first process-gas-heating outlet (1104A), a first heat-transfer-fluid inlet (1106 A), and a first heat-transfer-fluid outlet (1108A).
  • a first turboexpander (1110A) can include a first process-gas inlet (1112A) configured to receive a first process gas fluid flow from the first process-gas-heating outlet, and a first process-gas outlet (1114A).
  • a second heat exchanger (1100B) can be provided, including a second process-gas-heating inlet (1102B), a second process-gas-heating outlet (1104B), a second heat-transfer-fluid inlet (1106B), and a second heat-transfer-fluid outlet (1108B).
  • a second turboexpanders (1110B) can be provided, including a second process-gas inlet (1112B) configured to receive a second process gas fluid flow from the second process-gas-heating outlet, and a second process-gas outlet (1114B).
  • One or more third heat exchangers (1 lOOC) can be provided, with each including a third process-gas-heating inlet (1102C), a third process-gas-heating outlet ( 1104C), a third heat-transfer-fluid inlet (1106C), and a third heat- transfer-fluid outlet (1108C).
  • the process gas flow exiting the second turboexpander 1110B via the second process-gas outlet 1114B can be split into two or more flow streams that are directed into two or more third heat exchangers 1 lOOC. Three flow streams are depicted in FIG.
  • process gas flow exiting the second turboexpander 1110B may remain as a single stream into a single third heat exchanger and third turboexpander, or the process gas flow exiting the second turboexpander can be split into two flow streams for two third heat exchangers and two third
  • turboexpanders or the process gas flow exiting the second turboexpander can be split into four or more flow streams for associated third heat exchangers and third turboexpanders.
  • One or more third turboexpanders (11 IOC) can be provided, with each including a third process- gas inlet (1112C) configured to receive a third process gas fluid flow from the third process- gas-heating outlet, and a third process-gas outlet (1114C).
  • the system further includes at least one electrical generator (1200) operatively coupled to one or more of the first turboexpander, the one or more second turboexpanders, and the one or more third turboexpanders.
  • the at least one electrical generator (1200) can be operatively coupled to one or more of the turboexpanders by being mounted with the one or more turboexpanders on a common shaft (not shown in FIG. 4 for clarity).
  • FIG. 5 is a schematic diagram of an implementation of the present disclosure, showing an exemplary system 1001.
  • System 1001 can be used for power generation and includes three stages of pre-heating and turboexpansion.
  • System 1001 differs from system 1000 in that two or more second turboexpanders 1 HOB are included in the system 1001.
  • a first heat exchanger (1100A) can include a first process-gas-heating inlet (1102 A), a first process-gas-heating outlet (1104A), a first heat-transfer-fluid inlet ( 1106A), and a first heat- transfer-fluid outlet (1108A).
  • a first turboexpander (1110A) can include a first process-gas inlet (1112A) configured to receive a first process gas fluid flow from the first process-gas- heating outlet, and a first process-gas outlet (1114A).
  • One or more second heat exchangers (1100B) can be provided, with each including a second process-gas-heating inlet (1102B), a second process-gas-heating outlet (1104B), a second heat-transfer-fluid inlet (1106B), and a second heat-transfer-fluid outlet (1108B).
  • the process gas flow exiting the first turboexpander (1110A) via the first process-gas outlet (1114A) can be split into two or more flow streams that are directed into two or more second heat exchangers 1100B. Three such process gas flow streams are depicted in FIG. 5, but in other implementations the process gas flow exiting the first turboexpander 1110A may remain as a single stream into a single second heat exchanger 1100B and second turboexpander 1110B (as shown in FIG.
  • first turboexpander 1110A can be split into two flow streams for two second heat exchangers 1100B and two second turboexpanders 1110B, or the process gas flow exiting the first turboexpander 1110A can be split into four or more flow streams for associated second heat exchangers 1100B and second turboexpanders 1110B.
  • One or more second turboexpanders (1 HOB) can be provided, with each including a second process-gas inlet (1112B) configured to receive a second process gas fluid flow from the second process-gas-heating outlet, and a second process-gas outlet (1114B).
  • the process gas flow exiting the second turboexpander 1110B via the second process-gas outlet 1114B can be split into two or more flow streams that are directed into two or more third heat exchangers 1 lOOC.
  • Three flow streams are depicted in FIGs. 4 and 5, but in other implementations the process gas flow exiting the second turboexpander 1110B may remain as a single stream into a single third heat exchanger and third turboexpander, or the process gas flow exiting the second turboexpander can be split into two flow streams for two third heat exchangers and two third turboexpanders, or the process gas flow exiting the second turboexpander can be split into four or more flow streams for associated third heat exchangers and third turboexpanders.
  • One or more third heat exchangers (1100C) can be provided, with each including a third process-gas-heating inlet (1102C), a third process-gas-heating outlet (1104C), a third heat-transfer-fluid inlet (1106C), and a third heat-transfer-fluid outlet (1108C).
  • One or more third turboexpanders (11 IOC) can be provided, with each including a third process-gas inlet (1112C) configured to receive a third process gas fluid flow from the third process-gas-heating outlet, and a third process-gas outlet (1114C).
  • the system further includes at least one electrical generator (1200) operatively coupled to one or more of the first turboexpander, the one or more second turboexpanders, and the one or more third turboexpanders.
  • the at least one electrical generator (1200) can be operatively coupled to one or more of the turboexpanders by being mounted with the one or more turboexpanders on a common shaft (not shown in FIG. 5 for clarity).
  • the process gas from an upstream gas supply network is supplied to the first heat exchanger 1100 A at the first process-gas-heating inlet 1102A.
  • the first heat exchanger 1100A is supplied with a heat- transfer fluid, also referred to as a secondary fluid, which transfers heat to the process gas and raises the temperature of the process gas to a suitable temperature for the first process-gas inlet 1112A of the first stage turboexpander 1110A, for example, typically 130-150 °F (54.4- 65.6 °C) in certain implementations.
  • the process gas passes through the first stage of expansion, dropping the pressure to an intermediate level as some of the enthalpy is used to produce electricity, thereby cooling the process gas.
  • This cooled process gas then passes through the one or more second heat exchangers 1100B, which raise the process gas temperature, for example, back to 130-150 °F (54.4-65.6 °C).
  • the second stage of expansion in the second stage turboexpanders 1110B brings the temperature of the process gas back down to an intermediate level, extracting enthalpy and lowering the pressure to the corresponding value.
  • This cooled process gas then passes through the one or more third heat exchangers 1 lOOC, which raise the process gas temperature, for example, back to 130-150 °F (54.4-65.6 °C).
  • the process gas passes through the third stage of expansion, dropping the pressure to a distribution level as some of the enthalpy is used to produce electricity, thereby cooling the process gas.
  • the low pressure warm gas from the third stage turboexpander outlet in certain implementations at a temperature of at least 50 °F (10 °C), is fed into the downstream distribution network.
  • the three-stage systems shown in FIGs. 4 and 5 can advantageously provide for pressure reduction from pipeline transmission levels, which can be from about 200 psig (13.8 Bar) to about 1500 psig ( 103.4 Bar), down to neighborhood or house distribution levels less than about 200 psig (13.8 Bar), less than about 100 psig (6.9 Bar), less than about 80 psig (5.5 Bar), less than about 60 psig (4.1 Bar), less than about 40 psig (2.8 Bar), less than about 25 psig (1.7 Bar), or less than about 15 psig (1.0 Bar).
  • the process gas entering the first process-gas-heating inlet 1102A can have a pressure of about 750 psig (51.7 Bar).
  • the heat-transfer fluid can be provided at a temperature of less than about 250°F, less than about 200°F, less than about 150°F, less than about 130°F, less than about 110°F, or less than about 90°F.
  • the present disclosure provides for methods of generating power.
  • the methods can comprise (i) receiving a first flow of a process gas, wherein the first flow is characterized by a first flow rate, a first pressure, and a first temperature, (ii) heating the first flow with a first heat exchanger to generate a second flow of the process gas, wherein the second flow is characterized by a second flow rate, a second pressure, and a second temperature, (iii) expanding the second flow with a first turboexpander to generate a third flow of the process gas, wherein the third flow is characterized by a third flow rate, a third pressure, and a third temperature, (iv) heating the third flow with one or more second heat exchangers, each second heat exchanger generating a fourth flow of the process gas, wherein the fourth flow is characterized by a fourth flow rate, a fourth pressure, and a fourth temperature, (v) expanding the one or more fourth flows with one or more second turboexpanders, each second turboexpander generating a
  • the methods can further comprise providing each of the first, second, and third heat exchangers with a supply flow of a heat-transfer fluid.
  • the heat-transfer fluid can be provided at a temperature of less than about 250°F, less than about 200°F, less than about 150°F, less than about 130°F, less than about 110°F, or less than about 90°F.
  • the at least one electrical generator is operatively coupled to one or more of the first turboexpander, the one or more second turboexpanders, and the one or more third turboexpanders via a common shaft.
  • two or more electrical generators are operatively coupled to one or more of the first
  • turboexpander the one or more second turboexpanders, and the one or more third turboexpanders via two or more common shafts.
  • a torque can be imparted on each common shaft by the expanding gas in the one or more turboexpanders and the torque can be converted to electricity by the electrical generator.
  • the electrical power output from the turboexpander and the electrical generator can pass to an inverter where it is first rectified to DC then converted to AC at a voltage and frequency to be consistent with the characteristics of the local electricity grid.
  • the electrical generator can be a permanent magnet generator.
  • the methods can further comprise sensing an operational characteristic using at least one sensor selected from the group consisting of a sensor that is configured to detect a flow rate of the process gas, a sensor that is configured to detect a pressure of the process gas, and a sensor that is configured to detect a temperature of the process gas.
  • the methods can further comprise sensing an operational characteristic using at least one sensor selected from the group consisting of a sensor that is configured to detect a flow rate of the heat-transfer fluid, a sensor that is configured to detect the pressure of the heat-transfer fluid, and a sensor that is configured to detect the temperature of the heat-transfer fluid.
  • the present disclosure provides for methods of generating power.
  • the methods can comprise (i) receiving a first flow of a process gas, wherein the first flow is characterized by a first flow rate, a first pressure, and a first temperature, (ii) heating the first flow with a first heat exchanger to generate a second flow of the process gas, wherein the second flow is characterized by a second flow rate, a second pressure, and a second temperature, (iii) expanding the second flow with a first turboexpander to generate a third flow of the process gas, wherein the third flow is characterized by a third flow rate, a third pressure, and a third temperature, (iv) heating the third flow with one or more second heat exchangers, each second heat exchanger generating a fourth flow of the process gas, wherein the fourth flow is characterized by a fourth flow rate, a fourth pressure, and a fourth temperature, (v) expanding the one or more fourth flows with one or more second turboexpanders, each second turboexpander generating a
  • the methods can further comprise providing each of the first and second heat exchangers with a supply flow of a heat-transfer fluid.
  • the heat-transfer fluid can be provided at a temperature of less than about 250°F, less than about 200°F, less man about 150°F, less than about 130°F, less than about 110°F, or less than about 90°F.
  • the at least one electrical generator is operatively coupled to one or more of the first turboexpander and the one or more second turboexpanders via a common shaft.
  • the methods can further comprise sensing an operational characteristic using at least one sensor selected from the group consisting of a sensor that is configured to detect a flow rate of the process gas, a sensor that is configured to detect a pressure of the process gas, and a sensor that is configured to detect a temperature of the process gas.
  • the methods can further comprise sensing an operational characteristic using at least one sensor selected from the group consisting of a sensor that is configured to detect a flow rate of the heat-transfer fluid, a sensor that is configured to detect the pressure of the heat-transfer fluid, and a sensor that is configured to detect the temperature of the heat-transfer fluid.
  • gas bearings are described in relation to shafts.
  • active magnetic bearings can substituted, provided that an appropriate electrical power source for the active magnetic bearings is provided.
  • a regulated flow of filtered process gas and associated gas bearing inlets/outlets are not required, which can provide an advantage of simplifying the system design.
  • Active magnetic bearings have been observed to be more robust for field use in comparison with gas bearings in some implementations.
  • a turboexpander and generator unit has a two stage process gas expander, each stage including a turboexpander and a heat exchanger.
  • High pressure (HP) process gas is first heated to increase the process gas volume and maintain the temperature inside the expander.
  • the heated HP process gas then passes to the first stage turboexpander where it imparts a torque on the common shaft as it expands through the turbine.
  • the process gas then leaves the first stage turboexpander at an inter-stage pressure lower than the pressure at the entry to the first stage turboexpander and is heated again. This second heating further increases the process gas volume, maintains the temperature inside the turboexpander and generator unit and ensures the process gas leaving the second stage turboexpander is not too cold.
  • the process gas flows through the second stage turboexpander and imparts a torque on the common shaft as the process gas expands through the turbine.
  • FIGs 1A, IB, 2, 3 A, 3B, 3C and 3D An implementation of the disclosed turboexpander and generator unit and associated system is produced as described above and as illustrated in FIGs 1A, IB, 2, 3 A, 3B, 3C and 3D.
  • the turboexpander turbines are configured to operate at a speed of about 20,000 to about 25,000 rpm. In certain implementations, the turboexpander turbines are configured to operate at a speed of about 21,500 to about 24,000 rpm. In some implementations, the turboexpander turbines are designed for a speed of about 22,500 rpm, and an inlet gas temperature of about 328 °K (54.85 °C, 130 °F). In exemplary
  • the design pressure ratios are as summarized in Table 2, below.
  • the temperature of the process gas at the inlet of the first stage turboexpander and the temperature of the process gas at the inlet of the second stage turboexpander is maintained by using a first heat exchanger and a second heat exchanger, respectively, wherein the first heat exchanger and the second heat exchanger transfer heat from a secondary' fluid, such as a 30% aqueous solution of propylene glycol, to the primary fluid or process gas, the natural gas.
  • a secondary' fluid such as a 30% aqueous solution of propylene glycol
  • the pressure of the process gas at the system inlet is about 754 psi (52 Bar)
  • the pressure of the process gas at the system outlet is about 465.6 psi (32.1 Bar)
  • the system pressure ratio is 1.62.
  • the pressure of the process gas at the first stage inlet is about 750 psi (51.7 Bar)
  • the pressure of the process gas at the first stage outlet is about 594.7 psi (41 Bar)
  • the first stage pressure ratio is 1.27.
  • the pressure of the process gas at the second stage inlet i.e., the inlet of the second stage turboexpander
  • the pressure of the process gas at the second stage outlet i.e., the outlet of the second stage turboexpander
  • the second stage pressure ratio is 1.27.
  • implementations of the disclosed turboexpander and generator unit and associated system operate with a flow rate of process gas of about 4 kg/sec (12,036 scfm, 528 lb/min) to about 7.5 kg/sec (22,568 scfm, 990 lb/min).
  • the disclosed turboexpander and generator unit and associated system operate with a flow rate of process gas of about 4.5 kg/sec (13,541 scfm, 594 lb/min) to about 6.5 kg/sec (19,559 scfm, 858 lb/min).
  • the disclosed turboexpander and generator unit and associated system configured to the range of conditions exemplified by the values summarized in Table 2, above, operates with a flow rate of process gas of about 5 kg/sec (15,045 scfm, 660 lb/min) to about 6 kg/sec (18,054 scfm, 792 lb/min).
  • the disclosed turboexpander and generator unit and associated system configured to the range of conditions operating in a range of conditions exemplified by the values summarized in Table 2, above, can produce an electrical power output of about 225 to about 275 kw, more preferably about 238 to about 263 kW, and typically about 250 kW. In certain implementations, the disclosed turboexpander and generator unit and associated system configured to the range of conditions operating in a range of conditions exemplified by the values summarized in Table 2, above, can produce an electrical power output of about 250 kW.
  • the basic turboexpander and generator unit is configured with related components in a readily transportable turn-key system having components including a controller system 500 operatively connected to a first stage turboexpander 110, a second stage turboexpander 210, a generator 310, a DC / AC converter 380, a first heat exchanger 410, a second heat exchanger 420, a valve system 600 and a sensor system 700 mounted in a frame comprising steel or a material having similar characteristics.
  • the system is pre-configured with piping and wiring, and requires only connection to sources of natural gas, instrument grade compressed air, warm water and electricity. Typically, the required electrical supply to the assembly is three phase 480 volts, 60 Hz.
  • the frame is configured for commercial containerized transportation.
  • the control electronics are contained in a purged cabinet and at least one panel that houses the control electronics is cooled by a heat exchanger system.
  • the control electronics are mounted in a control panel that is cooled by water or an aqueous solution.
  • the control panel is cooled by the secondary fluid, and waste heat extracted by cooling the control electronics can be supplied to the first heat exchanger 410 and the second heat exchanger 420 as a contribution to heating the process gas.
  • the electrical supply to the control panel is single phase 120 volts, 60 Hz.
  • the control electronics include a programmable logic controller.
  • the control electronics include a computer comprising a microprocessor, a visual display, nonvolatile memory, RAM memory, and at least one user input device selected from a touch screen, a keypad, a keyboard, a mouse, a touch pad, track pad and a track ball.
  • the computer is connected to a local network by ethernet or a wireless connection, and to the Internet.
  • the flow of fluids is controlled by pneumatic actuator driven valves and regulators, which are in turn controlled by the control electronics.
  • Fluid pressure relief valves are also provided.
  • Fluid piping includes filters and pressure regulators as known in the art.
  • At least one pump is provided to circulate the secondary fluid through the respective heat exchangers.
  • Table 3 shows typical performance criteria for implementations of the disclosed turboexpander and generator system that are designed to operate at three pressure ratings, with the pressure ratio bands for each range. All implementations configured to operate in the three indicated pressure ranges are based upon a common generator and shaft configuration, but in each implementation, the turbine impellors of the first stage turboexpander 110 and the second stage turboexpander 210 are designed specifically for the given pressure operating range to ensure that the turboexpanders operate at optimal
  • the temperature of the process gas at the process gas inlet 401C of the first heat exchanger 410 and at the process gas inlet 402B of the second heat exchanger 420 are maintained at 150 °F (65.6 °C).
  • the heat conversion percentage shows the amount of waste heat that is converted to useful electricity.
  • an organic rankine cycle system with waste heat available at 250°F (121.1°C) would only achieve a heat conversion percentage of about 12.5% and would require a connection to a cooling tower or other cooling system to dispose of the residual heat once it had been processed.
  • 'MMB/h is one million BTU/h.
  • IMMB/h 293kWof heat
  • implementations of the disclosed turboexpander and generator system convert significantly more of the available heat to electricity, between about 30% and about 70% depending on the operating conditions.
  • heat exchangers use the remainder of waste heat to warm the gas flow passing through the pressure reduction station, preventing condensation and protecting pipes from low temperature embrittlement.
  • little or none of the waste heat recovered is rejected to atmosphere through cooling towers.
  • the disclosed turboexpander and generator system can provide an advantageous way to dispose of excess heat from combustion processes, gas engines or kilns without the high capital and operating costs of running cooling towers.
  • the system is configured to accept an inlet pressure of about 750 psig (51.7 Bar) and the disclosed turboexpander and generator system is designed for a pre-selected pressure ratio (PR), the ratio of the of the pressure of the process gas at the system inlet to the pressure of the process gas at the outlet of the second stage turboexpander.
  • PR pre-selected pressure ratio
  • the difference between the system inlet pressure and the second stage turboexpander outlet pressure affects the requirement for preheating by the first heat exchanger 410 and reheating by the second heat exchanger 420 to provide a suitable outlet temperature of the natural gas for downstream transmission to the sites of use.
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 750 psig (51.7 Bar) to a system outlet pressure of about 200 psig (13.8 Bar). In certain implementations, the disclosed system can be configured to a pressure difference between a system inlet pressure of about 750 psig (51.7 Bar) to a system outlet pressure of about 325 psig (22.4 Bar). In certain implementations, the disclosed system can be configured to a pressure difference between a system inlet pressure of about 750 psig (51.7 Bar) to a system outlet pressure of about 450 psig (31.0 Bar).
  • the system is configured to accept an inlet pressure of about 750 psig (51.7 Bar) and is configured to operate with a flow rate of process gas of about 2.230 kg/sec (6,711 scfm, 294.4 lb/min) to about 5.427 kg/sec (16,330 scfm, 716.4 lb/min).
  • the system is configured to accept an inlet pressure of a medium pressure of about 300 psig (20.7 Bar) to about 350 psig (24.1 Bar), and the disclosed turboexpander and generator system is designed for a pre-selected pressure ratio (PR).
  • PR pre-selected pressure ratio
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 300 psig (20.7 Bar) to a system outlet pressure of about 180 psig (12.4 Bar).
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 325 psig (22.4 Bar) to a system outlet pressure of about 130 psig (9.0 Bar).
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 350 psig (24.1 Bar) to a system outlet pressure of about 80 psig (5.5 Bar).
  • the system is configured to accept an inlet pressure of about 300 psig (20.7 Bar) to about 350 psig (24.1 Bar) and is configured to operate with a flow rate of process gas of about 2.048 kg/sec (6,162 scfm, 270.3 lb/min) to about 5.427 kg/sec (16,330 scfm, 716.4 lb/min).
  • the system is configured to accept an inlet pressure of a lower pressure of about 120 psig (8.3 Bar) to about 180 psig (12.4 Bar), and the disclosed turboexpander and generator system is designed for a pre-selected pressure ratio (PR).
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 120 psig (8.3 Bar) to a system outlet pressure of about 80 psig (5.5 Bar).
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 150 psig (10.3 Bar) to a system outlet pressure of about 60 psig (4.1 Bar).
  • the disclosed system can be configured to a pressure difference between a system inlet pressure of about 180 psig (12.4 Bar) to a system outlet pressure of about 40 psig (2.8 Bar).
  • the system is configured to accept an inlet pressure of about 120 psig (8.3 Bar) to about 180 psig (12.4 Bar) and is configured to operate with a flow rate of process gas of about 2.138 kg/sec (6,433 scfm, 282.2 lb/min) to about 7.284 kg/sec (21,917 scfm, 961.5 lb/min).

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  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • Structures Of Non-Positive Displacement Pumps (AREA)

Abstract

L'invention concerne un système qui comprend au moins deux turbocompresseurs reliés de manière fonctionnelle à un générateur qui génère un courant électrique par la réduction de la pression d'un flux de gaz naturel, le système réduisant la pression du flux de gaz naturel dans au moins deux étapes de réduction de pression, et de la chaleur étant ajoutée au flux de gaz naturel par le système pour ajuster la température avant chaque étape de réduction de pression. Le générateur peut être un générateur à aimant permanent.
PCT/US2018/030026 2017-04-27 2018-04-27 Système et procédé de production d'électricité par réduction de pression de gaz naturel WO2018201095A1 (fr)

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US62/490,913 2017-04-27

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WO2019210309A1 (fr) * 2018-04-27 2019-10-31 Anax Holdings, Llc Système et procédé de production d'électricité par réduction de pression de gaz naturel
CN112576317A (zh) * 2020-12-08 2021-03-30 康锰 一种永磁传动低温多级涡轮发电机
CN114046188A (zh) * 2021-12-01 2022-02-15 重庆科技学院 一种密闭式天然气管道发电、过滤装置
WO2023069784A1 (fr) * 2021-10-22 2023-04-27 Magellan Scientific, LLC Système et procédé de générateur de détente de gaz naturel
WO2024097366A1 (fr) * 2022-11-03 2024-05-10 Sapphire Technologies, Inc. Production d'hydrogène à l'aide d'énergie électrique générée par réduction de pression de gaz

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US5685154A (en) * 1993-07-22 1997-11-11 Ormat Industries Ltd. Pressure reducing system and method for using the same
US20120087778A1 (en) * 2009-08-19 2012-04-12 Hideki Nagao Machine unit layout system
KR20110126056A (ko) * 2010-05-14 2011-11-22 누보 피그노네 에스피에이 발전 시스템용 터보 팽창기
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US20160146352A1 (en) * 2013-05-17 2016-05-26 Victor Juchymenko Methods and systems for sealing rotating equipment such as expanders or compressors

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2019210309A1 (fr) * 2018-04-27 2019-10-31 Anax Holdings, Llc Système et procédé de production d'électricité par réduction de pression de gaz naturel
CN112576317A (zh) * 2020-12-08 2021-03-30 康锰 一种永磁传动低温多级涡轮发电机
CN112576317B (zh) * 2020-12-08 2023-11-24 内蒙古汇能集团蒙南发电有限公司 一种多级涡轮发电机
WO2023069784A1 (fr) * 2021-10-22 2023-04-27 Magellan Scientific, LLC Système et procédé de générateur de détente de gaz naturel
US11761705B2 (en) 2021-10-22 2023-09-19 Magellan Scientific, LLC Natural gas letdown generator system and method
CN114046188A (zh) * 2021-12-01 2022-02-15 重庆科技学院 一种密闭式天然气管道发电、过滤装置
WO2024097366A1 (fr) * 2022-11-03 2024-05-10 Sapphire Technologies, Inc. Production d'hydrogène à l'aide d'énergie électrique générée par réduction de pression de gaz

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