ASU nitrogen sweep gas in hydrogen separation membrane for production of HRSG duct burner fuel

Power-Only IGCC Plant with CO 2 Capture

FIG. 1 shows a simplified process flow diagram (PFD) for an embodiment of the present invention in which a power-only (i.e. without high-purity H 2 production) IGCC plant with CO 2 capture utilizes HTM technology to make a H 2 —N 2 fuel mixture for combustion in the gas turbine and the HRSG duct burner. The portions of the plant representing aspects of the present invention are drawn with dashed lines and/or labeled with bold font in the diagram. While not to be construed as limiting, an exemplary stream summary is given in Table 1 for the computer-simulated example case described below.

As shown in FIG. 1 , air 1 is fed into an ASU 100 where it is separated into O 2 3 , N 2 streams 5 and 6 , and unused products 7 . The O 2 3 is compressed in compressor 102 and fed to the gasifier 104 where it is reacted with a slurry 13 (made from coal 9 and water 11 in mixer 106 ) to form raw syngas 15 and slag 16 . In this example, a Conoco-Philips E-Gas® gasifier is modeled for unit 104 that operates at 615 psia and 1970° F.

The raw syngas 15 exiting gasifier 104 is sent to the syngas processing portion of the plant 108 where it is cooled by generating steam 17 from boiler feed water 19 . The steam 17 is sent to the heat recovery steam generator (HRSG) 110 for use in the steam turbine 112 steam cycle. Impurities 21 in the raw syngas stream that must be removed could include heavy metals, halides, particulate matter, and/or sulfur-containing compounds. Impurity removal may be accomplished via traditional cold gas cleanup technology in this example, but advanced warm gas cleanup technologies may also be used. To maximize IGCC efficiency and the extent of carbon capture, it is preferred that the syngas processing method be designed such that the impurities are separated without capturing carbon-containing species or H 2 .

The water gas shift (WGS) reactors, which are also included in the syngas processing portion of the IGCC plant 108 shown in FIG. 1 , convert H 2 O and CO into H 2 and CO 2 . The WGS reactors are needed to maximize H 2 content in the membrane feed and minimize the amount of CO 2 purification necessary for sequestration. In this particular example, a two-stage WGS reactor design is used. Computer simulation analysis shows that a design for this Example that uses a high temperature shift reactor (HTS) in series with a medium temperature shift reactor (MTS) is preferred over a design with two high temperature shift reactors in series.

The stream 23 exiting the syngas processing portion of the plant 108 is predominantly made up of H 2 , CO 2 , and H 2 O and is fed to hydrogen transport membrane (HTM-GT) 114 at near-gasifier pressure (for example, about 350 to 1000 psia). For this study, the hydrogen membrane 116 is a dense transition metal membrane (such as Nb or Ta) that is coated with Pd catalyst on the surface. The Pd catalyzes the dissociation of H 2 molecules into H atoms on the syngas side 118 of the membrane. The H atoms then diffuse through the bulk metal to the permeate 120 where Pd catalyzes the re-association of H atoms into H 2 molecules that desorb into the bulk gas. This arrangement gives high H 2 flux at near 100% selectivity. The advantage of using metals like Nb or Ta for the bulk membrane is that they have high proton flux but cost much less than Pd. However, the membrane surface should be coated with Pd because the bulk metal is not an efficient catalyst for H 2 dissociation. It should also be noted that any membrane material(s) with reasonable H 2 flux and selectivity would suffice in an IGCC plant for power production. One skilled in the art will appreciate that reasonable H 2 flux and selectivity can be determined based on design conditions, processing and economic factors. While not to be construed as limiting, alternative HTMs for use in the present invention could include membranes having H 2 -selective material formed of one or more of the following: supported or unsupported porous ceramics, dense cermets, dense metals, and/or dense metal alloys.

As used in this Example, ASU N 2 6 emerges from ASU 100 at about 190 psia, while ASU N 2 5 emerges from the ASU at about 60 psia. A portion of ASU N 2 5 becomes stream 41 . The remaining portion 201 of ASU N 2 5 is compressed in compressor 119 to about 190 psia to form stream 203 , which is then combined with ASU N 2 6 to form stream 25 . ASU N 2 25 is compressed in compressor 121 in this example to 385 psia and used as HTM-GT 114 permeate sweep 27 in counter-current flow with the syngas feed 23 . N 2 is used as a permeate sweep stream to decrease H 2 partial pressure, increase H 2 flux across the membrane 116 , reduce the required membrane area, improve gas turbine 122 performance by increasing the mass flow and molecular weight of the expanding gas, and control the turbine inlet temperature to reduce NO x emissions. The H 2 partial pressure profile in HTM-GT 114 in this Example is shown in FIG. 2 . In this example, there is a total pressure drop of 10 psi in the direction of the flow in both the retentate 118 and permeate 120 and the H 2 recovery is 95%. The flow of the sweep gas 27 is set such that the lower heating value (LHV) of the resulting H 2 —N 2 fuel mixture 29 is 125 BTU/scf in order to minimize adiabatic flame temperature and NO x production in the gas turbine combustor 124 . The H 2 content in the fuel 29 is 45.6 vol % as shown in Table 1. In some cases, it may be possible to increase the N 2 sweep flow 27 and decrease the resulting fuel 29 LHV below 125 BTU/scf.

Since pressurized N 2 is used as sweep gas 27 , the HTM-GT 114 permeate 29 can be directly fed to the gas turbine combustor 124 without further compression. In this example, a General Electric Co. (GE) 7251FB gas turbine 122 generates 230 MW of electrical power from 607.1 thousand pounds per hour (kpph) of fuel 29 and compressed air 30 . After expansion, 3770 kpph of exhaust 31 at 1146° F. is sent to the HRSG 110 to generate high pressure steam 33 , intermediate pressure steam reheat 35 and low pressure steam 37 for the steam turbine.

In this example, the H 2 partial pressure in the HTM-GT 114 retentate 39 is 20 psia (see FIG. 2 ). Eighty-five percent of the remaining H 2 is recovered by feeding the H 2 -depleted syngas 39 from HTM-GT 114 into a second HTM 126 (i.e. HTM-DB) that uses LP ASU N 2 41 as a permeate sweep stream. The permeate produced 43 from this HTM 126 is a near-atmospheric pressure (for example, less than or equal to about 25 psia) mixture of H 2 and N 2 that can be combusted in the HRSG duct burner 132 to increase the temperature of the gas turbine exhaust 31 and increase the heat available in the HRSG 110 . The N 2 sweep 41 flow rate to HTM-DB 126 is set such that duct burner fuel 43 LHV is 125 BTU/scf (45.6 vol % H 2 ) in order to minimize additional NO x emissions from the HRSG stack 45 . The H 2 partial pressure profile in HTM-DB 126 is shown in FIG. 3 . HTM-DB 126 generates 25.6 kpph of H 2 —N 2 fuel mixture 43 exiting from permeate 130 of HTM-DB 126 that is burned in the HRSG duct burner 132 to increase the gas temperature in the HRSG 110 from 1146 to 1209° F. The net process efficiency increases from 32.7 to 32.9% (HHV basis) when HTM-DB 126 is used. If it is available, the N 2 sweep flow 41 could be increased such that the LHV of the H 2 —N 2 fuel mixture 43 is as low as 90 BTU/scf. This is possible because there is a longer residence time for combustion in the HRSG 110 .

Membrane 129 of HTM-DB 126 preferably has high (approaching 100%) H 2 permeation selectivity (e.g. the dense, Pd-coated membrane described above) and flux. Those skilled in the art will appreciate that other HTMs such as those described hereinabove may be suitable for use in accordance with the present invention so long as the desired H 2 flux and selectivity are met.

The retentate stream 47 exiting retentate side 128 of HTM-DB 126 is CO 2 -rich at near-gasifier pressure (for example, about 350-1000 psia). Before this stream 47 can be sequestered, it must be purified, dried, and compressed in the CO 2 processing portion of the IGCC plant 134 to produce sequesterable CO 2 49 and waste 51 (e.g., knockout water for catox-based systems) as shown in FIG. 1 . Options for CO 2 purification in 134 include, but are not limited to, catalytic oxidation of residual combustibles with ASU O 2 or CO 2 separation via partial condensation. The CO 2 purification process can be simplified when HTM-DB 126 is used because there is less H 2 to be removed from the CO 2 -rich stream 47 .

It is believed that the best mode for CO 2 purification in the examples cited herein is by oxidizing residual combustibles in one or more catalytic oxidation (catox) reactor(s) with ASU O 2 . There are several reasons including: O 2 is readily available and already being produced on-site with an ASU, the extra capacity required for the catox reactor is less than or equal to about 10% of the O 2 required for the gasifier, and there are advantages to the process heat integration with the catox unit because the high-level heat generated in the oxidation reactions can be used elsewhere in IGCC plant. In addition, there are also anticipated impurities issues with some alternative methods.

Those skilled in the art will appreciate that the example provided above and the example that follows are intended to be illustrative of the invention and are not to be construed as limiting. Those skilled in the art will also appreciate that the flow, compositions, temperature and pressure ranges as well as heating values and equipment given in the examples are likewise for purposes of illustration. Such examples and parameters could be altered in accordance with the present invention depending on process, equipment, economic considerations and the like. For example, one N 2 stream could be withdrawn from ASU 100 rather than streams 5 and 6 (as shown in FIG. 1 ). This one stream could then subsequently be divided into two streams or portions of N 2 (with appropriate compression as needed) for use as the N 2 sweep gas streams.

Co-Production of H 2 and Electrical Power in an IGCC Plant with CO 2 Capture

An exemplary arrangement of HTMs for co-production of H 2 (e.g., high-purity H 2 ) and electrical power in an IGCC plant with CO 2 capture in accordance with an alternative embodiment of the present invention is illustrated in FIG. 4 . As used in the present invention, “high-purity H 2 ” gas, it is meant H 2 gas that is at least 95% by volume H 2 . More preferably, such gas will be at least 99% by volume H 2 and most preferably, such gas will be greater than 99.9% by volume H 2 . The process flow diagram (PFD) only shows the portions for the HTMs of the IGCC plant. The processing and equipment upstream and downstream of the HTMs can be the same as described above and shown in FIG. 1 . The stream summary for this particular computer-simulated example is given in Table 2.

In this particular case and as shown in FIG. 4 , the H 2 -product HTM 136 , gas turbine fuel HTM 114 , and duct burner fuel HTM 126 are arranged in series. Clean, shifted syngas 23 (same as stream 23 in FIG. 1 and Table 1) is fed to the syngas side 138 of HTM-H 2 136 and H 2 53 is removed from the permeate side of HTM-H 2 136 . For high-purity H 2 production 53 , membrane 140 with high (near 100%) H 2 permeation selectivity (e.g. the dense, Pd-coated membrane described above) should be used in HTM-H 2 136 without N 2 sweep in order to avoid the need for permeate 53 purification. Those skilled in the art will appreciate that other HTMs such as those described hereinabove may be suitable for use in accordance with the present invention so long as the desired H 2 flux and selectivity are met. The ideal H 2 permeate 53 pressure is determined by minimizing product costs as a function of membrane capital and parasitic H 2 compression loads. The H 2 is cooled in heat exchanger 141 by raising steam or heating process gas or cooling water before it can be compressed in compressor 142 and sent to the pipeline 55 .

The retentate 57 from HTM-H 2 136 is fed sequentially to HTM-GT 114 and retentate 39 to HTM-DB 126 where the H 2 is recovered to make fuel 29 for the gas turbine combustor 124 and fuel 43 for the HRSG duct burner 132 in a similar fashion as described above. The coal 9 (not shown) flow rate for this exemplary IGCC plant with co-production of power and H 2 is the same as the coal 9 flow rate for the previous power-only IGCC plant. A smaller gas turbine 122 is used in this Example of the co-production plant design so that a significant quantity of the H 2 can be used to make pipeline product 55 instead of power. Therefore, the gas turbine fuel flow rate in 29 is 253.1 kpph and the gas turbine exhaust flow 31 (not shown) decreases from 3770 to 1696 kpph. The gasifier 104 , syngas processing 108 , and CO 2 purification 134 portions of the IGCC plant are the same size as in Example 1 and generate the same amount of saturated steam 17 that must be superheated in the HRSG 110 for expansion in the steam turbine 112 . Due to the decrease in mass flow in 31 , the amount of heat available in 110 is much lower and supplemental firing of the HRSG duct burner 132 is critical to maximizing plant performance by avoiding uneconomical steam 17 export or pressure let-down.

There are other options for providing for the duct firing fuel aside from the near-atmospheric pressure H 2 —N 2 fuel mixture described above. For instance, uncompressed H 2 product 53 could be burned instead of being sent to the pipeline, some of the syngas 23 could be throttled, or some of the high pressure H 2 —N 2 fuel mixture turbine fuel 29 could be throttled. The low-pressure H 2 —N 2 fuel mixture 43 made by HTM-DB 126 is the most efficient fuel because the maximum amount of energy from the coal 9 goes through the combined cycle and a high pressure fuel is not used where only low pressure is required. It also maximizes the extent of carbon capture possible and simplifies the CO 2 purification process 134 .

There are yet other alternative configurations for the IGCC plant that could be used in conjunction with the HRSG duct burner fuel made in 126 . For example, the clean, shifted syngas 23 could be cooled to 100° F. and the condensed water could be removed in a knock-out drum. Under these conditions, the H 2 content in dried stream 23 entering HTM-GT 114 feed increases and the H 2 partial pressure increases. In the power-only IGCC plant, this reduces membrane 116 area but also decreases the total high heating value (HHV) process efficiency. The cost of electricity produced is expected to decrease under these conditions because the sensitivity to membrane capital is higher than the sensitivity to process efficiency.

In the power-only example described above in Example 1, the recovery of H 2 from the syngas stream is 95% in HTM-GT 114 and 85% in HTM-DB 126 . These values could be adjusted to reduce the cost of electricity.

Integration of water gas shift (WGS) catalyst into the syngas side 118 of HTM-GT 114 is commonly suggested in the literature to increase CO conversion. Though this is an option, sensitivity analysis shows that this is not the best mode for practice because it increases the cost of IGCC products. The amount of membrane area required for H 2 separation is minimized if the syngas CO is converted in high temperature and medium temperature shift units in 108 before it is fed to the HTMs.

In yet another embodiment of the present invention in which an IGCC plant is designed to produce both H 2 and electricity, HTM 136 and HTM 114 could be arranged in parallel as shown in FIG. 5 . This is contrast to the embodiment of HTMs shown in FIG. 4 in which the HTMs are instead arranged in series. While the reference numerals in FIG. 5 correspond to those in FIG. 4 , the stream conditions in Table 2 do not correspond to FIG. 5 . Rather, stream conditions for FIG. 5 for this computer-simulated example are shown below in Table 3.

Simulation results indicate that the cost of H 2 product is almost equivalent if the HTMs are arranged in parallel or in series.

Other alternative configurations to consider for an IGCC plant where H 2 and electricity are both produced include: withdrawing permeate from HTM-H 2 136 at more than one pressure. The membrane area required for H 2 recovery increases with increasing permeate pressure because the driving force decreases between the syngas and permeate. However, H 2 product compression costs decrease with increasing permeate pressure. The cost of the H 2 product may be minimized by withdrawing portions of the total H 2 product at different pressure levels.

In addition, the use of pressurized superheated steam as a sweep gas in HTM-H 2 136 ( FIGS. 4 and 5 ) can be considered for an IGCC plant in which both H 2 and electricity are produced. Similar to the use of compressed ASU N 2 as a sweep stream for gas turbine fuel, the use of pressurized superheated steam as a sweep gas in 136 could reduce or eliminate H 2 compression costs and reduce membrane area by decreasing the H 2 partial pressure in the permeate. In such a case, superheated steam could be taken from the HRSG 110 and fed as a sweep gas to HTM-H 2 136 . The H 2 O/H 2 permeate is cooled, the condensed water is removed via a knock-out drum, and the H 2 is dried before it is sent to the pipeline. The condensed water is boiled and superheated in the HRSG or the IGCC process and recycled for use as HTM-H 2 sweep.

It may also be possible to use other diluents like superheated steam as permeate sweep gases in HTM-GT 114 or HTM-DB 126 , but it is unlikely that this would be the most efficient scenario. If the H 2 /H 2 O fuel that is produced in the membrane is combusted in the gas turbine 122 or the HRSG duct burner 132 , the latent heat of the steam exiting the stack of the HRSG 45 is not recovered.

Although the invention has been described in detail with reference to certain preferred embodiments, those skilled in the art will recognize that there are other embodiments for the processes and apparatus described hereinabove, and that such alternative processes and apparatus are within the spirit and the scope of the claims.