Projected emissions of hazardous air pollutants from a Shell coal gasification process-combined-cycle power plant

Projected emissions of hazardous air pollutants from a Shell coal gasification process-combined-cycle power plant Daniel

C. Baker

Shell Development (Received 18 May

Company, 3333 Highway 6 South, 1993; revised 17 November 1993)

Houston,

TX 77 082,

USA

An integral part of the development programme for the Shell coal gasification process (SCGP) has been the determination of hazardous air pollutants (HAPS) and other trace constituents in the process syngas. Numerous results at the Shell Coal Gasification Plant-l (SCGP-1) verify that very few HAPS or any other trace constituents are present in the syngas, and the concentrations of those few species present are extremely low. These results from direct measurements on the syngas are substantiated by analyses of other process streams and by inspection of syngas clean-up equipment and transport lines during decommissioning. The results are used to project emissions of HAPS and other trace constituents for a 500 MW SCGPcombined-cycle power plant. Not only would such a facility not be defined as a major source of HAPS, but in fact it might even establish a benchmark (based on low HAP emissions) for new coal-based power generation. (Keywords:coal; gasification; air pollution)

The 1990 Clean Air Act Amendments (CAAA) in the USA introduce 189 hazardous air pollutants (HAPS) to be regulated on a source-category basis, starting with major sources. Major sources are defined as facilities with emissions of > 25 short tons (- 23 tonnes) per year of total HAPS or > 10 short tons (- 9 tonnes) per year of any one of the HAPS. For one source category, namely electric power generation from fossil fuels, the CAAA specify that the issue of HAPS be studied by the EPA to determine whether regulation is warranted from the public health viewpoint. Against this regulatory backdrop, integrated coal gasification combined cycle (ICGCC) electric power generation has emerged as a very promising clean coal technology. To support the development of this technology, an extensive database on HAPS, as well as other trace constituents in general, has been developed for the Shell coal gasification process (SCGP), a high-pressure, oxygen-blown, dry-feed, entrained-bed, slagging gasification process which offers a number of environmental advantages over pulverized coal combustion, including low emissions of HAPsI. The database contains information obtained during the four-year operating life (1987-1991) of the Shell Coal Gasification Plant-l (SCGP-l), which processed a wide variety of feedstocks including bituminous coals, lignite and petroleum coke. Data on the levels of HAPS in the syngas during SCGP-1 operation on various feedstocks have been presented elsewhere’ and are summarized here. In addition to these data, the database also contains information on other streams (i.e. solids and water, for element balancing), from several gas clean-up slipstream studies, and from a systematic inspection of the plant, particularly the syngas clean-up section and 0016-2361,‘94/07,‘1082205 c 1994 Butterworth-Heinemann 1082

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transport lines, during decommissioning. An example of this information, specifically element distributions and balancing for the SCGP-1 design feedstock, Illinois No. 5 coal, is presented here for the first time, together with a discussion of the other results from the database which support the low HAP measurements in the syngas. EXPERIMENTAL The syngas characterization at SCGP-1 was part of a multimedia environmental programme initially conducted during a 1528 h demonstration run on the design feedstock, Illinois No. 5 coal, and repeated during periods of 150-300 h of continuous operation on other feedstocks’. Gas was sampled for elemental species by impinger trains (similar to EPA’s multi-metal train) connected to the gas streams of interest. Volatile metals were captured in an impinger train using a solution of hydrogen peroxide in nitric acid, followed by an impinger filled with potassium permanganate in sulfuric acid to ensure capture of mercury. A separate impinger train filled with sodium carbonate solution was used to capture halides, sulfide and selenide. Analyses were performed by atomic absorption spectrophotometry (a.a.s.), inductively coupled plasma mass spectrometry (ICP-ms.), or ion chromatography (i.c.), depending on the element of interest. For longer-term sampling of elemental species, a series of carbon beds was placed in the gas streams of interest, and the gas was processed to concentrate elements by three orders of magnitude. Analyses of virgin and syngas-exposed carbons were obtained by protoninduced X-ray emission spectroscopy (PIXE).

Shell coal gasification process:

Gas was sampled for semi-volatile organic species by similar impinger trains filled with methylene chloride and connected to the gas streams of interest. Analysis was performed by gas chromatography-mass spectrometry (g.c.-m.s.). Volatile organic species were sampled both through cartridges of Tenax, with thermal desorption into a g.c. equipped with a flame ionization detector (f.i.d.), and through cartridges of carbon, with extraction by carbon disulfide and analysis by g.c.-f.i.d.. Volatile organic species were also sampled into canisters and analysed by g.c.-m.s.. Low-molecular-weight hydrocarbons, sulfur species and nitrogen species were sampled into high-pressure cylinders and sub-sampled by high-pressure syringes followed by g.c.-f.i.d. analysis. Aldehydes were sampled by means of dinitrophenylhydrazine-coated absorbent-filled cartridges, followed by analysis by highperformance liquid chromatography (h.p.1.c.). For longer-term sampling of semi-volatile species, a series of carbon beds was placed in the gas stream of interest, and the gas was processed to concentrate absorbable material by about three orders of magnitude. The carbon was extracted with carbon disulfide, followed by analysis by g.c.-f.i.d.. During decommissioning, the location of any material deposits was recorded. Elemental analysis was then performed on any deposits by means of PIXE, as well as on cut-out sections from vessels and associated piping, and, where appropriate, samples of packing material, sorbents and recirculating solvents. RESULTS Figure 1 shows in simplified form, a potential block flow diagram for SCGP in a combined-cycle power generation application. The syngas clean-up sequence involves dry filtration of fly slag and secondary filtration of salts, catalytic removal of HCN and COS, water washing largely for ammonia removal, and multistage solvent contacting for acid gas removal. For the most part, these individual syngas clean-up steps were demonstrated at SCGP-1 (either on full stream or on a slipstream); otherwise they have been thoroughly investigated in the post-SCGP-1 period to ensure that a clean-up sequence can be designed so that the syngas is free of trace constituents and is well suited for fuelling a gas turbine. In addition, simulated SCGP syngas has been successfully test-fired in gas turbines to demonstrate its suitability. The experiences gained in the SCGP development programme, particularly from SCGP-1, confirm the overall effectiveness of the syngas clean-up sequence. For example, Table 1 shows the average elemental composition of the clean syngas during several SCGP-1 characterization programmes on bituminous coals of commercial interest. Essentially, no elemental matter is detected in the clean syngas.

Table 1 Average concentrations after clean-up”

Mg Ne P Si Ti

0.030 0.023 0.034 0.020 0.020 0.013 0.160 0.051 0.008

Ag As*

< 0.006 < 0.003

Al Ca Fe K

sag Figure

1

Shell CGCC

Flyslag

Salts

W&r

SUlfW

Hg* Mn*

(ppmw) of elements in SCGP-1

MO Ni* Pb* Sb* Se* Sn Sr Th Tl U V Zn

0.018 0.013 < 0.002
‘Elements asterisked are CAAA Title III HAPS; i detection limit indicated

syngas


signifies below the

The database also contains extensive elemental analyses of all inlet and outlet streams during steady operation on the design feedstock, Illinois No. 5 coal, the composition of which is given in Table 2. This information can be used to compute element recoveries. These element recoveries have been averaged over many data sets for the design feedstock and are presented in Table 3. This information has also been used for calculating element distributions for this feedstock based on post-SCGP-1 design modifications; these distributions are also shown in Table 3. The data confirm that after gasification most of the trace elements are in general tightly bound in the glassy matrix of the inert slag and fly slag - making these by-products suitable for utilization3 - and are not present in the water or the syngas. For the design feedstock, eleven of the elements shown in Table 3 have average recoveries of only 690%. Not surprisingly, these elements are all volatile during gasification. Consequently the low recoveries are believed to be real and to be evidence of retention of volatile elements within process equipment, particularly the clean-up train, and not of their emission. Besides the many direct syngas analyses showing that these elements are not emitted, there are four reasons substantiating volatile element retention rather than emission. First, qualitative information from inspection during SCGP- 1 decommissioning provided evidence of removal and retention of volatile elements on associated sorbent

Table 2

Average

composition

wt% db Ash C H N S 0 Al Ca Fe K Mg Na P Si Ti

of Illinois No. 5 coal ppmw

12.6 68.3 4.6 1.4 3.0 10.1

_,_-. Flue Gas

B Ba Be* Br Cd* cl* co* Cr* cu F*

D. C. Baker

0.869 0.893 1.289 0.018 0.083 0.060 0.181 3.021 0.056

Ag As B Ba Be Br Cd Cl co Cr CU F Hg Mn MO Ni

ppmw 0.13 5.70 126.7 45.17 1.54 2.50 0.24 568.7 2.10 9.40 12.78 98.33 0.14 109.9 4.72 13.95

Pb Sb Se Sn Sr Th Tl U V Zn

14.99 1.44 2.63 2.00 20.93 2.69 1.04 1.47 30.32 134.1

power plant block flow diagram

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Shell Table 3

coal gasification Typical

process:

element distribution

In slag”

D. C. Baker

(%) in SCGP

for Illinois No. 5 coal

In filter purges”

In water*

In sour gasc,d

In acid gas“

In synga&

_

Al

88

10

Ca

87

6

0.061

Fe

106

7


K

72

19

0.038

Mg Na

90

10

0.093

92

18

0.040

P

92

6

0.003

Si

85

13

0.003

Ti

99

11

0.002

Ag As

52

40

0.053

_

55

8

0.088

0.059

B

59

31

15.000

10.001 0.006

0.009

0.002 _

98 93

_

113

_

100

0.019

98

_

91

_
Recovery’,/

98

0.006

110

_

110

_

92

0.024

_

0.020

0.111

_

63 105

Ba

97

11

0.037

Be

43

52

0.032

Br

L

1114

O.Ollh

_

Cd

40

34

0.029

_

74

Cl

10

979

0.970*

_

108

_

100

108 95

co

90

10

0.003

Cr

107

12

0.004

0.007

CU

98

11

0.010

F

36

689

0.650*

0.011 _

Hg Mn

18

3

0.098

6

97

11

MO

_

113

119 109 105

_

27


_

108

111

12

0.018

_

123

Ni

62

22

0.003

_

84

Pb

33

47


Sb

29

11

0.020

Se

9

52

1.900

Sn

38

33

0.004

Sr

85

9

Th

50

Tl U

_

80 40

0.233

_

63

_

71


_

94

27

0.003

_

77

21

51

0.007

122

14

0.005

_

136

_

99

_

90

V

89

10

0.030

Zn

64

26

0.001

’ From measured recoveries and measured enrichment factors b From direct measurements ‘Sour gas from stripping of ammonia wash water d From direct measurements; only detected elements are shown eAverage of all Illinois No. 5 coal data on element recoveries f Low recoveries indicate retention in process equipment as explained g Adjusted from slipstream experience and engineering projections “Adjusted for secondary filtration of salts

and packing material during the syngas washing step. Specifically, this information came from precipitated deposits, including those associated with the washing step, which were analysed for all trace elements and found to be significantly enriched in mercury and five other elements representing the largest amounts of unrecovered mass: arsenic, lead, nickel, selenium and zinc. Enrichment of these volatile trace elements is shown in Figure 2. Removal and retention during the washing step of another five elements which represented lesser amounts of unrecovered mass (antimony, cadmium, thallium, thorium and tin) could not be confirmed by these analyses, but only inferred, owing to detection limits.

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_

72

_ 0.252

in text

t I0 fe i 1 ; 0

Figure

AEGION 1

2

REGlON 2 ,a3 kg&h .m q t4 OS.qam

Analyses of SCGP-1

deposits: regions ofelement

REGION 3

enrichment

Shell coal gasification

Second, deposit location also confirmed the effectiveness of the washing step for trace element removal. Only one deposit was observed in the acid gas removal stage, at the syngas inlet to the column; the remainder of the column was free of deposits, as was the line which transported the clean syngas to an adjacent power station. This finding indicates excellent volatile trace element removal upstream of the acid gas removal system. Third, analyses of the SCGP-1 acid gas solvent after several thousand hours of operation also confirmed that most of the trace elements were removed from the syngas before entry to the acid gas removal system. These analyses are presented in Table 4. A minor amount of material filtered (on-line) from the solvent was found to be FeS (most likely from scale erosion), and the filtrate was not noticeably enriched in any trace element. This again indicates excellent volatile trace element removal upstream. Fourth, syngas analyses upstream of the acid gas removal system also showed excellent trace element removal by that stage2. Besides elemental species, the SCGP-1 syngas has also been characterized for a wide range of organic species and low-molecular-weight nitrogen and sulfur species. The results show that very few if any such species are present in the syngas. For example, Table 5 shows the average molecular composition of clean syngas during the SCGP-1 characterization programmes on bituminous coals of commercial interest, including major species as well as those few trace C-, N- and S-containing species that were detected in the clean syngas. Very few organic species are present in the syngas because of the severe conditions achieved in pressurized, oxygen-blown, dry-feed, entrained-bed gasification. Heavy

Table 4 solvent

Average

concentrations

(ppmw)

Mg Na P Si Ti

0.026 1.041 3.715 3.413 0.112 5.440 0.380 0.337 0.010

B Ba Be Br Cd Cl

4s AS

0.009 0.051

Hg Mn

0.696 0.018 < 0.005 n.a. 0.016 165 0.020 0.540 0.063 35 < 0.004 0.667

Al Ca Fe K

co Cf CU F

of elements

in SCGP-1

MO Ni Pb Sb Se Sn Sr Th Tl U V Zn

0.027 < 0.008 0.034 0.03 1 1.295 0.009 n.a. <0.008 0.009 <0.008 0.016 0.303

Composition

of clean syngas

vol.% (dry, N,-free)

co

ppmw (dry) 67.1 31.9 1.0

H* CO, ppmw (dry) Formaldehyde Methyl mercaptan cos H,S CS, NH, HCN

from SCGP-1

0.108 0.657 87 1
Hydrocarbons Cl c2 c3 c4 c5 C6 c7 C8+

150
D. C. Baker

hydrocarbons, and organic compounds in general, do not survive, so virtually only C, molecules such as CO and CO, are detected in the syngas. In fact, besides methane, which appears in the syngas at ppmw levels, only low ppbw traces of other light hydrocarbons are present in the syngas, together with ppbw levels of two other C, molecules, namely formaldehyde and methyl mercaptan. No polycyclic organic material or phenolic material was detected in the syngas at the ppbw level; furthermore, none was ever detected in SCGP-1 wash water4. During gasification, most of the coal sulfur (i.e. N 80% for Illinois No. 5 coal) is liberated and converted to hydrogen sulfide and carbonyl sulfide in the syngas. Carbonyl sulfide is further hydrolysed to hydrogen sulfide during syngas clean-up. Depending on the design of the acid gas removal system, several parts per million of carbonyl sulfide, and possibly hydrogen sulfide, will be present in the clean syngas and ultimately converted to SO, in the gas turbine (Table 5). A small amount of reduced sulfur will also be converted to SO, in the SCOT thermal oxidizer in the sulfur recovery stage and emitted to the atmosphere. However, the projected level of SO, emitted from a Shell ICGCC plant (- 0.02 kg GJJ ’ coal input) is significantly lower than that emitted from pulverized coal combustioni. In the SCGP, because of its unique flame conditions, coal nitrogen is converted almost exclusively to molecular nitrogen within the gasifier. Typically < 1 wt% of the coal nitrogen remains in a reduced form, as roughly equivalent amounts of ammonia and hydrogen cyanide. Hydrogen cyanide is further hydrolysed to ammonia, while ammonia is removed by water washing during syngas clean-up. (Ammonia - in a sour gas stream generated from stripping the sour ammoniacal wash water - is further converted to molecular nitrogen in the Claus process, thereby completing the conversion of essentially all coal nitrogen to molecular nitrogen.) Thus no fuel-bound nitrogen has been detected in the clean syngas at the ppmw level (Table 5). Consequently, in the absence of any fuel-bound precursors, no prompt NO, is produced in the gas turbine combustor. In addition, test firing of simulated SCGP syngas in a gas turbine has even shown that only a small amount of thermal NO, is produced in the combustor’. Thus, the projected level of total NO, emitted from a Shell ICGCC plant ( -0.02 kg GJJ ’ coal input) is significantly lower than total NO, emitted from pulverized coal combustion, which has both higher thermal NO, and higher prompt NO, emissions’. PROJECTED

Table 5

process:

EMISSIONS

Results from the SCGP-1 syngas characterization have been used to project emissions of HAPS and other trace constituents for a 500 MW SCGPcombined-cycle power plant (Table 6). This information complements the projected emissions of SO, and NO, referred to above. The elemental matter in the clean syngas was assumed to contribute directly to emissions, while the combustible species were assumed to be destroyed with 99.9% combustion efficiency, with the remainder contributing to emissions. Furthermore, elements whose concentrations were below the detection limits were conservatively assumed to be present at the detection limit, even though equipment inspection and chemical analysis of clean syngas piping during decommissioning

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Shell coal gasification Table 6

Projected SCGP-combined-cycle

process: D. C. Baker

emissions of trace power plant

constituents

for a 500 MW

Emissions (t a-‘)

Pollutants Contribution from combined-cycle island HAPS (a) As, Be, Cd, Co, Cr, Hg, Mn, Ni, Pb, Se, HCl, HF (b) COS, HCN, CS, (c) Formaldehyde, listed hydrocarbons Non-HAPS (d) Al to Zn (e) H,S, NH, (f) Non-methane hydrocarbons, methyl mercaptan Contribution from SCOT thermal oxidizer HAPS (a) as above (b) as above (c) as above Non-HAPS (d) as above (e) as above (f) as above ‘Based on assumed na., not applicable

emissions

0.43 0.26 0.00032 1.3 0.0055 0.0023

n.a. < 1.3” na. n.a. < 0.7” n.a.

of 3 ppmv COS and 3 ppmv H,S

suggested that these elements may have been present at substantially below the detection limit. Emission of reduced sulfur from the SCOT thermal oxidizer was conservatively estimated, based on Shell Oil experience, assuming a maximum of 3 ppmv of COS and 3 ppmv of H,S (Table 6). In any event, these projected HAP emissions shown in Table 6 (co.8 and < 1.4 short tons per year respectively) are well below the regulatory thresholds defined in Title III of the 1990 CAAA for designation of a facility as a major source of HAPS, as quoted at the beginning of this paper. In fact, even with the stated conservative engineering assumptions, these low emissions of HAPS may well establish a benchmark for new coal-based power generation. CONCLUSIONS Extensive characterization programmes at SCGP-1 have clearly demonstrated the low levels of HAPS and other trace constituents in the syngas from this technology. In general, trace elements are tightly bound in the inert slag and fly slag, which makes these by-products suitable for utilization. In addition, this technology can provide for virtually complete volatile element capture and retention during syngas clean-up, as confirmed by analyses during operation and by inspection and analyses during

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decommissioning. Thus virtually no trace elemental matter is detected in the clean syngas. In fact, volatile element species are largely removed from the syngas even before acid gas removal. Because of the extreme gasification conditions achieved in the SCGP, essentially no carbon compounds except C, molecules such as CO and CO, survive in the syngas. Besides methane, present at the ppm level, only formaldehyde and methyl mercaptan are detected at the sub-ppm level, and a few light hydrocarbons at the low ppb level. No polycyclic organic or phenolic material is detectable at the ppb level. The exact ppm level of carbonyl sulfide in the clean syngas depends on the design of the acid gas removal system, while hydrogen sulfide removal is virtually complete. Typical carbonyl sulfide levels achieved in SCGP syngas would result in SO, emissions well below those for pulverized coal combustion when the syngas is burnt in a gas turbine. This is true even when the small amount of SO, emission from the SCOT thermal oxidizer is added. Essentially all coal nitrogen is converted to molecular nitrogen in the SCGP. No fuel-bound nitrogen is detectable in the clean syngas at the ppm level. Thus no prompt NO, will result from combustion of the syngas in a gas turbine. In addition, test firing of simulated SCGP syngas in a gas turbine has even shown that only a small amount of thermal NO, is produced, so total NO, emissions are well below those for pulverized coal combustion. Projected HAP emissions for a 500 MW SCGPcombined-cycle power plant, based on the results presented here, show that such a facility would not be defined as a major source. In fact, even with conservative engineering assumptions, this technology may well establish a benchmark (based on low emissions of HAPS) for new coal-based power generation. REFERENCES Davis, R. J. and Salzman, D. R. Paper to 85th Annual Meeting, Air & Waste Management Association, Kansas City, MO, 21-26 June 1992 Baker, D. C., Bush, W. V. and Loss, K. R. Paper to EPRI Conference, ‘Managing Hazardous Air Pollutants: State of the Art’, Washington, DC,4-6 November 1991 Salter, J. A., Gantz, S. H., Tang, W. T., Tijm, P. J. A., DuBois, J. B. and Perry, R. T. Paper to 9th Annual Ash Utilization Symposium, Coal Ash Association, Orlando, FL, 22-25 January 1991 Baker, D. C., Bush, W. V., Loss, K. R., Potter, M. W., Swatloski, R. A. and Russell, P. F. Paper to Sixth Annual Pittsburgh Coal Conference, l&14 September 1989 Allen, R. P., Battista, R. A. and Ekstrom T. E. Paper to 9th Annual EPRI Conference on Gasification Power Plants, Palo Alto, CA, 1619 October 1990