Hydrogen derived from ammonia: Small-scale costs

0360-3199/84 $3.0(I ~ II.(t0 Pergamon Press Ltd. International Association for Hydrogen Energy.

Int. J. Hydrogen Energy, Vol. 9, No. 9, pp. 759-766~ 1984. Printed in Great Britain.

H Y D R O G E N D E R I V E D FROM AMMONIA: SMALL-SCALE COSTS G.

STRICKLAND

Department of Energy and Environment, Brookhaven National Laboratory, Upton, NY 11973, U.S.A

(Received 20 January 1984) Abstraet--A systems study was made to assess the economic prospects for using purchased industrial ammonia as a hydrogen distribution and storage medium for users requiring 0.93-9.34 million stdm 3 y-~ of hydrogen (33-330 million std ft3y 1). Projected costs to the end user were determined for: the product of dissociated ammonia (N2+H~)/NH3, and the 99.999% pure tf2 obtained by separation of the nitrogen (H2/NH3); hydrogen produced by the steam reforming of natural gas (Hz/NG); electrolytic hydrogen (EHz); purchased (merchant) liquid hydrogen (LH/); OTEC (ocean thermal energy conversion) LH2; as well as OTEC NH3 and the H2 products derived from it. Future costs are projected as $ GJ -l and as 5 MBTU -I (19805 in 1990) using two sets of forecast energy prices. The results show that merchant LHz was substantially higher in cost than the other options, and that until EH2 is available at the projected costs, H2/NH3 would be the preferred option for the smallest plant sizes where it is projected to be competitive with Hz/NG of comparable purity. Thus, via state-of-the-art technology, industrial NH3 can now serve as a viable H2 carrier for some small-scale users. The availability of OTEC NH3 at the projected costs would substantially increase the competitive position of Hz/NH3. Consideration of safety and environmental factors are among the important items listed in recommendations for future work.

INTRODUCTION Hydrogen derived from anhydrous liquid NH3, via a dissociator and H2 purifier, offers an alternative to conventional methods of obtaining pure H2 for small-scale use. In the absence of a H2 pipeline network, smallscale users purchase merchant H2 as compressed gas in steel cylinders, or as liquid H2 (LH2) in cryogenic containers. The convenience, reliability, and service provided increase the cost of delivered H2. Alternatively, several on-site methods of producing H2 can be considered: (a) H2 via steam reforming of natural gas (H2/NG), as used for large-scale production; (b) electrolytic H2 (EH2) via water electrolysis, now under expanding development in the United States and elsewhere; (c) H2 via NH3 dissociation (N2+H2)/NH3, as now used for controlled atmospheres in metals processing; and (d) H2 via NH3 dissociation and purification (HjNH3), as considered here. Each of the on-site methods of producing pure Ha is expected to have a minimum delivery pressure of 2.1%2.51 MPa (300-350 psig). Although H2/NG is produced at minimum cost at a plant size of 2.83 million normal m 3 d -1 (2.83 MNm 3 d-l) *, or 100 million std ft 3 d-1(100 MSCFD)*, a market study by Fein, Mathey and Arnstein [1] has shown that at production levels below about 2.83 MNm 3 y-l(100 MSCFY) EH2 is projected to become lower in cost. In a similar study by Corneil, Heinzelmann and Nicholson [2], the cross-over point was given as 4.67 MNm 3 y-1(165 MSCFY). The economic prospects for using NH3 as a H2 carrier were recently assessed by Strickland [3] in a study on

* The normal m3 (Nm3) and the std ft3 (SCF) are referred to I a~m. 60°F (15.6°C). 759

NH3 made from sea water and air via an ocean thermal energy conversion (OTEC) process. Details of the OTEC concept and the cost projections for OTEC NH3 (and other energy carriers) have been reported by Avery and Dugger [4]. Because the results of the prior study by Strickland [3] indicated that H2 derived from OTEC NH3 might be comparable in cost with EH2, the current study was made to assess the economic prospects for industrial NH3. Hydrogen cost projections for the various options mentioned above (excluding compressed gas) were made for plant sizes of 0.93, 1.42, 2.83, 5.66, and 9.34MNm 3 y-1 (33, 50, 100, 200, and 330 MSCFY, 0.1-1.0 MSCFD) at a plant capacity factor of 0.9. or 330 days of operation per year. Also included for comparison are the cost projections made for H2 derived from OTEC NH3 and for OTEC LH2. All of the projections are costed as 19805 in 1990 because OTEC plantships and advanced technology electrolyzers could be commercialized by then. Ammonia is an attractive medium for distributing and storing H2 because it contains 17.8 wt-% H2, and because it contains 50% more H2 per cubic foot (at 21°C) than LH2. In addition, there is a large-scale infrastructure for NH3 production and distribution, providing economy of scale. The main barrier to extensive use of NH3 as a H2 carrier is its toxic nature. In present applications proper design and handling minimize the risks. Research and development needs on NH3 safety and environmental control are identified in a comprehensive study on liquefied gaseous fuels safety by Bomelburg and McNaughton [5]. Additional information on the use of NH3 as a H2 carrier is available in the prior study [3] and in an extended version of the current study [6]. Bomelburg [7] has published a study on uses of NH3 in energy-related applications.

760

G. STRICKLAND

E N E R G Y PRICES A N D BASIC P R O D U C T COSTS The production of H2 is an energy-intensive process; so the cost of HE is sensitive to the prices of natural gas and electricity consumed in producing it. In determining the cost of H2, expressed as 19805 in 1990, two levels of future energy prices were used in this study. As in the prior study [3] on OTEC NH3, the lower set of prices was forecast by the Department of Energy [8] in the 1980 Annual Report to Congress. A new and significantly higher set of energy prices was forecast by the National Center for the Analysis of Energy Systems at BNL (BNL set of prices). In this set the price of industrial natural gas was assumed to reach parity with the price of residual fuel oil [9]; and the price of industrial electricity was adjusted to the fractional amount made from coal using, utility coal prices [10]. The tentative price of coal was linked directly to world oil prices [ll]. Both sets of prices are listed in Table 1. It is evident that the range of A R C prices is modest; whereas the range of BNL prices is substantial, due to the uncertainty of future world oil prices. In determining the small-scale production costs of H : / N G and EH2, and the large-scale production cost of NH3, the cost analyses made by Chem Systems were used. These analyses were made as part of the study by Corneil, Heinzelmann and Nicholson [2] on production economics for H2, NH3 and methanol; and they had also been used as the basis for the H2/NG and EH2 costs developed by Fein, Mathey and Arnstein [1]. Modification of the basic product costs in 1990 was made by simply replacing the 1980 energy prices with the 1990 prices (as 19805) in the cost analysis done by Chem Systems. The costs of other items were not adjusted because they were assumed to change at the same rate as general goods and services. The H: costs are based on the higher heating value of H2, 141MJ kg -1 (61,100 BTU lb-1). In the following text the use o f 'forecast' and 'projected', as descriptive price and cost terms, will be minimized in order to avoid repetition. Table 1. Forecasts of U.S. average energy prices $ GJ -~ ($ MBTU -~) 19805 in 1990 Energy form

ARC price*

BNL price

Natural gas

4.63-5.28 (4.88-5.57) 12.71-13.32 (13.41-14.05) 4.58-4.80t

5.82-8.73 (6.14-9.21) 12.86--17.78 (13.57-18.76) 5.25-6.40t

1.60-1.62 (1.69-1.71) 2.64-2.76 (2.78-2.91)

2.25-3.42 (2.37-3.61) Not available

Electricity Coal: at mine delivered

* Prices published as 19795 MBTU 1 in 1990 were adjusted to 19805 in 1990 using a 9% inflation factor derived from data provided by Council of Economic Advisors [12]. t Values are in ¢ kWh -1.

COSTS OF A M M O N I A - B A S E D H Y D R O G E N This section discusses the cost of NH3 made from natural gas, or coal, or an OTEC process, and distributed to the end user. The processing costs are those related to NH3 storage and dissociation, as well as to compression and purification. Additional details on the costing are provided in the extended report by Strickland [6].

Cost of ammonia The cost analysis made by Chem Systems, Inc. was for a plant located on the Gulf of Mexico and having a daily capacity of 1814 metric tons (mt), or 2000 short tons (st) (a 2000 lb ton). Natural gas was specified as the feed and fuel in the amount of 36.6 GJ/mt-l(35 MBTU st -1) of NH3. The calculated NH3 production costs for A R C and BNL energy prices are listed in Table 2A (2000 st of NHa daily production). They range from $297-306 mt -1 ($270-278 st -1) and $344--459 mt -1 ($312--416 st-l), respectively. Thus under BNL pricing NH3 production costs can be up to 50% higher than under A R C pricing. Added to the production costs are distribution charges for NH3 used near the production plant, and shipping and distribution charges for NH3 shipped 1600 km (1000 miles) inland. These charges increase the NH3 cost by 20--40%. The costs of delivered NH3 are also listed in Table 2A; and the costs of OTEC NH3 are included in Table 2B for comparision. Not included in the above costs of industrial NH3 is the difference between the selling (market) price and the production cost. The mark-up varies with foreign competition and demand, and can be up to 20% of the production cost. Since NH3 made from coal may become the preferred feedstock according to Buividas [13], a cost projection was made using the analysis done by Chem Systems for a 'new' coal gasification process. The results showed that only NH3 made adjacent to the mine would be competitive with NH~ made from natural gas.

Hydrogen processing costs The processing costs of N2+HJNH3 consists of the capital costs for NH3 storage and dissociation, operating and maintenance costs, electrical energy costs for heating the dissociator, plus an allowance to replace the catalyst every two years. The total processing costs are listed in Table 3A; and they are $6.2-2.8 GJ -~ ($6.53.0 MBTU-1), for A R C energy prices, depending upon the plant size. For BNL pricing the values are $7.13.0 GJ -1 ($7.5-3.2 MBTU-1). These costs are moderately sensitive to plant size. The processing costs for H2/NH3 are comprised of the above costs---those for compressing the dissociator product from about 2 arm (abs) to 25 atm, plus the costs for removal of the NE to provide H2 of 99.999% purity. A more realistic estimate was made of the compression costs by calculating the power requirements, for a

761

HYDROGEN DERIVED FROM AMMONIA Table 2. Energy price set

Production cost at plant

Distributed cost near coast

Distributed cost inland

(A) Costs of industrial ammonia, 19805 in 1990" $ mt -~ 297-306 357-367 $ st -~ 270-278 324-334 $ GJ 1 11,8-12.1 14,1-14.6 $ MBTU 1 12.4-12.8 14.9-15.4

400-411 363-373 15,8--16.3 16,7-17.2

BNL

$ $ $ $

475-616 433-558 19.0-24.4 20.(1-25.7

ARC

$ mt -1 $ st -~ $ GJ -1 $ MBTU -1

BNL

$ $ $ $

ARC

mt ~ st -1 GJ -1 MBTU -1

344-459 312-416 13.6-18.2 14.4-19.2

413-551 376-499 16.4-21.8 17.3-23.0

(B) Costs of OTEC ammonia, 19805 in 1990" 229-298 275-357 208-270 249-324 9.1-11.8 10.9-14.1 9.6-12.5 11.5-14.9

mt 1 st -1 GJ -1 MBTU -1

229-298 208-270 9.1-11.8 9.6-12.5

318--413 288-375 12,6-16.4 13.3-17.3

275-357 249-324 10.9-14.1 11.5-14.9

340-442 308--400 13.5-17.5 14.2-18.5

* mt = metric ton (1000 kg) or 2205 lb, st = short ton or 2000 lb. multi-stage centrifugal compressor, using a standard relation [14]. T h e compressor costs were obtained by averaging two i n d e p e n d e n t values obtained from cost plots of brake h o r s e p o w e r [15, 16]. The costs were then updated, and 10% was added for features essential to H2 service. As a result the revised compression costs were substantially higher. The Polybed Pressure Swing Adsorption (PSA) system was selected for separation of the N2 because the desired H2 purity could be obtained. A n estimate of 75% H2 recovery was obtained from U n i o n Carbide [17], and a fuel credit of $3.8 G J -t ($4.0 M B T U -1) was assigned to the u n r e c o v e r e d H2 (net credit is $0.95 GJ -1 or $ 1 , 0 M B T U - I ) . O t h e r details are pro-

vided in the extended report [6]. Processing costs for H2/NH3 are listed in Table 3B; they are $14.75 . 1 G J -1 ( $ 1 5 . 5 - 5 . 4 M B T U -1) for A R C pricing, and $16.0-5.5 G J -1 ($16.9-5.8 M B T U -l) for B N L pricing. It is evident that these processing costs are even m o r e sensitive to plant size.

Total costs" of hydrogen The total costs of N2+H2//NH3 and H2/NH3 are comprised of the industrial NH3 production costs at the Gulf of Mexico, distribution charges for shipment near the Gulf Coast, or distribution and delivery charges for shipment 1600kin (1000miles) inland, plus the pro-

Table 3. Plant sizes* (MNm 3 y-~ MSCFY) ARC prices:

0.93 33

1.42 50

2.83 100

5.66 200

(A) Processing costs for N2+H2/NH3 $ GJ 1 (5 MBTU -;) 19805 in 1990) 6.0-6.2 5.2-5.3 4.0-4.1 3.3-3.4 (6.4-6.5) (5.7-5.6) (4.2-4.3) (3.4-3.5)

BNL prices:

6.4-7.1 (6.8-7.5)

ARC prices:

14.6-14.7 (15.4-15.5)

BNL prices:

15.1-16.0 (15.9-16.9)

5.5-6.1 (5.8-6.5)

9.34 330 2.8-2.9 (3.0-3.0)

4.2-4.7 (4.5-4.9)

3.5-3.9 (3.7-4.1)

3.(t-3.3 (3.2-3.5)

(B) Processing costs for H2/NH3 11.9-12.0 8.5-8.7 (12.5-12.7) (9.0-9.1)

6.4-6.5 (6.8-6.91

5.1-5.2 (5.4-5.5)

6.8-7.4 (7.2-7.8)

5.5-6,1 (5,8-6.4)

12.4-13.2 (13.1-13.9)

8,9-9.6 (9.4-10.2)

* The normal m 3 (Nm 3) and the std ft3 (SCF) are referred to 1 atm and 60°F (15.6°C).

G. STRICKLAND

762

cessing costs for each product. The total costs of NH3-based H2 for A R C and BNL energy prices, at the coast and inland, are listed in Tables 4 and 5, and, except for costs at the coast, they are plotted in Figs 1 and 2 for ease in comparison. For A R C and BNL pricing, the costs of N2+H~/NH3 are $23-19GJ -1 ($25-20 MBTU -~) and $32-22 GJ -1 ($33--23 MBTU-1), respectively. The corresponding costs for H2/NH3 are $32-21 GJ -1 ($34-22 M B T U -1) and $40-24 GJ -~ ($4326 MBTU-1). The costs of equivalent OTEC products are only tabulated (see Tables 4 and 5).

COSTS O F O T H E R H Y D R O G E N The products considered here for comparison with NH3-based H2 are: Hz/NG, EH2 and LH2 (merchant and OTEC). Both EH2 and OTEC LH2 are more speculative in cost because the technology is still in an early stage of development.

Cost of hydrogen made from natural gas The cost of H2 made in small on-site reformers was determined from three plant sizes analyzed by Chem Systems: 0.93, 4.48 and 22.4MNm3y -~ (33, 158 and 792 MSCFY). After substituting both sets of prices for natural gas and electricity, the Hz/NG costs were plotted in order to obtain the costs for the five desired plant sizes. Costs to the end user are listed in Tables 4 and 5 and are plotted in Figs 1 and 2, respectively. The values are $37-14 GJ -~ ($39-15MBTU -~) for A R C pricing, and $42-16 GJ -~ ($45-17 MBTU -~) for BNL pricing. It is clear that the price of H2/NG is quite sensitive to plant size. Increasing the H2 purity from 98% to >99.999% would increase the cost of H J N G by up to 15% for the smallest plant size, and by up to 10% for the largest plant size. A compressor would not be needed.

Cost of electrolytic hydrogen The advanced technology electrolyzer on which the

Table 4. Projected costs of hydrogen based on ARC energy prices $ GJ -1 ($/MBTU) 19805 in 1990 Plant sizes:

MNm 3 y 1 MSCFY

N2+Hz/NH3

Coastal

2.83 100

5.66 200

9.34 330

Land-based products 20.2-21.5 19.3-20.7 (21.3-22.7) (20.4-21.8) 21.9-23.2 21.0-22.4 (23.1-24.5) (22.2-23.6)

18.1-19.4 (19.1-20.5) 19.8-21.1 (20.9-22.3)

17.2-18.7 (18.4-19.7) 19.1-20.4 (20.2-21.5)

17.0-18.2 (17.9-19.2) 18.7-19.9 (19.7-21.0)

28.7-30.0 (30.3-31.7) 30.4-31.8 (32.1-33.5)

26.1-27.4 (27.5-28.9) 27.8-29.1 (29.3-30.7)

22.7-24.0 (23.9-25.3) 24.4-25.7 (25.7-27.1)

20.6-21.9 (21.7-23.1) 22.3-23.6 (23.5-24.9)

19.2-20.6 (20.3-21.7) 20.9-22.3 (22.1-23.5)

HE/NG

35.5--36.6 (37.5-38.6)

26.7-27.7 (28.2-29.2)

20.1-21.1 (21.2-22.3)

16.1-17.3 (17.0-18.2)

13.9-15.1 (14.7-15.9)

EH2

23.7-24.5 (25.0-25.8)

22.4-23.2 (23.6-24.5)

21.0-21.7 (22.2-22.9)

20.1-20.9 (21.2-22.0)

19.7-20.4 (20.8-21.5)

LH2

47.7-48.6 (50.3-51.3)

44.8--46.1 (47.3-48.6)

42.3-43.5 (44.6-45.9)

39.1-40.4 (41.3-42.6)

37.5-38.7 (39.6--40.8)

OTEC-based products 17.0-20.3 16.1--23.7 14.7-18.2 (17.9-21,4) (17.0-25.0) (15.5-19.2) 18.7-22.6 17.8--21.7 16.6-20.5 (19.7-23.8) (18.8-22.9) (17.5-21.6)

14.1-17.4 (14.9-18.4) 15.9-19.7 (16.8-20.8)

13.7-17.0 (14.5-17.9) 15.5-19.2 (16.3-20.3)

25.5--28.8 (26.9-30.4) 27.2-31.1 (28.7-32.8)

22.7-26.2 (24.0-27.6) 24.5--28.4 (25.8-30.0)

19.4-22.7 (20.5-24.0) 21.1-25.0 (22.3-26.4)

17.3-20.7 (18.3-21.8) 19.1-22.9 (20.1-24.2)

16.0-19.3 (16.9-20.4) 17.7-21.6 (18.7-22.8)

23.1-27.7 (24.4-29.2) 26.4-31.8 (27.8-33.6)

20.5-25.0 (21.6-26.4) 23.7-29.2 (25.0-30.8)

18.0-22.6 (19.0-23.8) 21.2-26.7 (22.4-28.2)

16.7-21.2 (17.6--22.4) 19.9-25.4 (21.0-26.8)

16.4-20.9 (17.3-22.1) 19.6-25.1 (20.7-26.5)

Inland H2/NH3

Coastal Inland

Nz+HE/NH3

Coastal Inland

Hz/NH3

Coastal Inland

LH2

Coastal Inland

0.93 33

1.42 50

763

HYDROGEN DERIVED FROM AMMONIA Table 5. Projected costs of hydrogen based on BNL energy prices $ GJ -~ ($/]VIBTU-1) 19805 in 1990 5.66 200

9.34 330

Land-based products 22.7-28.9 21.9-28.0 20.6--26.5 (24.0-30.5) (23.1-29.5) (21.7-28.0) 25.3-31.5 24.4-30.5 23.1-29.1 (26.7-33.2) (25.7-32.2) (24.4-30.7)

19.8-25.7 (20.9-27.11 22.5-28.2 (23.7-29.8)

19.3-25.1 (20.4-26.5) 21.9-27.7 (23.1-29.21

31.4-37.8 (33.2-39.9) 34.0-40.4 (35.9--42.6)

28.7-35.0 (30.3-36.9) 31.3-37.5 (33.0-39.6)

25.3-31.5 (26.7-33.2) 27.9-34.0 (29.4-35.9)

23.1-29.3 (24.4-30.9) 25.7-31.8 (27.1-33.6)

21.8-27.9 (23.0-29.41 24.4-30.4 (25.7-32.11

H2/NG

37.4-42.2 (39.5-44.5)

29.8-34.5 (31.4-36.4)

22.4-26.9 (23.6-28.4)

18.0-22.7 (19.0-23.9)

15.9-20.6 (168--21.7)

EH2

26.1-30.1 (27.5-31.8)

24.8--29.0 (26.2-30.6)

23.4-27.6 (24.7-29.11

22.5-26.6 (23.7-28.11

22.1-26.2 (23..3--27.6)

LH2

51.7-57.1 (54.5-60.2)

48.9-54.4 (51.6-57.4)

46.4-518 (48.9-54.6)

43.1-48.5 (45.5-51.2)

41.4-46.9 [43.7-49.5)

14.4-18.0 (15.2-19.0) 17.0-21.4 (17.9-22.61

13.9-17.4 (14.7-18.4) 16.5-20.9 (17.4-22.0)

17.7-21.5 (18.7-22.71 20.3-24.9 (21.4-26.3)

16.4-20.2 ( 17.3-21.3) 19.0-23.6 (20.0-24.9)

16.8-21.3 (17.7-22.5) 21.5-27.7 (22.7-29.2)

16.4-20.9 (17.3-22.11 21.1-27.3 (22.3-28.8)

Plant sizes: N: + H2/NH3

(MNm3 y-1 MSCFY) Coastal Inland

HjNH3

Coastal Inland

N2 + HJNH3

Coastal Inland

H2/NH3

Coastal Inland

LH2

Coastal Inland

0.93 33

1.42 50

2.83 100

OTEC-based products 17.3-21.2 16.4-20.3 15.2-18.8 (18.3-22.4) (17.3-21.4) (16.0-19.8) 19.9-24.6 19.0-23.7 17.7-22.2 (21.0-26.0) (20.0-25.0) (18.7-23.4) 26.0-30.1 23.3-27.3 19.8-23.8 (27.4-31.8) (24.6-28.8) (20.9-25.1) 28.5-33.6 25.9-30.7 22.4-27.2 (30.1-35,4) (27.3-32.4 (23.6--28.7) 23.4-28.0 20.7-25.2 18.1-22.7 (24.7-29.5) (21.8-26.6 (19.1-23.9) 28.2-34.3 25.4-31.6 22.8-29.0 (29,7-36.2) (26.8-33.3 (24.1-30.6)

EH2 costs were based is being developed by the General Electric Company. It is commonly called the SPE electrolyzer because the electrolyte is a solid polymer rather than a liquid as in conventional (alkaline) electrolyzers, No credit was allowed for the by-product 02. Catalytic conversion to H20 of the trace amounts of 02 in the H2, and subsequent drying, are used to increase the H2 purity to 99.999%. The method of computing production costs for EH2 was the same as that used for natural gas. Costs for the small-scale on-site production of EH2 are listed in Tables 4 and 5 and plotted in Figs 1 and 2. The values for A R C and BNL prices are $25--20 GJ -I ($26--21 MBTU -1) and $30--22 GJ -x ($32-23 MBTU-a), respectively. Thus EH2 costs are much less sensitive to plant size than Hz/NG is.

100 MSCFY), and $0.32 Nm -3 ($0.90 100 SCF -1) for 9,34 MNm 3 y-~ or 330 MSCFY [19]. These prices were adjusted to 19805 in 1990 using the average 1980 prices for natural gas and electricity from the Department of Energy [20], taking into account the relative amounts of natural gas and electricity used [21]. Higher delivery charges under BNL pricing, a 10% transfer loss, and higher operating costs are included. Total costs to the end user are listed in Tables 4 and 5, and plotted in Figs 1 and 2. For A R C energy prices the merchant LH2 costs are $49-38 GJ -~ ($51-40 MBTU-1), and for BNL energy prices the costs are $57-41 GJ -1 ($60--44 MBTU-I). The costs of OTEC LH2 were similarly updated and are listed in Tables 4 and 5. For inland delivery, the cost of OTEC LH2 became $32-20 GJ -I ($34--21 MBTU -1) and $34-21 GJ -I ($36--22 MBTU -1) for A R C and BNL energy prices, respectively.

Cost of liquid hydrogen The costs of merchant LH2 are based on delivery to the end user, and on rental of an on-site storage system with a vaporizer, and with a liquid-pump for attaining the nominal pressure of 2.51MPa or 350psig [18]. Estimates obtained for the delivered price were $0.35 Nm -3 ($1.00 100 SCF -~) for 0.28-2.83 MNm 3 y-~ (10-

DISCUSSION O F H Y D R O G E N COSTS Figures 1 and 2 clearly show that merchant LH2 is much higher in cost than any of the options assessed for small-scale users. Its higher cost is mainly attributed to the service rendered. Lowest in cost over most of the range of plant sizes considered is H~./NG. Increasing

G. STRICKLAND

764

MNma/y

PLANT SIZE, I

2

3

4

5

6

7

8

ii

I

I

1

T

I

t

1

0934

I0 I

9

i i 934

60

60 55 55 50

~

5O _m

.c_

~

45

45 LH2

o

40

I-.-

~

40

o

35

0

g

rio

55 ~

d, I '~

7

o~ .E

O ¢j

PLANT CAPACITY FACTOR = 0.9

Z u,l

30 ~0

30

>"i"

1-

~,

H2/NH 32/NH3 INLAND

25

25 .......

"'-~t.~,~:~.~

:.. . . . . . . 20

zO INLAND

. . . . . . [~ . . . . . . . .

H,ING_~¢"......." . . . . . . . . . . . . . . . 15

E

0

3350

E

I

I00

15

I

l

I

I

150

200

250

300

t

I

330550

PLANT SIZE, MSCFY

Fig. l. Projected costs of hydrogen using ARC prices for natural gas and electricity.

its purity to 99.999% would reduce its competitive position by 10-15%, depending upon the plant size. For ARC energy prices, H2/NH3 is always higher in cost than EH2, but for BNL energy prices it may be competitive. Since the projected costs for N2 + H2/NH3 and HjNH3 are production costs rather than selling prices, their values should be up to 20% higher--thereby reducing their competitive position. At the smallest plant sizes, H2/NH3 would be competitive with HE/NG. In the case of N2 + H2//NH3, it is near the cost of EH2 for both sets of energy prices. The comparable OTEC products are lower in cost, especially OTEC LH2. RECOMMENDATIONS FOR F U T U R E WORK The factors listed below should be examined with the goal of lowering the costs of N2 + H2/NH3 and Hz/NH3 and obtaining more complete costs. • Low-cost purification

• • • • • •

H2 purity vs cost Dissociation by other methods Expansion of the infrastructure Shipping and distribution costs Safety and handling Environmental regulations

The additional development needs for the use of NH3 in fuel applications are listed below. Safety and environmental factors are more critical for vehicular use because of contact and increased vulnerability. • • • • • • • •

Safety and handling Environmental regulations Dissociator size reduction Low-temperature dissociation Fundamental combustion studies Reduction of NOx in exhaust gas Use of N2 + H2pNH3 in fuel cells Direct use of NH3 in fuel cells

765

HYDROGEN DERIVED FROM AMMONIA P L A N T SIZE, MNm3/y

0.934

I

2

3

4

5

6

7

8

9

ii

I

l

I

1

I

]

I

II

I0

9.54

T

--

60

60

55 55

50 s

5O

o

m I-(13

----_L

45

5O~ m

._. O (z)

4O __

~

4O

p" (.9 55 z b.l (.9 0 nr" (:3 >]2

45

MERCHANT /Hz

.c_

"-%,.. " ~

30

I , ~ I I 7 ~ "

35 if} O (.3 Z

....

', 25

PACITY FACTOR = 0 9

".. .

3o

H~/NH 3 INLAND ~

. . . . . . . . I" " " -".

/_

FNH~INLAND ¢.

~

. . . . . . . . . .

-~, . . . . . . _3c--_._____

~

O rr a I

25

~

:L~--TL i L 20

2O

Hz/NG

- . .

15

15 0

3

15 ; 5

i

100

I

150

I

200

PLANT SIZE,

I _

250

I

300

~

350

5

150

MSCFY

Fig. 2. Projected costs of hydrogen using BNL prices for natural gas and electricity.

CONCLUSIONS Consideration of anhydrous liquid NH3 as a compact H2 carrier is still in an early stage of evolution. Ammonia is an acceptable chemical commodity now made almost entirely from natural gas. It is also a H2 distribution and storage medium that can readily be made from water and air using renewable-resource energy or nuclear energy. Because NH3 can be readily dissociated to provide H2, it has potential as a future alternate fuel. And the fact that it does not contain carbon has both supply and end-use advantages. The results of the current study show that H2/NH3, H j N G and EH2 are projected to be substantially lower in cost than merchant LH2 for all of the plant sizes considered. However, for LH2 there is a minimum service responsibility; and it is the most suitable option for intermittent service. Although EH2 is projected to be lower in cost than Hz/NH3 for ARC energy prices, H2/NH3 may be competitive with EH2 for BNL energy

prices in the larger plant sizes. Until EH2 is available at the projected costs, H2/NH3 made via state-of-theart technology, would be the preferred option for the smallest plant sizes where it is projected to be competitive with Hz/NG of comparable purity. Thus, in the near term, NH3 can be viable H2 carrier for small-scale users requiring up to about 1.1 MNm 3 y 1 (40 MSCFY) of 99.999% H2. Like EH2, H2 based on an OTEC process offers the promise of low-cost; but in the interim, H2 derived from industrial NH3 is worthy of consideration as an alternate to merchant LH2, and to H2/NG for the smaller plant sizes.

Acknowledgement--The author is grateful to A. Mezzina and F. J. Salzano for guidance and support during the course of the study. Appreciation is expressed to the inviduals and organizations who supplied essential information for the study. The author thanks B. Ivero and E. M. Citrolo for preparing the manuscript and R. J. Tulipano for drawing the graphs.

G. STRICKLAND

766 REFERENCES

1. E. Fein, C. J. Mathey and C. Arnstein, The Market Potentialfor Electrolytic Hydrogen. Prepared for Electric Power Research Institute by The Futures Group, Glastonbury, Connecticut, U.S.A. Report No. EPRI EM-1154, Project 1086-4 (1979). 2. H. G. Corneil, F. J. Heinzelmann and E. W. S. Nicholson, Production Economics for Hydrogen, Ammonia and Methanol During the 1980-2000 Period. Exxon Research and Engineering for Brookhaven National Laboratory, Upton, New York, U.S.A. BNL 50663 (1977). 3. G. Strickland, Small-scale uses and costs of hydrogen derived from OTEC ammonia. Proc. 16th 1ECEC Conf., pp. 1459-1467. Atlanta, Georgia, U.S.A. August (1981). 4. W. H. Avery and G. L. Dugger, Contribution of ocean thermal energy conversion to world energy needs. Int. J. Ambient Energy 1, No. 3 (1980). 5. H. J. Bomelburg and D. J. McNaughton, Ammonia as a fuel. Report X in Liquefied Gaseous Fuels Safety and Environmental Control Assessment Program: Second Status Report, Vol. III, DOE/EV-0085, U.S. Department of Energy, (October 1980). 6. G. Strickland, Small-scale costs of hydrogen derived from ammonia. Brookhaven National Laboratory, Upton, New York, U.S.A. BNL 51487. October (1981). 7. H. J. Bomelburg, Use of Ammonia in Energy-Related Applications. Pacific Northwest Laboratory, Richland, Washington, PNL-SA 9057 (1981). 8. Department of Energy/Energy Information Administration, 1980 Annual Report to Congress, Vol. 3: Forecasts. p. 43. DOE/EIA-0173(80)/3. U.S. Govt Printing Office, Washington D.C. March (1981). 9. J. D'Acierno and M. Belier, Analysis of the Use of Hydrogen as a Supplement to Natural Gas. Brookhaven National

10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21.

Laboratory, Upton, New York, U.S.A. BNL 51442. July (1981). A. Oueirolo, Private communication, Brookhaven National Laboratory, Upton, New York, U.S.A, 24 July (1981). R. Newcombe and J. La Montagne, Factors Associated with the Annual Average Price of Bituminuoas Coal and Lignite (Work in progress at BNL) July (1981). Council of Economic Advisors. Economic Indicators, Prepared for Joint Economic Committee. p. 3. U.S. Govt Printing Office, Washington D.C., March (1981). L. J. Buividas, Coal to ammonia: its status. Chem. Eng. Prog. 77, 44-53 (1981). R. F. Neerken, Compressor selection for the chemical process industries. Chem. Engr 82, 2, pp. 78-98.20 January (1975). A. Pikulik and H. E. Diaz. Cost estimating for major process equipment. Chem. Engr 74, 20, 106-122, 10 October (1977). M. S. Peters and K. D. Timmerhaus. Plant Economics for Chemical Engineers. 3rd Edn. McGraw-Hill, New York (1980). Union Carbide Corp. Linde Division, 8 April (1981) (Private communication). Private communication, Air Products & Chemials Inc., 14 May (1981). Private communication, Air Products & Chemicals Inc., 17 July (1981). Department of Energy, Monthly Energy Review. DOE/ E14-0035 June (1981). J. H. Kelley and E. A. Laumann, Hydrogen Tomorrow, Jet Propulsion Laboratory, California Institute of Technology, California, U.S.A. JPL 5040-1, p. 100, p. 107. (1975).