Power plant flue gas as a source of CO2 for microalgae cultivation: Economic impact of different process options

~

Energy Convers. Mgmt Vol. 38, Suppl., pp. $505-$510, 1997

Pergamon

PII: SO 196-8904(96)00318-4

© 1997 Elsevier Science Ltd. All rights reserved Printed in Great Britain 0196-8904/97 $17.00 + 0.00

POWER PLANT FLUE GAS AS A SOURCE OF CO2 FOR MICROALGAE CULTIVATION: ECONOMIC IMPACT OF DIFFERENT PROCESS OPTIONS KIRAN L. KADAM Bioteehnology Center for Fuels and Chemicals National Renewable Energy Laboratory, 1617 Cole Boulevard, Golden, CO 80401, USA

ABSTRACT As CO2 plays a central role in the economics of microalgae cultivation, an accurate estimate of its cost is essential. Toward this end, an economic model was developed for CO2 recovery from power-plant flue gas and its delivery to mieroalgae ponds. A design basis was devised for recovering CO2 from flue gas emitted by a typical 500 MW power plant located in the Southwestern United States. For the standard process, which included monoethanolamine (MEA) extraction, compression, dehydration, and transportation to the ponds, a delivered CO2 cost of $40/t was estimated. The model was also used to evaluate the efficacy of directly using the flue gas, however, this option was found to be more expensive. The economics of mieroalgae cultivation using power-plant flue gas can be evaluated by integrating this model for CO2 recovery with a previously developed model for mieroalgae cultivation. The model predictions for a long-term process are: a lipid cost of $1.4/gal (unextracted) and a mitigation cost of $30/t CO2 (CO2 avoided basis). These costs are economically attractive and demonstrate the promise of mieroalgal technology. © 1997 Elsevier Science Ltd KEYWORDS mieroalgae cultivation,power plank flue gas, lipid production, CO2 mitigation, monoethanolamine (MEA) process, economic analysis

INTRODUCTION The United States (US) generates about 4.8 Gt (G --- 109) CO2, per year amounting to about 22% of the worldwide anthropogenie emissions (Herzog et aL, 1994). Electrical power plants are responsible for more than one-third of the US emissions, and for about 7% of the world's CO2 emissions from energy use. Physical capture of CO2 from fossil-fuel power-plants, which are stationary, concentrated sources of CO2, has been regarded as a possible mitigation option since Marehetti (1977) first suggested disposing the captured CO2 in deep ocean. Several investigators have since investigated a variety of options for CO2 capture from power plants and its subsequent disposal or use (l-Ierzog et al., 1993). Thus, CO2 capture is a common step to most of the remediation options, and getting a precise handle on its cost is essential. Because CO2 cost plays a pivotal role in the economics of mieroalgae cultivation, developing an economic model for its capture from flue gas is important to rigorously derive a CO2 resource cost to be charged to the process. The model reported addresses CO2 extraction using a typical monoethanolamine (MEA) process and delivery to the ponds; this allows us to precisely determine the delivered CO2 cost to the process. The previously derived economic model for miercaigae cultivation (Kadam and Sheehan, 1996) and $505

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this model for CO2 capture from flue gas can be integrated to develop realistic costs for lipid production and CO2 mitigation, and to gain an insight into the overall process. MEA PROCESS To date, the MEA process has been the technology of choice in the recovery of CO2 from low-pressure flue gases (Maddox, i977; Kohl and Riesenfeld, 1979). A detailed flow diagram for the MEA process is shown in Figure 1 (adapted from Maddox, 1977; Anada et al., 1982). The process flow scheme changes little, irrespective of the aqueous amine solution used as the absorptive agent. The primary pieces of equipment are the absorber and stripper columns, together with the associated piping, heat exchange, and separation equipment. The MEA process was chosen for CO2 capture and was modeled as described below.

C02 COST ESTIMATION Design Basis The key design and calculated performance parameters are given in Table 1. A 500-MW capacity was assumed for the standard recovery process. The power plant was assumed to be located in the Southwestern US. Based on typical Southwestern plants, flue gas emission and CO2 concentration of 2.25 million SCFD/MW (standard cubic feet per day/megawatt) and 14% by vol., respectively, were assumed. The SO2 and NO~ levels are defined as those in the 1990 CAAA (US Clean Air Act Amendments), i.e., 200 and 150 ppm, respectively. Based on these conditions, the total CO: recovered was 2,830,300 t/yr for a CO: recovery of 88.6%. A lower plant capacity of 50 MW, which had a correspondingly lower CO2 production capacity, was also analyzed. The standard process includes MEA extraction, compression to 1500 psi, dehydration, and transportation to the ponds, and delivers a gas that is -100% CO2. Dehydration of the gas to water concentrations of <50 ppm by volume is necessary to prevent corrosion of the pipeline by carbonic acid. In order to assess whether the flue gas could be directly utilized, a ease was devised that omitted the extraction step and only included compression, dehydration, and transportation to the ponds. As this direct pumping option does not further process the flue gas, it delivers the gas to the ponds at a COe concentration of only 14%. A transportation distance of 100 km was assumed. The pond system would likely not be adjacent to the power plant, and a 100-kin (ca. 60-mile) distance is a judicious choice from the standpoint of reasonable transportation costs and increased land availability. Basis for Capital and Operating Costs Table 2 lists the major equipment as shown in Figure 1, and Table 3 shows items that contribute to the operating costs. As the direct pumping option does not include MEA extraction, Table 2 does not apply. However, because this option has to handle a sevenfold higher volume of the gas for a given CO2 input to the algae ponds, the size of compressors and pipeline increase, and electricity consumption rises substantially. A higher gas-injection capacity at the ponds is also needed; however, this was not factored into the calculations. The Questimate ® software (ICARUS Corp., 11300 Rockville Pike, Rockville, Maryland) was used for estimating capital costs. For major pieces of equipment such as compressors and blowers, vendor quotations were solicited, and they compared reasonably well with the software estimates. For consistency, all model calculations were done using capital costs derived from Questimate. ®

KADAM: POWER PLANT FLUE GAS

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Table 1. Design Basis and Plant Performance: 500 MW Plant, Standard MEA Process Parameter

Value

lnput to the Model

Power plant type Location Rated capacity, MW Coal consumption, t/d IFGD (Flue Gas Desulfurization) Alrnosphenc pressure, psia !Fluegas emission, MM SCFD/MW lFlue gas flow rate, SCFM i

'

'

Coal-fired SW US 500 5,556 Yes 12.2 2.25

.

781,250 22,503 14.0 1,500 100

sm3/min

CO2 concentration, vol. % Compression pressure, psig Pipeline distance, km Calculated Performance Parameters

Total CO2 recovered, t/yr CO2 recovery, % Equivalent microalgae facility size for algal productivity of 45 g/m2d, ha

2,830,311 88.6 13,862

115°F 14.7 ) s l a Lean las

('Abs°rber I

Blower

Filter ~ 0 0 O F I ~J ] Blanket !

c~,er '~___~,

,nte,,~gac~,er, Inlet gas cooler

100°F A

~.

Rashnas I f _ J ~ "

,ne V----'

I I

~e

I

I Strippq

I

11oof 21% ~tank I

.

, I Fluegas V l a ~ e ~ ' - ' ~ gas from power 14.7psia 130OF plant after desulfudzation Flash tankL~l ~ Rich amine pump

CO2

/

~Z-~ 2~0°FI ~ I

0

• \ v \ .~,/195°F~' ,~ I Lean ,235OF v LI • amine pump Foul MEN Still JeanMEA reboiler heat exchanger

~

Reflux I I , eeclaimer

To crystallizer P204-B,?.57801

Fig. 1. Detailed flow diagram of the MEA process. E C M 38/SUPI

R

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Table 2. Costs Centers: MEA Extraction

Absorber column Stripper column Stripper reboiler Stripper reclaimer Stripper condenser Amine-amine beat exchanger Flash tank

Capital Costs Lean amine cooler Inlet gas cooler Interstage cooler Byproduct gas blower Reflux tank Surge tank

Rich amine pump Lean amine pump Reflux pump Crystallizer Boiler Cooling tower

Operating Costs MEA makeup Na2CO3, anhydrous Cooling tower water Coal for steam gen. Electricity Labor

Amine filter

Table 3. Cost Centers: Compression, Dehydration and Transportation Capital Costs Inlet Gas Cooler Compressor 2 inter-cooler Compressor 1: high capacity, Dryer centrifugal Compressor 2: high pressure, Pipeline reciprocal Compressor 1 inter-cooler

Operatin~ Costs Cooling tower water Electricity Labor

Pipeline costs were estimated by updating the data of I-lare et at (1978) to 1995 by using an average of Chemical Engineering and Marshall-Swift indices; these indices were used since the pipeline cost index is no longer published by Oil & Gas Journal. Another approach for estimating pipeline costs is to use Oil & Gas Journal's annual Pipeline F_x~nomicsReport (True, 1994). Both methods gave similar numbers for 1995 pipeline costs; the Oil & Gas Journal costs were used in model calculations. Coal costs were obtained from the following US Deparlment of Energy's publications: "Coal Industry Annual 1993," and "Cost and Quality of Fuels for Electric Utility Plants 1993" (Energy Information Administration, 1994a; 1994b). Materials costs were obtained from ChemicalMarkeang Reporter. Comparison of Processing Options The MEA extraction, compression and dehydration, and transportation sections were analyzed for capital and operating costs, and an annualized cost in $/t CO2 was calculated for each case. Cost summaries for recovering CO2 from a 500 MW plant using the MEA extraction and the direct pumping options are shown in Tables 4 and 5, respectively. Delivered C02 cost for the standard process with MEA extraction is $40.5/t for a 500-MW plant and rises to $57.1/t for a 50-MW plant. The 50-MW ease represents either a very small plant or a slip stream from the flue gas of a large plant. The direct pumping option is more expensive than the MEA extraction option by about 40% and 54% for the 500- and 50-MW capacities, respectively. This is due to the penalty paid by the direct pumping option in compression and transportation of a sevenfold higher gas volume. Furthermore, the higher gas volume injected into the ponds can also increase evaporative loss of water. Thus, using the flue gas 'as is' does not seem to be a viable strategy. This is a significant finding and has profound implications for pond design and operation.

EFFECT OF PREDICTED C02 COSTS ON MICROAGAL TECHNOLOGY To trap all the CO: from the 500-MW plant, about 14,000 ha of land would be needed for the long-term process that has an algal productivity of 45 g/m2/d. The microalgae model of Kadam and Sheehan (1996) for a 1000-ha pond system was used for studying the effect of the CO2 resource costs on overall process economics. Scale-up of the microalgal system is assumed to be on a modular basis size as ponds larger than 20 ha are considered to be unwieldy, if not impossible. A large-scale microalgal facility would

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Table 4. Cost Summary for CO2 Recovery from 500 MW Plant: Standard Process with MEA Extraction

MEA extraction Compression and

Capital Operating Costs, Costs, $ $ 112,785,600 60,155,900 52,359,500 13,564,500

Transportation Total

44,508,300 209,653,400

Annualized Costs, $/t CO2 28.72 8.48

Annualized Costs, % of Total Cost 70.9 20.9

3.30 40.50

8.2 100.0

445,100 74,165,500

Table 5. Cost Summary for CO2 Recovery from 500 MW Plant: Direct Pumping of Flue Gas

Compression and

Capital Costs, $ 287,928,100

Transportation Total

142,564,700 430,492,800

Operating Costs, $ 91,423,800

Annualized Costs, $/t CO: 46.64

Annualized costs, % of Total Cost 81.5

1,425,600 92,849,400

10.58 57.21

18.5 100.0

Table 6. Economic Performance of Microalgal Processes with Different Maturities Mid-Term Process

Long-Term Process

Cell concentration in pond, g/L

1.0

1.2

Algal lipid content, % wt

45

50

Residence time, d

5.5

4

Operating season, d/yr

275

300

Algal productivity, g/m2/d

27.3

45

Photosynthetic efficiency, %

3.6

6.1

282.5

209.5

87.7 /2.09

58.6 / 1.40

26.6

37.9

as is basis

63.8

20.0

C02 avoided basis2

95.7

30.0

Algae cost, $/t Lipid cost, $/bbl, $/gal (tmextracted) C02 cost, % of annualized cost C02 mitigation cost1, $/t C02

1Based on credit at the followingrate: lipid = $240/t, protein = $120/t, carbohydrate = $120/t. 2CO2 avoided basis cost = 1.5 x (as is basis cost). Based on data of Herzog (1994). consist of several 20-ha ponds, and hence, the economies of scale would not apply in a significant way. Furthermore, these estimates are conceptual in nature. Therefore, the above model can be assumed to reasonably predict the process economics of a 14,000-ha system. If anything, the model predictions would be on the conservative side. Table 6 shows a comparison of two cases that can be envisioned: a mid-term and a long-term process that exemplify the potential of this technology. Microalgal technology can be looked upon as an avenue for producing a lipid feexlstockfor biodiesel production; alternatively, it can be an option for C02 mitigation. The model was used to predict process performance from both of these angles. Using a CO2 resource cost of $40.5/t, the mid-term process yields a C02 mitigation cost of $96/t (CO2 avoided basis), which falls in

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KADAM: POWER PLANT FLUE GAS

the range of cost estimates reported by Herzog (1994) for the capture and ocean-disposal option. The lipid cost for the mid-term process is also comparable to the current crude soybean oil prices of $2.25 $3.25/gal; soybean oil is currently the preferred feedstock used in biodiesel production. The long-term process yields a lipid cost of $1.4lgal (unextraeted) and a CO2 mitigation cost of $30/t (CO2 avoided basis), both of the costs being highly competitive. Thus, the microalgal technology is a promising technology for both lipid feedstock production and CO2 mitigation.

CONCLUSIONS The economic model developed allows us to rigorously derive C O 2 recovery costs and make decisions regarding processing options. Pumping the flue gas directly to the ponds does not seem to be a viable alternative as it is 40% more expensive than the MEA extraction option. This finding is important since it has a significant effect on pond design and operation. Integrating the models for microalgae cultivation and CO2 capture from flue gas allows us to predict overall process performance. The predicted lipid and CO2 mitigation costs are economically viable, given that the defined performance targets are met and the longterm process comes to fruition. Thus, microalgal cultivation is a potentially useful technology.

ACKNOWLEDGMENTS This work was supported by the following projects: Biological Trapping of Carbon Dioxide, funded by DOE/PETC (Dept. of Energy, Pittsburgh Energy Technology Center, Pittsburgh, Pennsylvania; and Bioutilization of Coal Combustion Gases, funded by DOE/FE (Dept. of Energy, Fossil Energy section, Germantown, Maryland).

REFERENCES Anada, H., D. King, A. Seskus, M. Fraser, J. Sears and R. Watts. (1982). FeasibiBty and Economics of By-product C02 Supply for Enhanced Oil Recovery, Final Report: DOE/MC/08333-3 (DE82004814). Energy Information Administration. (1994a). US DOE (Dept. of Energy) publication: Cost and Quality of Fuels for Electric Utility Plants 1993, Washington, DC. Energy Information Administration. (1994b). US DOE (Dept. of Energy) publication: Coal lndustry Annual 1993, Washington, DC. Hare, M., H. Perlieh, R. Robinson, M. Shah and F. Zimmerman (1978). Sources and Recovery of Carbon Dioxide for Enhanced Oil Recovery, Final Report: FE-2515-24. Herzog, H., E. Drake and J. Tester (1993). A Research Needs Assessment for the Capture, Utilization and Disposal of Carbon Dioxide from Fossil Fuel-Fired Power Plants, Report for DOE (Dept. of Energy) Grant No. DE-FG02-92ER30194.A000. Herzog, H. (1994). CO2 mitigation strategies: How realistic is the capture and sequestration option? Paper no. 94-RAl13.02, Proc. 87th Air & Waste Manage. Assoc. Ann. Mtg. & Exhibi., Cincinnati, Ohio. Kadam, K.L. and J.J. Sheehan. (1996). Mieroalgal technology for remediation of CO2 from power plant flue gas: a teehnoeconomicperspective. World Resource Review, 8(4), 493-504. Kohl, A.L. and F.C. Riesenfeld (1979). Gas Purificaaon, 3~ ed., Gulf Publishing Co., Houston. Maddox, R. N. (1977). Gas andLiquid Sweetening, John M. Campbell (Campbell Petroleum Series), Norman, Oklahoma. Marchetti, C. (1977). On geoengineering and the CO: problem. Climaac Change, 1, 59-68. True, W.R. (1994). Pipeline economics report. Oil & Gas J., 92(47), 41-58.