SERI/TP-232-3820

UC Category: 244

DE90000361

CO2 Sources for

Microalgae-Based

Liquid Fuel Production

D. Feinberg

M.Karpuk

August 1990

Prepared under Subcontract No. HK·8·18045-1

Solar Energv Research Institute

A Division of Midwest Research Institute

1617 Cole Boulevard

Golden , Colorado 80401-3393

Prepared for the

U.S. Department of Energy

Contract No. DE-AC02-83CH10093
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at the above address.
TP-3820

SUMMARY

The Solar Energy Research Institute's (SERI) Aquatic Species Program is developing microalgal species

and culture teclmologies that result in microalgal cells with a high percentage of lipids. The lipids can

be extracted and converted to a diesel fuel substitute. Optimal microalgae growth occurs in carbon

dioxide (COz) saturated solutions. If these research efforts are successful, large quantities of low-cost

CO2 will be needed. The purpose of this study is to identify possible CO2 sources for microalgaebased fuel production and to quantify the amounts available and possible costs. Because of the early

stage of development of the fuel synthesis technology, and the current plentiful supplies of gaseous and

liquid fossil fuels, we chose the year 2010 as the earliest date that CO2 for fuel synthesis would be

needed.

We analyzed four sources of CO2:

Natural Reservoirs. Large natural reservoirs of CO2 in the southwestern United States are currently

being utilized for enhanced oil recovery (EaR). These reservoirs are expected to be depleted by the

year 2010 and consequently unavailable for micro algae production. However, the CO2 used for EaR

will remain in the depleted oil fields. and could be recovered for micro algae production. Some natural

gas fields contain significant quantities of CO2• which are not currently being produced because of high

separation costs. If the economics of these fields improve, this CO2 could become available.

Fossil Fuel Combustion. The United States has very large coal reserves, and coal is expected to remain

a primary energy source in 2010 and beyond. Coal combustion in power, synthetic fuels, and chemical

process plants will produce large quantities of COz• Clean coal technologies under investigation by the

Electric Power Research Institute (EPRI) and the U.S. Department of Energy (DOE) have the potential

to produce large quantities of concentrated C~ at low cost. Concern about possible regulation of

global warming caused by the release of CO2 into the atmosphere may make CO2 available from these

sources at low or even negative costs.

Air Separation. It is conceivable that CO2 could be recovered directly from the atmosphere, where it

is the fourth-largest constituent. However, because the atmospheric CO2 concentration is very low (330

ppm), significant technical breakthroughs are required to make the process viable.

Anaerobic Digestion. Anaerobic digestion of biomass and wastes is currently being investigated as a

source of methane. Methane and COz are coproduced in approximately equal molar volumes and are

easily separated. Large quantities of CO2 could be available from fuel-scale anaerobic digestion plants.

The results of this study indicate that there are several large sources of CO2 that could support

micro algae-based fuel production.

We also evaluated the costs of transporting CO2, Supercritical pipelines are the most economical

method of transporting CO2 for the flow rates required for fuel synthesis. Transportation costs are

typically $0.008/kg per 100 miles for a pipeline capacity of approximately 2.6 x H1 kg/d. Therefore,

transportation of CO2 is feasible only from large concentrated sources over relatively short distances.

This implies that microalgae production facilities should be sited near CO2 sources.
TP-3820

TABLE OF CONTENTS

SECTION PAGE

1.0 INTRODUCTION ••..•...•••.••..•••.•..•••••..•••..•.•.•• 1

1.1 Purpose of Study 1

1.2 System Overview '. . . . . . . . . . . . . . . . . . . . . . . . . . . . . " . . . . . .. 1

1.2.1 Energy Sources 1

1.2.2 Microalgae Conversion Technology . . . . . . . . . . . . . . . . . . . . . 1

1.2.3 Quantities of CO2 Needed . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.2.4 Conversion Factors . . . . . . . . . . . . . . . . . . . . . . . .. 2

2.0 CURRENT SOURCES AND USES OF CO2 •••••••••••••••••••••••• 4

2.1 Merchant Market 4

2.1.1 Sources of CO2 for the Merchant Market . . . . . . . . . . . .. 4

2.1.2 Uses of CO2 in the Merchant Market 5

2.1.3 Value of CO2 in the Merchant Market . . . . . . . . . . . . . . . . . . . 6

2.2 Enhanced Oil Recovery 7

2.2.1 Sources of CO2 for Enhanced Oil Recovery 7

2.2.2 Value of CO2 in Enhanced.Oil Recovery 7

3.0 POTENTIAL CO2 SOURCES FOR MICROALGAE-BASED

LIQUID FUEL PRODUCTION 8

3.1 Natural CO2 Reservoirs 8

3.1.1 Estimated Reserves ". . . . . . . .. 8

3.1.2 Depletion..............................,. . . . . .. 9

3.1.3 EOR CO2 Reuse '. . . . . . . .. . . . . . .. 9

3.2 Noncommercial Quality Natural Gas .. . . . . . . . . . . . . . . . . . . . . . . . 9

3.2.1 Estimated Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 10

3.2.2 Separation Cost 11

3.3 Fossil Fuel Combustion 12

3.3.1 Process Plants . . . . . . . . . . . .. 12

3.3.2 Conventional Power Plants .:........................ 14

3.3.3 Clean Coal Technologies 17

3.3.4 CO2 Emissions Controls . . . . . . . . . . . . . . . . . . . . . . . . . . .. 22

3.4 Atmospheric Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 23

3.5 Anaerobic Digestion 23

4.0 TRANSPORTAnON COSTS •.•••••.•••.•••.••••..•.•••..••. 25

500 ANALYSIS OF SEPARAnON, TECHNIQUES • • . • • • .. . . • • . • • • . . • . .• 29

5.1 Physical Solvents 29

5.2 Chemical Solvents 29

5.3 Membranes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 29

5.4 Cryogenic Distillation 29

5.5 Electrochemical CO2 Carriers . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 30

5.6 Separation Energy Requirements. . . . . . . . .. . . . . . . . . . . . . . . . . .. 30

6.0 CONCLUSIONS. . . .. . . . • • • • • • .. . . • • • . . • . • • • .. .. . .. • • • • • . .. • •. 31

7.0 REFERENCES. . .. .. . . • . .. . • • . .. • • . . • .. . . • • . . . • .. . . .. .. . • .. .. • .. ... 33

ii
TP-3820

LIST OF FIGURES

NUMBER

2-1 CO2 Merchant Market: Capacity, Production, and Future Demand . . . . . . . . . . 5

2-2 Merchant Market CO2 Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 6

3-1 Major Natural CO2 Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 8

3-2 Plot of Compositions of Mixed Natural Gas/C02 Sources . . . . . . . . . . . . . . . .. 10

3-3 Commercial and Noncommercial CO2 Reserves 11

3-4 CO2 Recovery + Compression Costs from Process Plants . . . . . . . . . . . .. 15

3-5 CO2 Recovery + Compression Costs from Power Plants . . . . . . . . . . . . . . . . .. 16

3-6 U.S. Demonstrated Coal Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 17

3-7 Projected Year-201D Combustion of Fossil Fuels for Electricity . . . . . . . . . . . .. 18

3-8 ANL Scheme for Concentrated CO2 Combustion 19

3-9 EPRI/Fluor Coal Gasification With and Without CO2 Coproduction . . . . . . . . . .. 21

3-10 The Advanced Coal Refinery 22

4-1 Transportation Costs for Various Transportation Options ~................ 26

4-2 Allowable Transportation Distance Based on CO2 Source .1. • • • • • • • • • • • • • •• 27

iii
TP·3820

LIST OF TABLES

NUMBER

1-1 CO2 Quantities Required for Microalgae-Based Fuel Production . . . . . . . . . . . .. 2

2-1 Annual Production of CO2 for the Merchant Market . . . . . . . . . . .. 4

3-1 Major Natural CO2 Reserves .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 9

3-2 CO2 Recovery and Drying Costs from Noncommercial Natural Gas 12

3-3 CO2 Production and Concentration from Cement Plants 14

3-4 Coproduction of CO2 with Electricity from Fossil Fuels . . . . . . . . . . . . . . . . .. 15

3-5 Energy Potential of Fuel Synthesis Using CO2 from Anaerobic Digestion . . . . . .. 24

4-1 Comparison of Assumed Line Sizes for Supercritical Pipelines 25

5-1 Theoretical versus State-of-the-An Energy Requirements for

Separation of CO2 from Flue Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 30

6-1 Potential Sources of CO2 for Fuel Synthesis in 2010 . . . . . . . . . . . . . . . . . . .. 32

iv
TP-3820

1.0 INTRODUCTION

This study, funded by the Solar Energy Research Institute's (SERI) Aquatic Species Program, examines

sources of carbon dioxide (CO~ for microalgae-based fuel production in the year 2010 and beyond.

1.1 Purpose of Study

Under the auspices of the U.S. Department of Energy (DOE), the SERI Aquatic Species Program is

developing microalgal species and culture technologies that result in microalgal cells with a high

percentage of lipids. Lipids can be extracted and converted to a diesel fuel substitute. Optimal

microalgae growth occurs in a CO2 saturated solution.

If these research efforts are successful, large quantities of low-cost CO2 will be needed. The purpose

of this study is to identify possible CO2 sources for microalgae-based fuel production and quantify the

amounts available and possible costs. Because large quantities of CO2 will be needed over the next

25-50 years for enhanced oil recovery (EOR), we have made extensive use of many studies and

projections developed by those involved in EaR; we acknowledge the value and usefulness of their

efforts. Because of the early stage of development of the microalgae-based fuel production technology,

and the current plentiful supplies of gaseous and liquid fossil fuels, 2010 was chosen as the earliest

date that CO2 for microalgae-based fuel production would be needed.

1.2 System Overview

1.2.1 Energy Sources

Microalgae-based liquid fuel production using CO2 may be important in the future when petroleum

and natural gas supplies have largely been depleted. Microalgae production facilities will be located

in sunny areas with moderate climates. Consequently, we have emphasized CO2 sources in the southern

and southwestern United States where solar radiation is the greatest. We have analyzed CO2 sources

in the ten sunniest states in the United States: Alabama, Arizona, California, Florida, Georgia,

Louisiana. Mississippi, New Mexico, Oklahoma, and Texas.

1.2.2 Microalgae Conversion Technology

SERI is pursuing research on the production of liquid fuels through photosynthetic organisms such as

rnicroalgae. Microscopic algae have demonstrated the ability to accumulate cell mass in the form of

high-energy products, or lipids, while achieving high rates of growth (Neenan et al. 1986). The lipids

produced are chemically similar to hydrocarbons, having long chains of 12-24 carbon atoms, with

0-5 double bonds (Tornabene et ale 1983). However, increases in lipid content are mainly achieved

at the expense of higher growth rates, and vice versa. Neenan et ale (1986) concluded that further

species improvement in productivity, lipid content, and environmental tolerance was critical in

establishing the economic viability of fuels from microalgae technology.

1.2.3 Quantities of CO2 Needed

1.2.3.1 Fuel Synthesis. The quantity of CO2 required to support the synthesis of a given amount of

fuel product depends on which product is considered. For the synthesis of carbohydrate, the

generalized reaction is

Based on a heat of combustion for the typical carbohydrate of 7500 Btu/lb (17.4 Ml/kg), the CO2

requirement is 90 x 109 kg/quad (1.7 TSCF/quad).

1
TP-3820

For lipid fuel products, two sets of values were calculated, each based on "typical" microalgal lipids

as being triglycerides of a saturated 12-carbon fatty acid ora polyunsaturated 18-carhon fatty acid.

For the latter, the generalized reaction would be

57 CO2 + 31 H20 -----> CS7H620 6 + 69.5 O2 ,

Based on a triglyceride heat of combustion of 17,000 Btu/lb (39.5 MJ/kg), the CO2 requirement is

80 x 1()9 kg/quad (1.5 TSCF/quad). For the 12-carbon triglyceride (C39H740J, the CO2 requirement is

72 x 1()9 kg/quad (1.4 TSCF/quad).

The above calculations for lipids are based on recycle of all nonlipid cell mass by anaerobic digestion,

with resulting production of methane and more CO2, If the nonlipid constituents are not recycled, then

more CO2 is required per quad of stored energy. Table 1-1 summarizes the quantities of CO2 required

for microalgae-based fuel production via the various routes discussed.

Table I-I. CO:z Quantities Required for Microalgae-Based

Fuel Production

Fuel Synthesis" Energy Storage

Product g COJg product lQ9 kg/quad"

CH20 1.5 89

Lipids" (with

cell recycle) 2.7-3.0 72-80

Lipids (without

cell recycle) 3.6-4.0 96-107

a 100% utilization efficiency

b To convert kg to SCF, divide by 0.0522

c 60% lipid content

1.2.3.2 Enhanced Oil Recovery. We will review CO2 demand for EOR uses because it has many

similarities to the CO2 needs for microalgae-based fuel production. Hare et aI. (1978) estimates the

ultimate quantities of oil that could potentially be recovered through the use of CO2 at 4-8 x 109 bbl.

The CO2 requirement to recover 1 bbl of oil can vary between 5 and 15 MSCF/bbl (260-780 kg/bbl),

with a more likely range of 5-10 MSCF/bbl after recycling. Multiplying these two quantities together

could yield a range of anywhere from 20 to 80 TSCF (1-4 X 1012 kg). To arrive at an annual demand,

we arbitrarily assume an depletion period of 25 yr, which is consistent with. derived estimates of

0.6-1.2 x 1a' bbl/d (based on 80% production) from the work of Hare et aI. (1978). This depletion

period yields annual demand figures of 40-160 x 10' kg COJyr~ Because a barrel of domestic crude

oil represents, on average, 5.8 MMBtu (31 MJ/m3

) , between 45 and 135 x 109 kg of CO2 would be

required to produce one quad of crude oil, which is in the same order of magnitude as the estimates

for microalgae-based fuel production of Table 1-1.

1.2.4 Conversion Factors

Because CO2 quantities are expressed in units of weight and volume with nearly equal frequency, we

will clarify here the conversion factors that we will use throughout this report. The abbreviation

"SCFtI will refer to the standard cubic foot as used by the gas industry, which is at 68°F and 14.7 psia

(l ann). The weight of 1 SCF of CO2 is 0.115 lb, so

1 SCF = 0.115 lb (68°P, 1 attn).

2
The convention for English (not SI units) of "M" to indicate thousands, "Mlvl" to indicate millions,

and "B" and "T" to indicate billions and trillions enables us to make the following conversion:

I ton = 17,400 SCF = 17.4 MSCF.

Based on the fact that 1 kg =2.204 lb:

1 SCF = 52.2 g

1 MSCF = 52.2 kg

1 MMSCF = 52.2 Mg or 52.2 x 103 kg

1 BSCF = 52.2 x 106 kg, etc.

In addition, a note about annualized figures presented in this report is in order. In much of the gas

processing industry, it is convenient to express daily quantities, e.g., one billion standard cubic feet per

day is represented by 1 BSCFD. What annualized quantity does this represent? Many of the sources

we rely on assume a capacity factor of 80%, or roughly 300 operating days per year. Others ensure

a capacity factor of 90% or 330 days per year. Still others are less clear; where this occurs we opt

for the rigorous approach, which is to cite the daily and annualized numbers separately and, where

applicable. to cite the capacity factor explicitly.

3
TP-3820

2.0 CURRENT SOURCES AND USES OF CO2

2.1 Merchant Market

Although the merchant market accounts for only a tiny fraction of the total annual CO2 production, its

components are reliably estimated and reported. The two primary sources of carbon dioxide for the

merchant market are the production of ammonia from natural gas and ethanol from the fermentation

of sugars (Chemical and Engineering News, 1984, 1986). The key factor that makes the CO2 from

these processes (as well as the others detailed below) available to the merchant market is that it must

be separated from the main product during the purification of that product. Thus, no extra costs are

required for CO2 recovery. Table 2-1 summarizes recent annual domestic production of CO2 for the

merchant market.

Table 2-1. Annual Production of CO2 for

the Merchant Market

State

Production (109 kg/yr)

1986 1985

Solid

Liquid

Gas

Total

0.44

4.00

3.76

8.20

0.41

4.13

3.50

8.04

Source: U.S. Department of Commerce, 1987

2.1.1 Sources of CO2 for the Merchant Market

2.1.1.1 Ammonia plants. The production of ammonia from natural gas is a multiple-step process,

primarily consisting of (1) steam reforming of the natural gas into synthesis gas (carbon monoxide

and hydrogen), (2) water-gas shift reaction of carbon monoxide and water into hydrogen and CO2, and

(3) reaction of the hydrogen with nitrogen to form ammonia. In typical plants, 1.1-1.2 kg of CO2 are

produced per kilogram of ammonia, a portion of which is often used captively for the production of

urea (Stern 1986). The majority (up to two-thirds) of the CO2 coproduced with ammonia is actually

vented, as adequate CO2 sources exist to meet current demand. The total CO2 coproduction is 15-

19 x 109 kg/yr; of this, one-fourth is used for urea production, and only about 40% actually enters

the merchant market (Chemical and Engineering News, 1987).

2.1.1.2 Ethanol plants. The production of ethanol by the fermentation of organic substances such as

com, molasses, and potatoes has grown significantly throughout this decade. The increased use of

ethanol as a blending agent in automotive gasoline, the result of tax incentives as well as mandated

reductions in tetraethyl lead, has opened up the market considerably. In the fermentation process,

ethanol and CO2 are produced in approximately equal weights. Based on current fermentation ethanol

production of 700 million gallons per year (Alcohol Outlook, July 1987), more than 2.1 x 109 kg of

CO2 are coproduced. Again, much of this gas is vented, leaving a merchant production of about 1 x

109 kg/yr.

2.1.1.3 Hydrogen plants. Refmeries produce hydrogen for operations such as hydrocracking and

isomerization, using the first two major steps in the production of ammonia described above. The CO2

must be removed to produce a high-purity hydrogen product. The volumetric ratio of CO2 to

hydrogen produced by this process is 1 to 4 (Stem 1986). Only about 5%-10% of the nearly 9 x

109 kg/yr of CO2 produced in this way enters the merchant market.

4
TP-3820

2.1.1.4 Other sources. These include CO2 coproduction with ethylene oxide, as well as those sources

that produce CO2 as a dilute component of a product or waste stream; e.g., electric power plants,

cement plants, and industrial boilers and furnaces. None of these sources currently contributes

significant quantities of CO2 to the merchant market, although all of them have the potential to do so

if the economics and the technology improve. We will discuss these considerations in Section 3.

Figure 2-1 summarizes the discrepancy between the quantity of by-product CO2 produced and the

quantity that would actually be required for future demands such as EOR or microalgae-based fuel

production. It also compares the current production and sales to that which would be needed for

EaR.

2.1.2 Uses of CO2 in the Merchant Market

2.1.2.1 Refrigeration. Liquid carbon dioxide provides a readily available method of rapid refrigeration

and is used for quick chilling of loaded trucks and rail cars before shipment. For example, a 4-min

injection of liquid CO2 into a loaded ice cream truck can decrease the temperature as much as 70°C,

flushing the warm air from the truck and leaving a layer of CO2 snow. This process greatly reduces

the load on the truck's mechanical refrigeration system and minimizes the time required to cool the

truck's contents to a safe storage temperature. Solid carbon dioxide (dry ice) is also an important

refrigerant in many laboratories and hospitals, as well as for molded rubber products, aluminum rivets,

and food products such as meats and ice cream (Ballou 1978). Production of liquid and solid carbon

dioxide from the gaseous state is summarized in Section 2.1.3.

150

5- 100 ......

a

.:.e.

'0

50

o

Low

D FubseDemands

• Actual

Hy<togen plants

Ethanol plants

I::::::!::"::"i!::::!:il Ammof1a plants

Sot.I'ces:

C & E New8 (1987)

Stern (1986)

Capacity Actual saJes EOR

Figure 2-1. CO2 merchant market: capacity, production, and future demand

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TP-3820

2.1.2.2 Beverage manufacture. Gaseous CO2 under pressure is introduced into beverage mixes; on

pressure release, the foaming beverage product is produced. Both soft drinks and so-called "light"

beers are made in this way (Ballou 1978).

2.1.2.3 Miscellaneous. There is a wide variety of other uses for carbon dioxide. The gas is used

for shielded arc welding, where speed has been increased tenfold with semiautomatic microwave

welding equipment. The gas is' also used in foundries (to harden sand cores and molds) and

slaughterhouses (to immobilize the animals prior to slaughter). Liquid CO2 is used as a fire

extinguisher in chemical plants, warehouses, and airplanes; it is also used in the coal mining industry.

It also finds applications as a chemical reagent in the manufacture of sodium, potassium, and

ammonium carbonates and bicarbonates (Ballou 1978).

2.1.3 Value of CO2 in the Merchant Market

The value of carbon dioxide in the merchant market depends on its state. These values, summarized

in Figure 2-2, are based on 1985 data from the U.S. Department of Commerce. The price differences

are essentially functions of the costs associated with phase-change. Liquefaction is accomplished by

two common processes; the first involves compression at 32°C to 75 atm followed by condensation.

The second involves compression to 16-24 attn, followed by cooling to the range of -12° to -23°C,

and condensation. Filtration and drying are included in both processes to remove any oil and water.

Dry ice is produced in blocks by hydraulic presses. The liquid CO2 is fed to the press chamber at

7 atm and -46°C. The feed is then expanded to atmospheric pressure, thus passing the triple point

(5 atm) and solidifying to form carbon dioxide snow. The hydraulic rams then press the snow into

a solid block of dry ice, which is usually stored in insulated bins or trucks (Ballou 1978).

0.1

0.09

8 0.08

......

0.07 ...-

s 0.06

0

0.05

x

S 0.04

i 0.03

0 0.02

0.01

0

Gas L.icJJid Solid

(Source: U. S. Department of Commerce, 1987)

Figure 2-2. Merchant market CO2 cost

6
TP-3820

2.2 Enhanced Oil Recovery

Carbon dioxide is used in EaR in a procedure known as miscible flooding. CO2 is injected into a

reservoir to modify the viscosity-temperature-pressure profile of the oil, making the oil flow more

easily. EOR may be conducted early in the life of a reservoir, or at any time during its producing life.

It is most likely to occur after primary recovery (normal depletion without the addition of injected

fluids), and secondary recovery (the injection of immiscible fluids, e.g., water as an energy source),

have been completed. Estimates of the ultimate potential for CO2-based EaR are speculative, but, as

discussed in Section 1.2.3, could be as high as 2-8 x 109 bbl (Hare et al. 1978), or somewhere between

10%-30% of the 1986 proven crude oil reserves (U.S. Department of Energy 1987a).

As discussed in Section 1.2.3, the annual CO2 demand for EaR is estimated to fall in the range of

40-160 x 109 kg, or between 150% and 500% of the current merchant market production capacity of

27 x 1Q9 kg/yr.

2.2.1 Sources of CO2 for Enhanced Oil Recovery

2.2.1.1 Natural sources. Carbon dioxide exists underground in significant quantities, in reservoirs of

essentially pure CO2 or CO2 mixed with natural gas. When these reservoirs are located near crude oil

reservoirs, they become the source of choice for EaR projects, since CO2 from natural reserves can

be produced at low costs and transportation costs increase significantly with distance. Hare et al.

(1978) collected data on the major natural CO2 sources in the Rocky Mountain region (Colorado, Utah),

Southwest (Texas, New Mexico), and Appalachian states (West Virginia) and were able to formulate

estimates of the quantities of reserves available. However, they could not estimate CO2 costs from such

sources because of uncertainties in critical factors such as well reserve size, flowing wellhead pressure,

and actual drilling costs. In fact, these uncertainties are not always fully resolved by the time a

venture becomes commercial. Arco Oil and Gas Company is currently operating a 400-mile CO2

pipeline from Huerfano County, Colorado, to Gaines County, Texas, whose design was based on

erroneous reservoir performance data (Watson and Siekkinen 1986), causing many of the components

to be larger or more expensive than necessary. The details of natural CO2 sources will be discussed

further in Section 3.1.

2.2.1.2 Electric power plants. There are so many power plants spread throughout the country that,

in the aggregate, they represent a huge potential source of CO2, However, their current use is limited

because of two factors: (1) the CO2 content of the typical flue gas is only about 14%, and (2) the

power plants are rarely located in close proximity to either the EaR project itself or a pipeline that

can deliver the CO2 to the project. The first factor can be overcome by suitable CO2 separation

techniques (Section 5.0); the second factor must be overcome by constructing either new power plants

or pipelines (Section 4.0).

2.2.2 Value of CO2 in Enhanced Oil Recovery

Because EaR may compete with microalgae production for CO2 , we have examined possible prices in

this application. Based on a 10% annual rate of return, and for CO2 flooding efficiency of 520 kg/bbl

(10 MSCF/bbl), the maximum allowable CO2 cost was estimated at $0.015/kg ($O.80/MSCF) for a

wellhead oil value of $20/bbl. If the price of oil were to double to $40/bbl in constant dollars, the

allowable CO2 cost would increase to $0.040/kg ($2.00/MSCF). More efficient utilization of CO2 in

the miscible floods would increase the allowable CO2 costs (Stem 1986): at a flooding efficiency of

260 kg/bbl (5 MSCF/bbl), the allowable CO2 cost would range from $0.040/kg ($2.10/MSCF) to

$0.080/kg ($4.20MSCF).

7
3.0 POTENTIAL CO2 SOURCES FOR MICROALGAE-BASED LIQUID

FUEL PRODUCTION

To be considered a suitable source for microalgae-based fuel production in 2010 and beyond, a CO2

source must be able to supply sufficient quantities at sufficiently low cost to those regions of the

country where fuel production facilities would most likely be located. For microalgae production, warm

sunny climates are needed. This means that the CO2 must either be produced or be cheaply deliverable

to the southern or southwestern United States.

3.1 Natural CO2 Reservoirs

3.1.1 EstimatedReserves

Hare et al. (1978) examined all the natural CO2 sources in the United States. Nearly 90% of the total

domestic supply is located within the borders of four states: Colorado, New Mexico, Utah, and

Wyoming (Figure 3-1). Table 3-1 summarizes the major domestic natural CO2 sources.

ain

---Existing Pipelines

- - - - PIamed Pipelines

Scale: 7.3 nm. 100 mi

Solrces: Taber (1985),

Zinmerman et aI(1979)

GUt

Coast

Figure 3-1. Major natural CO2 reserves

8
Table 3-1. Major Natural CO2 Reserves

TP-3820

Sheep Mountain, CO

McElmo Dome, CO

Bravo Dome, NM

LaBarge, WY

Jackson Dome, MS

Total

Reserves

109 kg

52

438

313

1044

52-157

1900-2000

Capacity,

Current

5.0

5.3

5.2

15.5

109Icg/yrPlanned

9.9

6.1

16.0

aBased on 80% production

Source: Stem 1986

3.1.2 Depletion

As can be seen from Table 3-1, the major natural CO2 reservoirs would be insufficient to meet the

projected daily EOR demand of 360-440 x 106 kg/d, even though they would appear to satisfy the

ultimate projected demand of 1-4 x 1012 kg (Anada et aI. 1982, 1983; Hare et aI. 1978). This is

primarily due to regional mismatches, e.g., essentially all the CO2 demand is in the west Texas

oilfields, but the supply is spread over several nonadjoining states. We can conclude, then, that the

highest purity and closest proximity CO2 sources will be the first developed for EaR, with the more

dilute and more distant sources utilized later. As the demand for CO2 continues to increase, natural

CO2 sources are likely to be drastically depleted; the lack of development of a given CO2 reserve

would indicate only an uncertain geology or some other factor making it uneconomic. But because

natural CO2 supplies are insufficient to meet projected EOR demands, those in the EOR business have

examined potential future sources of CO2, The majority of studies reviewed for this report were

produced from the perspective of EaR supply and demand. The potential annual fuel synthesis

requirements considered here require an even harder look at potential sources of CO2,

3.1.3 EOR CO2 Reuse

One possible source of CO2 in the years beyond 2010 is from depleted oilfields that have been

produced using CO2 flooding. The areas where EOR has been most extensive will become new

underground CO2 reservoirs. Much of the CO2 will remain trapped underground in these reservoirs.

Normally, estimates of both daily and ultimate CO2 demand for EOR projects are based on the ability

of significant portions of the CO2 injected (typically 35%-50%) to be recycled and reused. Assuming

that 20% of the annual projected CO2 used for EOR (40-160 x 109 kg/yr) could be recovered and

reused after the petroleum reserves were depleted, 8-32 x 109 kg/yr could be recovered. We could not

reliably estimate the cost of recovering this CO2; it would likely be at high concentration «90%) and

low to intermediate pressure, and thus cost roughly the same as CO2 coproduced with ethanol (Section

3.3.1).

3.2 Noncommercial Quality Natural Gas

Although most natural gas deposits contain less than 10% CO2, there are significant deposits with

much higher CO2 content. Some deposits contain greater than 50% CO2, which could be too high for

economical development. Reevaluation of these resources would lead to the conclusion that, if the

demand for CO2 and methane (and hence the price) were sufficiently high, then both could be

developed. The mixed gas would have to be treated with one of the conventional processes to

separate the CO2 from the natural gas.

9
TP-3820

3.2.1 Estimated Reservoirs

Zimmerman et al. (1979), utilizing data published by the U.S. Bureau of Mines, constructed a data

base of more than 11,000 analyses of gas samples from oil and gas wells. The analyses were

performed using the Orsat apparatus, a mass spectrometer, and other devices. Using this extensive data

base, the researchers were able to develop plots such as that shown in Figure 3-2. This plot was

constructed on a printer-plot module in such a way that the module indicates the number of data points

falling in one point location; e.g., at the top left comer the number 8 indicates 8 data points with CO2

composition of 100%. One is struck by the huge numbers of data points with >80% methane, and

relatively few points with >80% CO2, The authors attempted to estimate the additional quantities of

CO2 that might be available in reservoirs containing dilute CO2, methane, or both. The plot was

CARBON DIOXIDE MOL %

+---------+---------+---------+---------+---------+---------++

100.0 +8 REGION 1

!S2

!64*<========Sheep Mountain, CO

90.0 '373* (Watson and Siekkinen, 1986)

!*3 * 2

!42 2 REGION 2

83.3 +** *

12 * 1* * *

75.0 ! 3 * 1 2 *

1* * * 66.7 +

!

! ** !

!* * *

REGION 3

* * * * *

!2 ** 2<========Terrell, TX

50.0 + * * (Hillyard, 1980) +

! * * !

! !

!* *2* !

! * * 3 !

! 2 * !

33.3 +2 **.+

! * * 2 !

122 * 2* * 2* !

! * 2 * ***2 !

!* * 3 * * 3* * !

!* 22 * 22 2*** ** 2 * !

16.7 +2 * * *** 2 2* *2 * *** +

!6 3 * * * ** * * * *2*444*3*2 !

10.0 '2 3* * * * * ** ** * * 242 2 ***3222 !

!32* 2* * ** * 3**** * 2 ** 2** 2*2 *5334 3 *32*64 !

!3 ** * ** * 24*2 224* 22*4*44732*2364533A947BH5 I

10**58*4623*22246*5 **2232 5224385685E6A6DB6HKMQVP»»>R»>8 i

0.0 +»CG667BAGHFBBGA778A78CH9IHVPLW»»»»»»»»»»»»»»»!

+---------+---------+---------+---------+---------+---------++

0.0 16.7 33.3 50.0 66.7 83.3 100.0

METHANE MOL %

NO. PLOTTED POINTS 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16.17 18

PLOT SYMBOLS 1 2 3 4 5 6 7 8 9 ABC D E F G H I

NO. PLOTTED POINTS 19 20 21 22 23 24 25 26 27 28 29 30 30 32 33 34 35 >35

PLOT SYMBOLS J K L M N 0 P Q R STU V W X Y Z >

Figure 3~2. Plot of compositions of mixed natural gas/Cf), sources

(Source: Zimmerman et al. 1979)

10
TP-3820

divided into three regions as follows: region 1 contains samples with CO2 content >90%, which

includes those discussed in section 3.1; region 2 contain samples with CO2 content between 75% and

90%; and region 3 contains samples with CO2 content between 10% and 75%. Samples with CO2

content below 10% were not considered, because these samples would already be commercially

attractive.

For all four regions, the number of samples and the weighted average CO2 composition were calculated.

Based on these quantities and from Stem's (1986) estimates in Table 3-1, the total naturally occurring

CO2 was estimated using two different assumptions:

(1) Low-range estimate: known natural CO2 reserves (2.1-1012 kg) assumed to fill regions 1 and 2

(2) High-range estimate: known national CO2 reserves assumed to fill region 1 only.

Figure 3-3 summarizes the estimated COz reserves from these calculations. The total natural CO2 in

noncommercial reservoirs could range as high as 1.3-2.5 x 101z kg. With depletion in 25 yr, 52-

100 x 1Q9 kg/yr of COz could be recovered from noncommercial natural gas sources. This CO2 could

also be used for EOR.

5

4

(\I

8 2

1

o

k:::::::::::::::::::1 Non-eonvnercial(hVl)

Non-eommercial (low)

• Known commercial

C02

Figure 3-3. Commercial and noncommercial CO2 reserves

3.2.2 Separation Cost

Anada et al. (1982, 1983) present detailed technical and economic analyses of purification of CO2

from a variety of sources. Two chemical absorption processes are" compared: one using alkano1amines,

usually monoethanolamine (MEA); and one using a potassium carbonate (K1C03) . The MEA process

is the most widely used for natural gas purification in this country; however, there are indications that

the K1C03 process may have particular advantages when S02 is present. Because this would be

especially important when treating stack gases from coal-fired power plants and cement plants, we will

discuss it in more detail below.

11
TP-3820

Of the three regions of CO2 shown in Figure 3-2, regions 1 and 2 require essentially no treatment

because of their high purity; only compression and drying would be required to upgrade it (as with all

CO~ to pipeline quality. Region 3 requires an entire purification system to upgrade the dilute CO2 to

98+%.

In estimating the recovery and drying costs of this CO2, we used a capacity factor of 80% (300 d/yr),

for a facility size of 35 MMSCFD (1.8 x 106 kg/d). Anada et al. (1982) determined that CO2

recovery cost was quite sensitive to plant capacity, but not so sensitive to recovery efficiency: the

price of CO2 when 60% was recovered was typically only 5% more than when 90% was recovered.

Nonetheless, only one facility size was chosen, in order to concentrate on direct comparison between

CO2 sources of differing concentrations. The recovery and drying costs estimated are summarized in

Table 3-2. The recovery cost for CO2 in region 1 and 2, at concentrations between 75% and 90%,

could not be reliably estimated from the data of Anada et al. (1982). They considered all CO2 above

90% to have zero recovery costs, but did not examine any gas streams with compositions in the 75%-

90% range. Region 3 has lower compression and drying costs because itssystem is designed to use

steam-driven compressors, using excess steam produced in the recovery system. Regions 1 and 2, with

no recovery system, must purchase electric power for their compressors.

Table 3-2. CO2 Recovery and Drying Costs from

Noncommercial Natural Gas (1986 $/kg)

Region'

1

2

3

Recovery Compression and

Costsb Drying Costs

o 0.011

o 0.011

0.049 0.004

Totar:

0.011

0.011

0.053

a Refer to Figure 3-2

b Treatment by K2C0 3 in recovery step

c Based on 1.8 x 106 kg/d (35 MMSCFD) capacity

Source: Anada et al. (1982, 1983)

3.3 Fossil Fuel Combustion

The vast majority of carbon dioxide produced during the next 50 years, a quantity sufficient to meet

not only all projected EOR demands but also all demands for microalgae-based fuel production, will

be derived from various conversions of fossil fuels. These conversions are either direct combustion

(i.e., in the generation of electric power) or production of a commodity chemical (e.g., ammonia).

Most but not all of these conversions represent processes that are currently in commercial use. Other

processes are' likely to be commercially developed, with one objective being the actual enhancement

of CO2 coproduction. We will consider the process plants first, then the electric power plants.

3.3.1 Process Plants

3.3.1.1 Ammonia. The major steps used in the manufacture of ammonia from natural gas were

summarized in Section 2.1.1. For further details, consult references such as Shreve (1977). The

important facts to note are the typical feedstock requirement of 21~OOO SCF of natural gas per ton of

ammonia produced, and CO2 coproduction of about 21,000 SCF per ton (1.2 kg/kg) of ammonia. This

means that essentially 100% of the natural gas feedstock volume actually ends up as CO2 coproduct.

Also note the requirement that CO2 be removed before the hydrogen-nitrogen reaction, to prevent it

from poisoning the nickel catalyst. As a result, a CO2 stream of typically 97.5% purity is produced,

which requires a very minimal treatment system consisting of only compression and drying to upgrade

it to pipeline quality.

12
TP-3820

However, even though ammonia is an important commodity chemical, it would not contribute

significantly to the CO2 demand for microalgae-bascd liquid fuel production. Recent ammonia

production has ranged from 13 to 16 x 1(1 kg/yr (Chemical & Engineering News 1987). This means

that, even if all the domestic ammonia-derived CO2 could be captured, it would amount to just under

20 x 109 kg/yr. Further, urea production averages 5-7 x 109 kg/yr, representing the utilization of

roughly 25% of the annual ammonia and CO2 coproduction (Chemical & Engineering News 1987).

Urea also represents a substantial value added to both the ammonia and CO2, and so would not likely

be displaced by a fuel substance. The greatest amount of CO2 that could ever be available for

microalgae-based fuel production is thus 75% of the annual coproduction with ammonia, or 10-

12 x lQ9 kg/yr. The amount that is actually produced near potential new microalgae-based fuel

synthesis, in the 10 states on the United States' southern border (i.e., Alabama, Arizona, California,

Florida, Georgia, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas), amounts to 8.6 x lQ9

kg/yr. Fully half this potential is in one state, Louisiana.

3.3.1.2 Hydrogen. It is convenient to consider all the refinery operations where CO2 is produced in

this section. Anada et al. (1982) contacted Exxon representatives in Baytown, Texas, who identified

the fluid catalytic cracking regeneration unit and the hydrogen production unit as the sources of

economically recoverable CO2, The hydrogen production unit was discussed briefly in Section 2.1.1.

The similarities between this process and the production of ammonia should again be emphasized,

especially the high purity of the CO2 stream (estimated at 97.5%).

The fluid catalytic cracking unit (FeeD) is much more prevalent in refineries than the hydrogen unit.

Nearly every refinery has an FCCU, while usually only those refineries treating sour crudes require a

separate hydrogen unit. The FeeD uses high temperatures and low pressures to crack heavier, highboiling petroleum fractions into lighter, more reactive materials. Because of the severity of the

cracking process, the catalyst must be continuously regenerated to remove coke formed on its surface.

In the regenerator the coke is burned off to form a mixture of CO and CO2; this mixture is then fed

to a eo boiler where the remaining CO is burned to CO2, The outlet of the CO boiler has roughly

15% CO2 content. CO2 coproduction in the typical FCCU is reported by Anada et al. (1982) as 205

SCF/bbl (10.7 kg/bbl) fed to the FCCD.

The e02 that could reasonably be contributed by refineries (FCCUs and Hz plants) in the 10-state area

of interest is about 50% greater than that available from ammonia plants, totaling 13 x 109 kg/yr. As

is the case with ammonia plants, the potential capacity is fairly well concentrated by state: Texas

would supply nearly half of the total refinery-derived CO2 , and California and Louisiana 20%-25%

each.

3.3.1.3 Cement. Portland cement is produced in approximately equal amounts by one of two

processes: a dry process and a wet process. In the dry process, limestone and sand are crushed,

blended, and fed to a kiln to produce clinkers. The clinkers are produced by heating the raw materials

to drive off CO2 from the CaC03 leaving CaO in a process known as calcination. Gypsum is then

added to the clinkers to form cement. The wet process is similar except that water is added to the

raw materials before grinding and the resulting slurry is then fed to the kiln. The fuel for the kiln is

either coal or natural gas. The combustion products from the kiln mix with CO2 from calcining, and

the resulting exhaust gas is cleaned of particulates before being vented at 300°-400°F.

The primary difference between the wet and dry processes as they apply to CO2 generation is that in

the wet process the water content of the exhaust gas is much higher than in the dry process, over 30%

compared to under 12%. CO2 from the wet process plant will thus require slightly higher drying costs

than that from the dry plant. CO2 content is generally in the range of 21%-29% for either type of

plant, using either fuel source. One other factor of note is the increased energy efficiency in newer

plants versus older ones: Anada et al. (1982) found that plants built after 1963 (i.e., which were

10 years old or less in 1973) could cut their fuel consumption and their CO2 output below that of

13
TP-3820

plants built earlier. CO2 production, CO2 content, and HzO content for the various configurations of

cement plants are summarized in Table 3-3. Only the post-1963 cement plants have been included,

because only they are likely to be operating by the year 2010.

The CO2 quantities that might be recovered from cement plants are greater than from refineries and

ammonia plants combined. In the 10-state area of interest, over 26 x 109 kg/yr of COz could be

recovered from cement plants. About half the CO2 potential is from wet-cement plants, where recovery

costs might be somewhat higher because of the high water content in the flue gas. California and

Texas have the largest cement plant CO2 capacity; about two-thirds of the plants in Texas are wetcement plants, while those in California are divided about evenly between the wet and dry process.

Table 3-3. CO2 Production and Concentration from

Cement Plants (Constructed after 1963)

Type of plant 1Q3 kg CO.jda wt.% COz wt.% H2O

Wet coal 883 25.8 35.2

Dry coal 883 29.3 6.3

Wet gas/oil" 801 23.6 37.3

Dry gas/oil 801 28.6 10.1

a Based on 910 x 103 kg/d (.....1000 ton/d) plant

b Gas- and oil-fired plants of similar age assumed to perform

equivalently

Source: Anada et al. (1982, 1983)

3.3.1.4 Ethanol. Fermentation ethanol represents another potential source of high-purity CO2, but not

in significant quantities. To supply COz to support one quad of microalgae, it would take more than

26 x 109 gal/yr of ethanol production. Ethanol production could grow that drastically only if ethanol

were to become a major transportation fuel. Ethanol from lignocellulosic biomass and agricultural

waste is, however, the subject of continuing research efforts; if significant technological breakthroughs

were to occur, ethanol production could become a significant source of coproduct CO2,

3.3.1.5 Recovery Costs. Recovery costs for CO2 from various process plants were examined by Anada

et al. (1982, 1983). As Figure 3-4 shows, the CO2 from ammonia and ethanol plants is much less

expensive to recover, requiring only compression and drying· costs of $0.009-$0.016/kg

($0.44-$0.84/MSCF), based on plant capacity, while cement plants and refmery effluents require the

recovery step of treatment with :MEA or KZC03• Total costs for these plants range from $0.054-

$0.096/kg ($2.82-$5.00/MSCF), with about 85% going for recovery and the rest for compression and

drying. The lowest recovery cost from an ammonia plant is at a flow rate of 3.2 x 106 kg/d, which

represents the largest ammonia plant in the United States, a 4400 ton/d (4 x 106 kg/d) plant in

Donaldsville, Louisiana.

3.3.2 Conventional Power Plants

Recovery from power plant stack gases clearly represents a major potential source of CO2, As Stem

notes (1986), the supply is stable, reliable, and widely dispersed to minimize transportation costs.

The amount of COz varies with type of fuel burned, and even among different samples of the same

type of fuel. Table 3-4 summarizes the typical quantities of CO2 generated per unit of energy input

(Btu) and output (MWc) , as well as annual estimated CO2 production. The major potential source of

COz is from coal-fired power plants, because of their greater number as well as their higher CO2

production per Btu.

14
0.2 ..------------------,

<D

,... 0.15

·Sfh

0.1

+

0.05

N

8

.

.

.

.,

.

.

.

..

--------------------

TP-3820

Remery FCCUIK2C03

cement (Gas)/K2C03

Cement (CoaI)/tJEA

Anvnonia. Ethanol

Note:To convert $/kg to $IMSCF,

Wtiply by 52. 2.

o

o 0.5 1 1.5 2

Th'~ (~kg/d)

Sou"ce: Anad&. et at(1982.1983)

2.5

Figure 3-4. CO2 recovery + compression costs from process plants

Table 3-4. Coproduction of CO2 with Electricity from Fossil Fuels

(Conventional Power Plants)

Fuel Coal Oil Natural Gas

Heating value (Btu/lb) 12,700 19,600 24,000

(common units) 25 MMBtu/ton 6.4 MMBtu/bbl 1000 Btu/SCF

Liquid/gas density 7.8 lb/gal 0.042 Ib/SCF

CO2 concentration (wt %) 14-15 12 9

CO2 produced (lb COJib fuel) 2.5 3.7 3.0

lb COz/MMBtu 200 160 130

SCF COJMMBtua 1740 1390 1100

SCF COz/bbl 8900

kg COJMMBtu 90.8 72.6 57.4

kg COJMWheb 935 748 591

1986 electric generation

(106 MWl\) 1386 137 249

CO2 (l012 kg/yr) 1.30 0.10 0.15

a Gas density =0.115 lb/SCF for CO2 at 68°F and 1 atm

b Power plant cfficiency » 33% (10,300 Btu in/kwh, out)

Sources: Steinberg et al. (1984); Stem (1986); Anada et al. (1982, 1983); U.S. Department of Energy

(1987)

15
lP-3820

Data from the work of Anada et al. (1982, 1983) on CO2 recovery costs for power plants are shown

in Figure 3-5. The cost difference between the recovery costs for coal and those for natural gas is

primarily due to cost differences in purchased fuel, since heat is required to operate the separation

processes. Low- sulfur coal plants have lower recovery costs than high-sulfur coal plants. The MEA

process appears to be more economical for low-sulfur coal plants, while the K2C03 process is less

expensive in the other cases examined. The costs of compression and drying also vary with plant

capacity and contribute 10%-15% to the total recovery/compression/drying costs.

0.07

Lo-S-CoaJ/K2C03

Lo-8-CoaI/tv£A

Hi-8-CoaJ~

Gas-fi'ed/K2C03

H-S-eoal/K2C03

Gas-fi'ed/tICA

Note: To convert$/kg to S/MSCF.

~by52.2.

2 3 4 5 6

,

.... ,

.......... ' ........, ,,". ........, ........--- .... .-.-...

""';:.~'--====~:::::..:::-::~: .._.._.._.._.._.._.._.._.._..-

1

0.03

0.04

0.02

o

0.05

0.06

Ttl'cqhxJt (..-on kg/d)

SolI"ce: Anada, et .. (1982. 1983)

Figure 3-5. CO2 recovery and compression costs for power plants

There was a recent commercial attempt at recovering CO2 from flue gas (Wiggins and Bixler 1983;

Chemical and Engineering News 1982). Flue gas from twin 50-MW natural gas units at Lubbock,

Texas, was treated with an alkanolamine in a solvent extraction process licensed by Dow Chemical.

The 1100 ton/d (1 x 106 kg/d) CO2 plant is no longer in operation, primarily for economic reasons.

According to a representative of Carbon Dioxide Technology Corp., former operator of the plant, CO2

recovery cost was at least $0.038/kg ($2.00/MSCF), so the process was not economically viable after

the oil price drop of the mid-1980s. There were other problems at the facility, but they were not

directly associated with the CO2 recovery process (Mohun 1988).

3.3.2.1 Domestic Coal Resources. It is reasonable to expect that coal will continue to supply larger

and larger fractions of this country's primary energy, especially in the area of electric power generation.

Figure 3-6 shows the 1985 Demonstrated Coal Reserve Base (DRB), the total tonnage that is

commercially minable (U.S. Department of Energy 1986a). The DRB totals 478 x 109 ton, which, at

25 MMBtu/ton is nearly 12,000 quads. This would be enough to meet the total primary energy needs

of the United States for 160 yr. Montana alone contains 25% of the DRB, with illinois and Wyoming

containing another 15% each.

16
TP-3820

(SotJ'"ce: U.S.D.D.E.. 1986)

LEGEND: Quads (Billion tons)

- >2500 (> 100)

III 1250-2500(50-100)

250-1250 (10-50)

M 25-250 (1-10)

CJ < 25 « 1)

Figure 3-6. U.S. demonstrated coal reserves

3.3.2.2 Year 2010 Projected Electric Generation. The official projections of DOE's Office of Policy,

Planning and Analysis (1983) have been used to estimate the quantity of CO2 that might be produced

from coal-fired power plants in the year 2010. First, state-by-state data for fossil-fired steam-electric

production were tabulated for 1985, the same year as the above ORB data (U.S. Department of Energy

1986b). A total of 18.3 quads of fossil fuels was used by utilities for steam-power generation. The

2010 projection was then developed by taking DOE's mid-range projection of 27.8 quads (total fossil

fuel input) and scaling it down to account for slower than expected growth before 1985 (actual 1985

fossil fuel input was 18.8 quads, compared to DOE's estimate of 20.5 quads). Total projected fossil

fuel input to power production in 2010 was thus estimated at 25.5 quads, of which 24.8 quads

represent steam-power production. Individual state projections were then developed based on their

proportions in 1985 (Figure 3-7).

The total of 24.8 quads of fossil fuel input to electric production is sufficient to supply 2.25 x 1012

kg/yr of CO2 every year. With respect to the areas most likely to be suitable for microalgae

production, the 10 states mentioned in the discussion of ammonia, the projected electric generation

amounts to 8.7 quads, enough to produce 790 x 109 kg/yr of CO2,

3.3.3 Clean Coal Technologies

3.3.3.1 Concentrated CO2 Combustion. Scientists at Argonne National Laboratory (ANL) have

suggested one novel approach to the problem of CO2 recovery from coal-fired power plants. They have

proposed to circumvent the problem of dilute CO2 concentration in the stack gas by separating the

combustion air into oxygen and nitrogen before it is fed to the furnace (Wolsky 1985; Barry et al.

1986). The coal is then combusted with a mixture of pure oxygen plus CO2 and H20 recycled from

the stack. The stack gas, after drying, would contain 95% CO2 or more, with small amounts of SOx

and NOr It would probably be suitable for EOR because of the enormous capacity of petroleum

reservoirs to neutralize and remove SOx and NOx (Taber 1985). The effects of these acids on

17
TP-3820

(Solrces: U. S.D. O. E., 1983. 198&)

Legend (Annual Quads)

• 3.0 0.5-1.0

• 1.5-2.0 1>:10.3-0.5

1.0-1.6 D ,0.3

Total • 24. e Quads

Figure 3-7. Projected year-2010 combustion of fossil fuels for electricity

microalgae production are unknown, but the large amounts of electrolytes required in solution by algae

could mitigate their harmful effects by buffering action.

The proposed ANL combustion scheme, shown in Figure 3-8, attempts to operate the existing furnace

on some mixture of O2 and CO2 exactly as it would run on air. .Evaluation of various CO.j0z ratios

was based on such considerations as flame stability, heat transfer rates, and excess O, requirement.

Early results of their experimental work indicates that a CO.j0z molar ratio of 2.23 performed most

similarly to typical combustion in air atmosphere. It is interesting to compare this ratio with that of

air: 3.76 mol N, per mol O2• Even though the amount of "carrier gas" COz is much less than for air,

the overall combustion characteristics are reasonably similar.

Although researchers at ANL feel it is too soon for definitive estimates of the costs associated with

this type of approach, they do raise some of the critical related issues. First, they feel that the COz

cost is likely to depend primarily on the cost of separating Oz from the air. This is commonly done

through a cryogenic liquefaction/rectification process (Shreve 1977), taking advantage of the normal

boiling point difference between O2 (90 K) and Nz (77 K). Between 10-12 kWh would be required

per SCF of CO2 (0.52-0.63 kWh/kg COz), which is close to 20% of the gross power output of a typical

power plant. To a utility with excess generating capacity, this might look attractive. The utility could

charge itself the incremental operating cost, including an electricity cost substantially below wholesale.

Another option would be to provide storage so that O2 production could be interrupted during peak

hours, when all the power produced would be needed to meet demand. Still another possibility would

involve running the power plant on air instead of COz and O, during peaks; this would obviate the

need for Oz storage. Oz production is estimated to contribute $O.30-$0.50/MSCF ($O.OI6-$O.026/kg)

to the cost of CO2, A further advantage of this process is that, because the COz produced is essentially

pipeline quality, there are no emissions; the cost of SOx and NOx removal is avoided. The utility

18
AIr OxidIzIng Product

- FURNACE . .-

1 ! .

°2 Mixture

TP-3820

95%

02 3%

SOx + NOX..... 2%

ReJect N2

from clr

Recycle CO2 (and H20) replace N2•

keeping flame temperature normal

ReJect H20

from output

Figure 3-8. ANL scheme for concentrated CO2 combustion

could credit itself the avoided cost of SOll and NOll removal. Based on analysis of two potential

versions of federal air pollution legislation, ANL estimated the cost of SOx and NOx removal to vary

from $0-$1.50/MSCF CO2 ($O-$O.078/kg) (Wolsky 1985), with the majority of plants falling in the

range of $0.30-$O.60/MSCF ($O.OI6-$0.031/kg). If this process could be successfully developed. the

avoided costs of NOxremoval might outweigh the costs of installing the additional equipment, resulting

in net positive cash flow.

3.3.3.2 Fluidized-Bed Combustion. In their review of environmental issues affecting the use of coal,

Yeager and Baruch (1987) stress the importance of developing a variety of technological improvements

for the next generation of coal-fired power plants. Fluidized-bed combustion (FBC), in particular, can

drastically reduce SOx and NOx emissions. FBC power plants can be designed to operate at either

atmospheric or increased pressure; the latter type has the advantage of requiring smaller sized

components, allowing for modular in-shop fabrication. The SOx and NOx are captured right in the

boiler by calcined limestone, forming calcium sulfate, which can be easily separated and disposed. The

Electric Power Research Institute (EPRI) is currently sponsoring three FBC demonstration projects of

100-160 MW, one of which involves conversion of an existing boiler and the others addition of new

boilers to existing turbine-generators (Yeager and Baruch 1987). No data are available on CO2

production or recovery costs from these units, but the atmospheric design is likely to be similar to

conventional power plants, while the pressurized design may allow lower recovery costs because of the

high partial pressures of stack CO2,

3.3.3.3 Gasification Based Cycles. Coal gasification represents another viable alternative to the

standard coal combustion practice. Turbine generators can be run on coal-derived gas (either mediumBtu gas or synthetic methane); sulfur removal and CO2 recovery are aided by the high partial pressures

of the gasifier effluent. EPRI has sponsored research on coal gasification for many years, and is one

of the principals in the Cool Water Coal Gasification Combined-Cycle Power Plant, near San

Bernardino, California. This 100-MWe unit, which began operation in 1984, is the world's first

integrated, commercial-scale coal gasification combined-cycle (GCC) power plant (Yeager and Baruch

1987). Based on a large-scale (500-MWe) design of the Cool Water plant, an EPRI-funded study by

Fluor proposed that with only minor design changes significant quantities of CO2 could be coproduced.

19
lP-3820

Figure 3-9 shows the original (the so-called electricity-only) design, and the modified (C02

coproduction) designs (Snyder and Depew 1986). The only difference in the two is the CO2 removal

(plus subsequent drying and compression) step from the gas before it is fed to the turbine generator.

This process is identified as the minimum CO2 production process. A further modification quenches

the gasifier outlet with water, then produces much larger quantities of CO2 with the water-gas shift

reaction. More than five times as much CO2 is produced in this so-called maximum CO2 production

system.

Capital and energy requirements of the coproduction plants were compared to the electricity-only plant.

Because CO2 coproduction reduces the net power output, these plants were scaled up so that their

power production matched that of the electricity-only plant (all these designs were for nominal 500-

MW. capacity). This enabled all the capital and operating costs for CO2 coproduction in both processes

to be broken out, and the incremental CO2 costs calculated independently of power production. Based

on initial commercial operation in 1991, 6% annual inflation, and rates of return typical for a regulated

utility, Fluor calculated the following levelized costs (mid-1985 dollars):

$O.016/kg ($0.85/MSCF) for Minimum CO2 (41.8 MMSCFD or 2.18 x 106 kg/d);

$0.012/kg ($0.64/MSCF) for Maximum CO2 (263.0 MMSCFD or 13.7 x 1()6 kg/d).

These calculations were for a utility-owned, GCC power plant with a required selling price for

electricity of $0.0395/kWh. The CO2 market price at the time of the study was $0.024/kg

($1.25/MSCF). Other scenarios were examined for their effects on power or CO2 selling price. For

example, sale of CO2 at the market price would lower the required electricity selling price to

($0.0285/k.Wh), with no loss to rate payers. If the electricity price remained constant, and CO2 was

sold for the market price, return on common equity could increase from 8.5%/yr to 16.6%/yr (constant

dollars). If the drying and compression. steps were performed by others, the utility's decreased capital

and operating costs would enable it to sell the CO2 for $0.OO7/kg ($O.38/MSCF) versus $O.012/kg for

pipeline quality CO2• Finally, ifa nonutility company owned and operated the entire electricity-Co,

complex and sold its power to a utility at an avoided cost of $O.06/kWh and its CO2 at the market

price of $0.024/kg ($1.25/MSCF), it would achieve constant dollar returns of l1.9%/yr on 100%

common equity.

3.3.3.4 Projected Impact of Synthetic Fuels. DOE has developed projections for synthetic fuels

production through the year 2010. Synthetic liquid and gaseous fuel production from coal in 2010 is

estimated to amount to 5.9 quads, with 2.5 quads for synthetic liquid fuels and 3.4 quads for synthetic

methane (U.S. Department of Energy 1983). The potential CO2 coproduction can be estimated using

portions of the Fluor designs discussed above. In the minimum CO2 production case, the Texaco

gasifier produces a fuelgas consisting of 54 (mol) % CO, 42% H2, and 1.4% CO2, along with Ar and

N2• Instead of being burned, such a gas would be directly usable for hydrocarbon synthesis, with a

suitable C:H ratio (l:1.6) for production of olefins, the most reactive type of hydrocarbon. The

projected 2.5 quads would require a coal input of 111 MM ton/yr. The resulting CO2 coproduction

would be 40 x 109 kg/yr. For gaseous methane synthesis, a shift reaction would be required to obtain

the proper 1:4 carbon:hydrogen ratio to make methane. By converting water molecules to hydrogen,

the shift reaction also causes greater CO2 quantities to be produced, normally in the range of 3.1 SCF

CO2 per SCF CH4 (Nelson 1983). For the projected 3.4 quads of synthetic methane, a total of 220

x 109 kg CO2 would be co-produced. It will also be recalled that gasification produces CO2 of both

high concentration (99+%) and high pressure (2000 psi), which therefore enables it to be fed directly

to pipelines in significant quantities with minimal recovery costs.

3.3.3.5 Advanced Coal Refinery. Given the large domestic coal reserves, and the continuing

technological improvements in coal utilization processes, Yeager and Baruch (1987) introduce the

concept of the advanced coal refinery (Figure 3-10). They suggest that in the 21st century, the

conventional coal-fired power plant will evolve from resource-inefficient, mechanical combustion units

into fully integrated refineries, where power generation is only one element of a much broader resource

processing capability. Such a refinery would produce products serving all sectorsof the economy:

20

TP~3820

residential, commercial (liquid and gaseous fuels and electricity), and industrial (heat plus COz, building

materials, and other useful substances), In addition, process development improvements should enable

cost-competitive recovery of valuable byproducts from the ash.

Coal

Preparation

C02

Recovery

I

I

I

Coal

Conversion

t--- Enhanced oil recovery

t---__-- Fertizer. chemicals

Li<JJid &gaseous fuel and feedstock

r--------__... Heat

Dry

CooIng

........ Fuel

.... ,.' Cel

,:"t ..;.' .. I--------.jl----I~ Electricity

____---.J~: ..: ~~.~ '--_--.-_-----It-------~-u--'~:or

By-prO<iJct

Recovery

----Coal

- - - - - - - Waste stream

.................. Heat

"'on.....1---+----1~ Sulflr

GyPSlm AltnIila

Trace metals Buik:tlg material

Figure 3-10. The advanced coal refinery

3.3.4 CO2 Emissions Controls

The potential for climatic change brought about by the buildup of CO2 in the atmosphere (the socalled "greenhouse effect") has been well documented, but it has so far proven impossible to develop

a consensus among the scientific community regarding many aspects of this problem (Launnann 1985).

In particular, the time frame during which harmful effects might occur depends heavily on future rates

of economic and energy growth; the fraction of CO2 emissions that can be biologically reabsorbed; and

the quantities and effects of other trace gases, e.g., CR., N02, and chlorofluorocarbons (CFC),

Based on laborious studies of the problem, Launnann (1986) has suggested a range of scenarios where

the doubling of atmospheric CO2 content from its pre-industrial level of about 280 ppm to 560-600

ppm could occur as early as 2025, and with increasing probability at any time throughout the following

century. The effects of the resulting temperature increase of 2°-5°C are also debatable, possibly

including longer growing seasons and other effects that might actually be welcomed in some regions

of the world, at least initially. But the long-term effects are likely to include some melting of the

polar ice caps with subsequent severe disruption of weather and, hence, agricultural patterns (Ember

et al. 1986). Laurmann makes the point that, by the time the global warming trend becomes a

problem, its solution could be extremely disruptive to the world's economy, as well as very expensive

to implement.

22
TP-3820

Another study found that, regardless of the longer term effects, a mean temperature rise of 1°C by

2000 would increase the generating capacity requirements of electric utilities (Linder and Gibbs 1987).

Those in southern regions that already have large peak summer loads, primarily air-conditioning, would

be most seriously affected. It was estimated that climate-induced capacity increases for such utilities

could reach 10%-20% of base case (no climate change) increases by 2016. Another significant effect

could be that of stream flow changes on hydroelectric production in those regions that rely heavily on

hydropower (e.g., New York).

One possible result of the major contribution of CO2 emissions to global warming is that the

policymakers would step in and mandate a reduction (or elimination) of CO2 emissions, either by

reductions in fossil fuel combustion or by utilization of CO2 recovery processes. Examination of the

potential policy impact has progressed to the point where some are considering disposal of CO2 by

pumping to the deep ocean, salt caverns, or spent oil and gas wells (Steinberg et al. 1984). Power

requirements for such endeavors would approach 15% of total generating capacity. Further, at 1986

CO2 costs of $0.035/kg ($1.80/MSCF) , the across-the-board mandate of this scenario would increase

electricity-generating costs an average of 75%. Although this estimate was based on liquid pipelines,

which are not the most economical option (see Section 4.0), the CO2 costs are somewhat lower than

those calculated by Anada et al. (1982; see Figure 3-5). Clearly, using CO2 for microalgae-based fuel

production would be preferable to mandated disposal schemes, having a positive economic impact with

minimal disruption of existing conventions.

3.4 Atmospheric Recovery

As the CO2 quantities potentially available from the combustion of fossil fuels dwarf those present in

natural reservoirs, so the quantities present in the atmosphere dwarf even those produced by fossil fuel

combustion. The Handbook of Chemistry and Physics (1979) published an estimate for the mass of

the atmosphere at 5.14 x 1018 kg. Given a CO2 concentration of 510 ppm by weight (330 ppm by

volume), the total CO2 in the atmosphere would be 2.6 x 1015 kg. The likelihood of recovering this

amount is negligible, but the point is that the atmospheric quantities of CO2 are large compared even

to power plants.

The primary obstacle to recovery of CO2 from the atmosphere is its low partial pressure, roughly 0.25

mm Hg at atmospheric pressure. The same principles used in commercial CO2 purification from natural

gas and ammonia could be employed for atmospheric recovery. It is known that CO2 will dissolve in

a dilute K2C03 solution to roughly 10 times the concentration that it will in pure water; in fact, the

CO2 reacts chemically with the K2C03 to form KHC03, which is the most easily metabolized form of

CO2 for many species of microalgae. The type of system designed by Anada et al. (1982) would have

to be significantly modified. Preliminary consideration has yielded two approaches. The first approach

involves changing the absorption tower into something resembling a cooling tower, where large

quantities of air could be contacted with the K2C03 solution, which would concentrate the CO2,

Another approach involves a spray pond with a series of nozzles spraying the K2C03 solution out where

it contacts the air. The advantage of this approach is that large horsepower motors are not required

for air movement; an average wind velocity of 2 mph would cause sufficient air circulation for CO2

absorption into the water. Such a pond would probably require a control system that closely monitored

wind direction and velocity to prevent carbonate losses by shutting down nozzles whose spray would

be blown offsite.

3.5 Anaerobic Digestion

Anaerobic digestion is the biological reduction of biomass or waste material to methane and CO2

under anoxic conditions. The process is generally considered to consist of two stages: the breakdown

of the carbohydrate, protein, and lipid into volatile acids; and the conversion of the volatile acids,

primarily via acetate, into methane. The generalized reaction for the anaerobic digestion of

carbohydrate follows (Klass 1980):

23
TP-3820

If these reactions were the only ones proceeding in a digester, 1 mole of CO2 would be produced for

each mole of methane produced. In actual practice, however, many other substances exist in digesters

because of incomplete conversion; roughly 2 moles of CO2 are produced for each 3 moles of methane,

yielding a product gas with heating values of 500-750 BtujSCF. Anaerobic digestion of biomass and

wastes represents a substantial potential methane source, and incidentally a substantial CO2 source as

well.

It is possible that higher energy costs will improve the competitive economics of anaerobic digestion

to the point that large-scale industrial digesters will be built. The resulting biogas could be burned

directly as a medium-Btu fuel or it could be purified to pipeline-quality by MEA or K2C03 separation

processes. The former alternative might occur first, providing no additional CO2 for microalgae-based

fuel production, but when the latter occurs, significant quantities of CO2 would be introduced to the

marketplace. Klass (1980) estimated that 1 quad of methane would require 13.8 x 106 acre, or 0.6%

of the total U.S. surface area, based on biomass yields of 25 metric ton/ha-yr (11 ton/acre-yr) and an

overall thermal efficiency of 50% in digestion. Coproduced with this would be 35 x 109 kg/yr of CO2

, .

The DOE-sponsored SERI Anerobic Digestion Program is projected to produce 6.6 quads by anaerobic

digestion of methane from biomass and wastes in the year 2010, as shown in Table 3-5 (Goodman

1988). If this methane contained the typical 40% CO2, an additional 130-230 x 109 kg/yr of CO2 could

become available for conversion to microalgal lipids.

The lowest cost estimated for biogas, equal to the lowest ethanol cost of $O.Oll/kg ($0.57/MSCF),

would occur only when high demand forced natural gas pipeline companies to bear the separation costs

themselves. If this did not occur, then the recovery costs for biogas would approach those of, e.g.,

cement plants, up to $O.084/kg ($4.40/MSCF).

Table 3-5. Energy Potential of Fuel Synthesis Using CO2

from Anaerobic Digestion

Methane from CO2 for Fuel

Energy Anaerobic Digestion Synthesis

Source (quad/yr) (109 kg/yr)"

Biomass 3.7 130

Wastes 2.9 100

Total 6.6 230

aBased on 60% methane/40% CO2 product composition.

24
TP-3820

4.0 TRANSPORTATION COSTS

Recovery, drying, and compression costs are not the only costs that must be considered in the

evaluation of CO2 sources for microalgae production. The costs of transporting CO2 from the source

(e.g., power plants) to the microalgae production facility must also be considered. Hare et al. (1978)

and Anada et al. (1982) estimated costs for a range of transportation options, based on potential future

demands of EOR. Hare et al. (1978) evaluated pipelines only, for three designs: supercritical (1400-

2000 psi), subcritical «1070 psi), and liquid pipelines. The cases considered by Anada et al. were

supercritical pipelines, trucks carrying liquified CO2 (300 psia at OaF), trucks carrying saturated vapor

CO2 (l000 psia at 67°F), rail transport, and barge transport.

Both Hare et al. (1978) and Anada et al. (1982) calculated pipeline costs in the same way: they

estimated capital and operating costs, and computed levelized gas costs from a discounted cash flow

economic model. A variety of discount rates were considered, but because 15% was used by both

groups, the data for that discount rate are presented here. Because both groups analyzed a supercritical

pipeline system, their results can be compared directly. Table 4-1 presents a comparison of the line

sizes the two groups used in their studies. Because the investment cost differences (and much of the

annual operating costs) are essentially caused by line size differences, the costs estimated by Hare et

al. (1978) would be expected to be much lower than those of Anada et al. However, the effect of line

size differences is mitigated because of the years in which the cost estimates were performed. The

costs developed by Hare et al. (in fourth-quarter 1978 dollars: Marshall and Swift (M&S) Index of

545.3) were required to be inflated by an additional 32% relative to those of Anada et al. (costs in

first-quarter 1981 dollars: M & S Index of 721.3). All costs presented here have been inflated to

1986 dollars, with a M & S Index of 797.6. Capital cost estimates for the largest size pipeline vary

from $57 MM by Hare et al. (1978) to $79 MM for Anada et al. (1982).

Table 4-1. Comparison of Assumed Line Sizes for

Supercritical Pipelines

CO2 Flow rate

(106 kg/d)

Pipeline Size (in.)

Hare (1978) Anada (1982)

0.5

2.6

6.5

13.0

26.1

8

10

14

18

5

10

16

22

30

Tractor-trailers are commonly used to haul liquid C02~ their insulated steel containers have a maximum

pressure of 300 psi. The cost of liquefaction could be avoided by transporting the vapor form under

high pressure (l000 psi). According to Anada et al. (1982), a 1000 psi trailer could be constructed

using current technology, but none is available. Based on the current design, trailer capacity in either

case is 20,000 kg. The 1000 psi trailer was assumed to cost twice that of the 300 psi trailer. Truck

transport is highly sensitive to labor costs, representing up to half of annual operating costs. Another

40% is accounted for by fuel and maintenance costs. It will be seen that a substantial portion of the

transportation cost of liquid CO2 is accounted for by the liquefaction costs.

Rail transport has the advantage of avoiding an initial capital investment, but it is complicated by other

factors. Among these are the complexity of rail freight rates, the need to lease standard Department

of Transportation (DOT) approved tank cars, the need to locate the microalgae-based fuel production

plant near an existing rail line (if possible), and the greater rail mileage required to connect source with

destination. The latter can be anywhere from 20% to 200% greater than the straight line distance

25
TP-3820

between the two. In their evaluation, Anada et al. (1982) found that no potential EOR sites were

located within 20 miles of existing rail lines; this distance would most likely need to be covered by

truck. A fuel production facility mayor may not have more flexibility in location. The tank cars

(DOT class 105A500W) have a capacity of about 75,000 kg; a typical 1000-ha microalgae facility

would require 9-10 carloads daily (Neenan et al. 1986). Another potential advantage is the possibility

of cheaper rail rates for large, steady volumes of traffic, such as after construction of a new facility.

Rail transport might be suitable as a short-term option or for pilot-scale facilities, before a decision on

large capital expenditures has been made.

Barge transport is feasible only for regions adjacent to navigable waterways, i.e., the Jackson Dome

region of central Mississippi (Figure 3-1), and was not further considered by Anada et al. (1982), since

they focused on the Permian Basin area of western Texas and the Williston Basin area of the Dakotas.

Figure 4-1 presents all the transportation cost estimates developed by Hare et al. (1978) and Anada et

al. (1982), inflated to 1986 dollars as described above. All costs are based on a transport distance of

100 miles; additional estimates that were developed for longer distances are not included here in order

to better focus on the primary cost factors for each mode of transportation. It is easily seen that the

supercritical pipeline is most economical over a wide range of flow rates from 2.6-26 x 106 kg/d

(50-500 MMSCFD). The costs estimated by Hare et al. (1978) are within 10% of those estimated by

Anada et al. (1982) at all flow rates except the highest, where there is a difference of 20%. The

subcritical pipeline design was estimated to be between 50%-100% more expensive than the

supercritical pipeline, over the limited range of flow rates examined; these flow rates were the ones

that Hare et al. (1978) felt to be the most economical based on a preliminary screening. The liquid

pipeline option is clearly uneconomic, because of the costs of the liquefaction plant, which contributed

up to 50% of the capital costs and 50%-75% of the operating costs to the total CO2 transportation

costs.

Costs per 100 miles

--- ..._-- ...... ------,,---

Sou'ces:

(1) Hare et aJ (1978)

(2) Anada at 81 (1982)

*TrueX-iQUid (2)

o Truck-vapor (2)

Pipelines:

Supercritical (1)

Supercrftlcal (2)

SWcriticai (1)

6 l.q.Jid pipeline (1)

Note: To convert kg to MSCF.

divide by 52 .2 .

15 20 25 30

Millionkg/d

10

0.035

0.03

0.025 (I)

1.0

0

0 0.02 I

. «; . i I

I

0.015 I

.. cGL..

.- 0.01 . C\I

0 I

0

0.005

0

0 5

Figure 4-1. Transportation costs for various transportation options

26
TP-3820

At low flow rates such as 0.5 x 106 kg/d (10 MMSCFD), a tractor-trailer system carrying 1000 psi

vapor might be economically competitive, especially for start-up or pilot-plant capacity. Although no

other flow rates were examined by Anada et al. (1982), it would be very difficult to predict the same

economies of scale for truck transport as are realized by the supercritical pipeline. The economics of

transport of the liquid CO2 are similarly uncompetitive to the liquid pipeline. Using Anada et al.'s

(1982) estimate of $0.009/kg for liquefaction costs (which seems to be based on the market price

differential between vapor and liquid CO~, liquefaction accounts for a full third of the transportation

cost of the liquid, and makes it 25% more expensive than that of the high-pressure vapor trucks.

Although tractor-trailer transport of liquid CO2 will continue to be widely used in the food and

chemical industries, the need to minimize transportation costs will probably render this option infeasible

for energy-related industries such as EaR and microalgae-based fuel production.

Now that transportation costs have been estimated for a variety of options, they can be coupled with

the recovery costs discussed in Section 3.0. Then, using the maximum allowable CO2 cost for

microalgae-based fuel production of $0.032-0.054/kg ($1.67-$2.82j11SCF, based on data from Neenan

et al. 1986), we can calculate the longest allowable distance that a given source of CO2 can be

economically transported. These data are plotted in Figure 4-2. For each CO2 source, transportation

costs for supercritical pipelines are calculated, based on the flow rates shown in Figures 3-4 and 3-5.

NC Low cone (10-75"')

FCCU

cement (coal)

Power (gas)

Power (H-S coal)

Power (Lo-S coal)

GeC (~C02)

GeC (Max C02)

o 200 400 600 800 1000 1200 1400

Allowable

Delivered

C02 Cost

D $O.032Jkg

($1 .61IMSCF)

!.:::::m:::::::·:'::~ $0 .054/kg

($2.82/MSCF)

Alowable

Figure 4-2. Allowable transportation distance based on CO2 source

(Source: Zimmerman et al. 1979)

27
TP-3820

At the higher allowable CO2 cost, various sources could be transported a distance of several hundred

miles. Natural sources of CO2 that can be recovered at a concentration of >75% and CO:~ from Gee

power plants of the maximum CO2 production design are clearly the best sources from the standpoint

of allowable distance. The reasons for this are obvious: the high initial concentrations minimize

recovery costs, and the high flow rates minimize per-mile transportation costs, especially for the Gee

case. This case in fact has an estimated economic transportation distance of nearly 1200 miles, which

is sufficient to reach the Permian Basin in Texas from Wyoming.

At the lower allowable cost, the situation is not so promising, nor are there the variety of possible

economic e02 sources. Only the natural high-concentration and maximum e02 production GCe

sources could be transported over 200 miles, and only two others, ammonia plants and minimum e02

production Gee power plants, could be transported over 100 miles. At this lower allowable e02 cost,

some sources drop out altogether, including gas-fired and high-sulfur coal power plants, cement plants,

and dilute noncommercial natural sources, Note that no methane credits are taken in the latter case,

and that the conventional gas and coal-fired power plant calculations are highly dependent on the fuel

cost, as discussed in Section 3.0.

28
TP-3820

5.0 ANALYSIS OF SEPARATION TECHNIQUES

The recovery of CO2 from dilute streams (e.g., flue gas from cement and power plants) was discussed

in some detail in Section 3.0. We placed particular emphasis on chemical absorption processes using

alkanolamines and potassium carbonate. Separation costs are the major cost of recovering CO2 from

these sources. It is worthwhile to consider the entire range of CO2 separation techniques, both commercial and noncommercial, to identify the potential improvements that could be achieved with further

research. Thus an examination of the advantages and disadvantages of each process will be useful.

5.1 Physical Solvents

Physical solvents perform separations by selectively dissolving one gas over all others, then desorbing

the gas in a low-pressure area. Physical solvents are only economical where the CO2 partial pressure

in the source is relatively high, at least 100 psi (Anada et al. 1982, 1983). Compare this with the flue

gas from a coal-fired power plant: at atmospheric pressure and containing 15% CO2, the CO2 partial

pressure is 15% x 14.7 = 2.2 psi, well below the 100 psi minimum. Physical solvents are used

commercially only in the purification of natural gas (Ballou 1978). The major processes used are the

Sulfinol process (using a mixture of alkanolamine, water, and sulfolane, this is actually a combination

physical-chemical solvent process); the Rectisol process (typically using methanol at low temperatures,

e.g., O°C); the Purisol process (using N-methyl-2-pyrrolidinone at 570-1000 psi); and the Fluor process

(using propylene carbonate). These processes could be used commercially for dilute CO2 sources, but

the cost of compression would make them uneconomical.

5.2 Chemical Solvents

As discussed in Section 3.0, the two most commonly used chemical solvents utilized for CO2 separation

are amines, e.g., .MEA or diglycolamine (DGA), or potassium carbonate. Chemical solvents actually

react with the CO2 cbemically tv form another chemical species (e.g., KHC03) ; they are well suited

to CO2 partial pressures as low as 6.89 kPa (1 psia). These processes can also be operated at elevated

pressures; the increased absorption of CO2 into the solvent and decreased steam c;0!:.~~P~8~ ~~

partially offset the higher costs of compression, Alkanolamine processes usually require some sort of

corrosion inhibitors as well. This is especially true as solvent concentrations are increased in pursuit

of higher CO2 loading rates per unit mass of solvent. Schendel (1985) discussed the need for further

improvements in corrosion, loading rates, and energy utilization in chemical solvent processes.

5.3 Membranes

The use of membrane filtration processes for CO2 recovery has to this point been restricted to the

processing of associated gas from oil wells (Stookey and Pope 1985). As with physical solvent

processes, the effectiveness of CO2 recovery depends strongly on CO2 partial pressure. Another

consideration is the trade-off between membrane selectivity and permeability. Selectivity is the ratio

of permeation rates; e.g., of CO2 versus N2• Higher selectivities inevitably, lead to lower overall permeation rates, which in tum require larger and more expensive membrane installations. For flue gases,

two-stage processes would probably be required: the first stage would produce a permeate of 30%-

35% CO2, and would be followed by interstage compression. The second stage could then produce

a 90% permeate. Stookey and Pope believe this scheme to be technically viable, but feel it is likely

to be uneconomic for quite some time, because of compression costs. The continuing growth of

membrane use in associated gas recovery, as well as the upgrading of low-Btu fuel gas to mediumBtu gas, should provide some incentives for further technical improvements.

5.4 Cryogenic Distillation

Using reduced temperatures can modify the relative volatility of mixtures containing CO2 • In theory,

this should make cryogenic separations of CO2 fairly easy, but in practice, certain complications occur

that make such separations more difficult (Holmes et al. 1985). One factor is the tendency of CO2

mixtures to solidify under the conditions one would choose for separation. In particular, solid CO2-

29
TP-3820

CH4 mixtures can be formed at pressures higher than the critical pressure of CH4, so a phase of pure

CH4 cannot be recovered at constant pressure without passing through the solid phase. Similar

problems occur for mixtures of CO2 and N2, although at different temperatures and pressures. CO2 can

be recovered cryogenically from flue gas at high pressures, which would require precompression.

According to Holmes, inlet composition must be at least 20%, and the feed must also be dried.

Another drawback is the presence of 15%-30% CO2 in the residual product; further recycling would

be necessary to increase the overall recovery of CO2, Alternatively, one can take advantage of the

tendency of CO2 to form azeotropes by adding a third component (e.g., butane) to the COZ-N2 or CO2-

CH4 mixture. The distillation can then be operated at higher temperatures and pressures, preventing

freezing and lowering refrigeration requirements. CO2 recovery is increased, and more flexibility of

feed conditions is allowed.

5.5 Electrochemical CO, Carriers

SERI is currently evaluating electroactive CO2 carriers for use aboard spacecraft (Bell et al. 1988).

Preliminary results indicate the potential for very low-energy CO2 transport.

5.6 Separation Energy Requirements

The theoretical and practical (state-of-the-art) energy requirements for separation of CO2 from flue gas

are summarized in Table 5-1. The state-of-the-art data for the chemical solvent processes were calculated directly from the base case and the optimistic designs of Anada et aI. (1982). Both thermal

and electrical energy were included, although for these processes, thermal energy accounts for more

than 99% of the total energy consumption. The actual energy consumed is greater 'than the theoretical

by factors of between 12 and 27, implying that further energy savings could be achieved. Note the

significant energy savings of the potassium carbonate process over MEA, mainly because of lower

operating temperatures. These processes are still about equally employed, proving that energy savings

do not always govern the process economics. The optimistic designs, which incorporate both lower

operating temperatures and lower solvent loading ratios, result in energy savings of 25%-30% compared

to the base case designs.

Table 5-1. Theoretical versus State-of-the-Art Energy

Requirements for Separation of CO:z from Flue Gas

(kWh/kg)

Practical

Theoretical (State-of-the-art)

Chemical solvents:

MEA

base case

optimistic

K2C03

base case

optimistic

membranes

0.05 (work)

0.05 (work)

0.05 (work)

0.05 (work)

0.05 (work)

2.96 (heat)

2.10 (heat)

1.74 (heat)

1.28 (heat)

0.98 (work)

Sources: Anada et al. (1982); Mazur and Chan (1982)

For the membrane system, the energy requirement takes the form of compression work (Mazur and

Chan 1982). Although less energy is required for this process than for the chemical solvent process,

there is still room for significant energy savings. The current state of the art for membrane separation

of flue gas requires high membrane feed pressures: 515 psia or more. Technical improvements in

selectivity and permeability could allow lower operating pressures, lowering the energy consumption

for these processes.

30
TP-3820

6.0 CONCLUSIONS

The results of our study indicate that there are several large sources of CO2 that could support

microalgae-based fuel production. The possible quantities and costs of CO2 are listed in Table 6-1.

The lowest cost sources of CO2 are from systems that produce CO2 at high pressure and in high

concentration. These systems include liquid and gaseous synthetic fuel plants, and gasificationcombined cycle power plants. From these sources, a total of 260-1050 x 109 kg (5.0-20.1 TSCF) per

year of CO2 could be available at a price of $0.012-$0.016/kg ($0.64-$0.85/MSCF). CO2 costs will

be higher or lower because of variations in flow rate, allocation of costs between main product and

CO2, process operating pressures, and other factors. Based on a requirement of 80 x 109 kg COJquad

(1015 Btu) of microalgae-derived liquid fuel, we estimate that sufficient CO2 from these sources is

available to support 3.3-13.1 quads annually of microalgae-based liquid fuel production. Gasificationbased combined cycle power plants have been included in this total, even though only one commercial

plant of this design exists. If this type of plant design gains favor with electric utilities, a significant

portion of the estimated 790 x 109 kg/yr of CO2 could actually be produced.

If these sources were not adequate or available in a particular location, low-pressure, high-purity

sources could be exploited. These sources include recovery from ammonia plants, ethanol fermentation

plants, and depleted oilfields that have been flooded with CO2 in EOR operations. A total of

17-41 x 109 kg (0.3-0.8 TSCF) per year is potentially available from these sources. The costs of

recovering CO2 from these sources range from $0.009-$0.016/kg ($0.47-$0.85/MSCF). This CO2 would

support an additional 0.2-0.5 annual quads of microalgae-based fuel production, bringing the total from

high-purity sources to 3.5-13.6 annual quads.

An additional 321-1159 x 109 kg (6.1-22.2 TSCF) per year of CO2 could be available from high- and

low-pressure dilute streams, primarily flue gas from coal-fired power plants and biomass anaerobic

digestion plants. This quantity, which could be available in a 10-state region in the sunny part of the

United States, is enough to support 4.0-14.5 annual quads of microalgae-based fuel production.

However, except for special cases, e.g., high demand for biogas leading to natural gas pipeline

companies bearing the cost of CO2 separation from biogas, recovery of CO2 from such dilute streams

is expensive, ranging from $0.029-$0.095/kg ($1.50-$5.00/MSCF). For flue gas, the situation is further

complicated by the presence of sulfur compounds. Unless improved separation processes are developed,

these sources may not be economical for microalgae-based liquid fuel production.

31
Table 6-1. Potential Sources of CO2 for Fuel Synthesis in 2010

TP-3820

CO2 Source

Potential CO2

(109 kg/yr)

Estimated Cost

(1986 $/kg) (1986 $/MSCF)

Concentrated, high-pressure sources:

Liquid synthetic fuels plants

Gaseous synthetic fuels plants

Gasification-based combined cycle

power plants

Subtotal

Concentrated, low-pressure sources:

Enhanced oil recoveDfb

Ammonia plants

Ethanol plants

Subtotal

Dilute, high-pressure sources:

Noncommercial natural gas'

Refineries"

Dilute, low-pressure sources:

Anaerobic digestion (biomass)

Anaerobic digestion (wastes)

Cement plants

Fossil-steam power plants"

Subtotal

40

220

0-790

260-1050

8-32

9

< 0.1

17-41

52-100

13

130

100

26

0-790

321-1159

0.012-0.016

0.009-0.016

0.011-0.053

0.054-0.095

0.011-0.084

0.051-0.084

0.029-0.048

0.64-0.85

0.47-0.85

0.57-2.77

2.80-5.00

0.57-4.40

2.78-4.40

1.50-2.50

a Assumes 25-yr depletion

b Based on 20% recycle of CO2 used for EaR

c Includes FCCD and hydrogen plants

d Totals for 10-state region (AL, AZ, CA, FL, GA, LA, MS, NM, OK, TX)

e Based on DOE projections for 2010

Sources: Zimmerman et al. (1979); Anada et al. (1982); DOE (1983, 1987); Nelson (1983)

32
TP-3820

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33
TP-3820

Linder, K.P., and M.J. Gibbs, 1987, Potential Impacts of Climate Change on Electric Utilities: Project

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34
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35
Documpent Control 11. SERI A~~~2~2~3820 age , 2. NTIS Accession No.

DE90000361

3. Recipient's Accession No.

4, Tille and Subtitle

CO 2 Sources for Microa1gae-Based Liquid Fuel

Production

7. Author(s)

D. Feinberg and M. Karpuk

9. Performing Organization Name and Address

Technology Development Associates

12421 W. 49th Avenue

Wheat Ridge, CO 80033

12 Sponsoring Organization Name and Address

Solar Energy Research Institute

1617 Cole Boulevard

Golden, CO 8040]

15. Supplementary Notes

16. Abstract (limit: 200 words)

5. Publication Date

August 1990

6.

8. Performing Organization Rept. No.

10. ProjecVTask/Work Unit No.

11. Contract (C) or Grant (G) No.

(C) HK-8-18045-1

(G)

13. Type of Report & Period Covered

Technical Report

14.

Researchers in the Aquatic Species Program at the Solar Energy Research

Institute are developing species of microalgae that have high percentages

of lipids, or oils. These lipids can be extracted and converted to diesel

fuel substitutes. Because microalgae need carbon dioxide (C02

) as a nutrient,

optimal microalgae growth occurs in CO2-saturated solutions. For this reason,

the authors of this study sought to identify possible large-scale sources of

CO 2 for microalgae-based liquid fuels production. The authors concluded that

several such promising sources exist.

17. Document Analysis

a. Descriptors carbon dioxide, microalgae, liquid fuels

b. Identifiers/Open-Ended Terms

C. UC Categories

244

alternative fuels, global warming

18. Availability Statement

National Technical Information Service

U.S. Department of Commerce

5285 Port Royal Road

Springfield, Virginia 22161

Form No 0069 (6:"m-8!)

19. No. of Pages

44

20. Price

A03