CO2 Capture from Cement Plants and Steel Mills using Membranes

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Separations

CO2 Capture from Cement Plants and Steel Mills using Membranes Richard William Baker, Brice Freeman, Jay Kniep, Yu Huang, and Timothy C. Merkel Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.8b02574 • Publication Date (Web): 26 Sep 2018 Downloaded from http://pubs.acs.org on October 2, 2018

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is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

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Industrial & Engineering Chemistry Research

CO2 Capture from Cement Plants and Steel Mills using Membranes

Richard W. Baker,* Brice Freeman, Jay Kniep, Yu (Ivy) Huang, Timothy C. Merkel

Membrane Technology and Research, Inc. 39630 Eureka Drive, Newark, CA 94560-4805

Prepared for Special Issue of I&EC Honoring Rich Noble

*Corresponding author email address: [email protected]

ACS Paragon Plus Environment

Industrial & Engineering Chemistry Research 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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ABSTRACT Carbon dioxide capture, utilization and storage (CCUS) has been identified as an effective method of mitigating anthropogenic CO2 emissions.

To date, most research and

development has centered on capturing CO2 emitted from coal power plants, as they are the largest point source emitters globally. However, cement and steel plants also emit large amounts of CO2 and are potentially easier targets for a CO2 capture process because the CO2 in their flue gas tends to be more concentrated. In this paper, the feasibility of capturing CO2 from cement and steel plants is examined using currently available membrane technology. Coal power plant flue gas contains 13-15% CO2; cement and steel plant flue gas contains 20-30% CO2; this higher CO2 concentration is useful for all separation technologies, but especially for membranes where separation is strongly dependent on partial pressure driving force. Membrane-based systems can capture 80% of the CO2 emitted from cement or steel production processes at costs of $40 to $50/tonne of CO2 captured. Lower costs are possible if lower capture rates are considered. This makes CO2 capture from these gas streams an attractive first application for commercial membranes recently developed for flue gas treatment.

INTRODUCTION It is now generally accepted that global temperatures are rising and this rise is caused by the emission of CO2 and other greenhouse gases to the atmosphere.1 Almost 40% of CO2 emissions come from the use of fossil fuels in power plants and various industrial processes.2 Replacing the fossil fuels used in power generation with no- or low-carbon alternatives, such as

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564 Cement & Steel Plants

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wind, solar and nuclear power, is underway but will take decades to complete. Moreover, some important industrial processes such as cement and steel production have no feasible way to avoid CO2 emissions. A number of studies have shown that the way to handle this issue is to develop costeffective technologies to capture the CO2 produced in power plants and industrial processes and utilize or sequester it underground.2, 3 Development of such CCUS technology provides a bridge to help the world transition to a clean energy future. The only capture technology currently demonstrated at large scale is amine absorption. Two, full-scale amine CO2 capture plants have been built and are in operation at coal power plants, but there is little enthusiasm to build more. The principle problems are their high cost-ofcapture and the potential for chemical emissions to the atmosphere. The use of membranes has emerged as a promising second-generation capture technology.4-10 Membrane technology, for this application, is at the development stage with several small pilot plants having been built and operated. Based on this experience, membranes are expected to have competitive capture costs, as well as offering significant operational advantages such as: simple flow scheme; smaller footprint; no hazardous chemicals emission, handling or disposal issues; lower water usage; better turndown, and near instantaneous dynamic response; also, the membrane process is powered by electricity so that no changes to the power plant steam cycle are needed. Most of the current U.S. work on CO2 capture has been sponsored by the U.S. Department of Energy (DOE) and has focused on capture from coal power plants. This makes sense given the relative size of CO2 emission sources. Table 1 compares CO2 emissions from power and large industrial point sources. Electric power production is by far the largest source,

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but taken together, cement and steel plants represent about 12% of total CO2 emissions. If future national and global emission targets are to be met, CO2 capture from these industrial facilities will also be needed. Table 1.

Large CO2 Point Sources Worldwide

source

number of sources

electric power plants

4940

cement production

3

emissions 3 6 10 tonnes/yr 10540

average source size 3 6 10 tonnes/yr 2.1

average CO2 concentration (mol%) 12-15%

1180

930

0.8

20-30%

refineries

640

800

1.3

30-40%

iron and steel plants

270

650

2.4

20-30%

petrochemical

470

380

0.8

5-10%

It is possible that the first full-scale membrane capture system will be installed on an industrial CO2 source, such as a cement or steel plant. This is because the CO2 concentration in flue gas from coal power plants is 13 to 15%, while the CO2 concentration of flue gas from cement and steel plants ranges from 20 to 30%. This higher concentration is beneficial for reducing the cost of capture, particularly for membrane processes where separation efficiency is strongly dependent on CO2 partial pressure (and hence CO2 concentration). The benefits of higher CO2 content in industrial flue gases on membrane capture processes have been described previously by a number of groups. For example, in a recent design study, Favre et al. have estimated costs of 75% CO2. At this concentration, compressing the gas to 30 bar and cooling to 25°C is sufficient to cause most of the CO2 to condense. Pure liquid CO2 is removed and pressurized to pipeline pressure of 150 bar by a liquid pump. The off-gas from the condenser containing the non-condensable nitrogen, oxygen and some CO2 is sent to a turbo-expander (not shown in Figure 1) to recover some of the compression energy and to provide some of the cooling for the CO2 condensation step. The gas is then recycled to the front of the second-stage membrane. The design in Figure 1 is based on a simplified flue gas feed and has not been optimized, but the energy consumption of 358 kWe/tonne CO2 captured and a membrane area of 6800 m2/(tonne/h) of CO2 captured are representative of what has been demonstrated with today’s membranes on this type of coal flue gas stream. At 60% capture, the residual CO2 emissions from this coal plant would amount to 0.32 tonne/MWe power produced. This would be similar to the emissions of a natural gas combined cycle power plant. Calculations show that the power consumption and the membrane area required by a membrane process are a strong function of the feed gas CO2 concentration. Some estimates made for the same two-stage membrane design shown in Figure 1 with different flue gas feeds are reported in Figure 2. For comparison, the normalized power consumption of a mono-ethanol amine (MEA) absorption process with different feed gas CO2 concentrations is also shown. The

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amine data is from a MEA pilot plant study conducted by Toshiba at a Chinese steel plant,25 but similar data has been reported by other users of amine technology.

1.2

1.0

Amine

0.8 Normalized energy requirement

0.6

Membrane

0.4

0.2 Blast furnace gas Cement

Coal 0.0 10

15

20

25

30

35

CO2 concentration, %

Figure 2.

The effect of feed CO2 concentration on the normalized energy consumption of an

amine plant and a membrane capture system both producing >99% CO2. The energy use for both of these capture processes at feed CO2 content of greater than 10% are normalized to their individual energy uses for a 10% CO2 feed. The membrane system calculations are for a twostage process with 60% CO2 capture similar to that shown in Figure 1.

In amine plants, a high feed gas CO2 concentration will reduce the size of the first absorption column, and hence the capital cost of the process, but the bulk of the process energy is used in the reboiler of the stripper column and in compression of the separated CO2 to pipeline pressure. Both of these operations are proportional to the mass of the CO2 being captured, so the

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power consumption per tonne of CO2 captured declines only slightly as the feed gas concentration changes from 10-30% CO2. In contrast, the efficiency of a membrane process is much more sensitive to the CO2 concentration in the feed gas.

The permeation rate through the membrane is linearly

proportional to the feed gas concentration. A higher concentration in the feed means less membrane area is needed to remove the same amount of CO2. In addition, a more concentrated feed makes the concentration of CO2 in the permeate higher, which reduces the power consumption of the vacuum units of both membrane stages and the final CO2 condensation step. It follows that membrane processes are much more efficient and economical when treating a feed gas containing more concentrated CO2 as the data in Figure 2 clearly shows.

Selective Exhaust Gas Recycle The sharp increase in efficiency of membrane systems at high CO2 feed gas concentrations is the reason a selective exhaust gas recycle design is such a useful concept.5 The general idea of selective exhaust gas recycle is illustrated in Figure 3. The basic two-stage CO2 separation and concentration process shown in Figure 1 is unchanged, but a new membrane unit is installed on the treated residue gas stream leaving the first membrane unit. The residue gas stream is passed across one side of the selective recycle membrane, while air on its way to the power plant combustor is circulated across the other side of the membrane. There is minimal pressure difference across the membrane, but there is a significant concentration difference. As a result, CO2 and some nitrogen permeate from the treated residue gas into the air stream, while some oxygen permeates in the opposite direction.

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Because the membrane is much more




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permeable to CO2 than oxygen and nitrogen, the principle effect is for CO2 to permeate into the air stream. By using this membrane unit, CO2 is stripped from the flue gas being discharged to the chimney and the stripped CO2 is selectively recycled with the air stream to the combustion process. This in turn increases the CO2 concentration in the combustor flue gas going to the membrane capture system.

Figure 3.

A simplified process flow diagram illustrating the impact of a selective recycle

membrane on a two-stage membrane system. The recycle membrane raises the feed gas concentration from 14.8 to 18%, while simultaneously lowering the discharge CO2 concentration from 6.7 to 3.7% CO2 (80% CO2 capture). Power consumption is reduced by 30 kWe/tonne of CO2 captured. The CO2 condensation column operates at 30 bar and -25°C.

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The higher feed gas CO2 concentration produced by selective recycle reduces the power consumption of the Figure 1 separation process from 358 kWe/tonne CO2 captured to 328 kWe/tonne CO2, while simultaneously increasing the overall CO2 capture rate from 60 to 80% CO2. The required membrane area per tonne CO2 captured increases slightly, but this is not a major cost factor. The membrane processes shown above are being developed by MTR for use at coal power plants under the sponsorship of the U.S. Department of Energy. The economics of the capture processes are a function of the membrane performance and the cost of the membranes and modules needed for these large plants.

Research programs are currently underway to

improve the membranes and to scale-up the capture process for use at coal power plants. However, as shown in the remainder of this paper, with today’s membrane performance and costs, the process already seems economical for some high CO2 concentration industrial gas streams.

CO2 Capture at Cement Plants A typical cement plant produces about one million tonnes/year of cement and the CO2 emissions average between 0.8 to 1.0 tonnes of CO2/tonne of cement produced. Various changes to the production process to reduce CO2 emissions have been suggested, including oxycombustion, chemical looping and post-combustion CO2 capture. The goal of these processes is to bring the CO2 emissions to less than 0.5 tonnes of CO2/tonnes of cement.26-28

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The ~0.5 tonne CO2 target arises because only about 40% of the CO2 generated in the cement plant flue gas is produced by combustion of fuel. The remaining 60% is produced by conversion of limestone to calcium oxide. Cement, when used in construction, picks up CO2 from the atmosphere as a portion of the calcium oxide reconverts to calcium carbonate. This is a slow process but means only the fuel fraction of the CO2 in the exhaust gas is permanently emitted to the atmosphere and must be captured and sequestered to make cement production a neutral CO2 emission process. Cement capture processes achieving greater than 40 to 50% capture over a long time become a negative CO2 emission source and in principal, cement plants fitted with capture systems could be used to offset CO2 emissions from other processes. A simple block diagram of a cement plant fitted with a membrane CO2 capture unit is shown in Figure 4. Limestone, clay and fuel (usually coal) flow from a mixing mill through a series of cyclone fluid bed heating steps before entering a large rotating kiln. The clinker formed in the kiln leaves at 1350°C.

The clinker product is then cooled, mixed and milled with

additional additives to make cement. Hot combustion gases formed in the rotating kiln flow countercurrent to the solids moving through the plant.

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Figure 4.

Schematic diagram of a 1000 tonne/day cement plant fitted with a membrane CO2

capture system.28 The system captures 80% of the CO2 emitted (800 tonnes/day) at an energy cost of 286 kWe/tonne CO2 using 3400 m2/(tonne/h) of membrane. The CO2 condensation column operates at 30 bar and -25°C.

Depending on the fuel and the ratio of limestone-to-air used in the plant, the exhaust gas can contain 25% CO2. This CO2 concentration is about twice that of a typical coal power plant and so it makes cement production a promising application for membrane-based CO2 capture. In the process shown in Figure 4, the exhaust gas contains 1000 tonnes/day of CO2 at 25% CO2, 64% N2, 4% O2, and 7% water. The membrane unit shown has the same general form

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as that described in Figure 1. However, because of the higher feed gas concentration for cement flue gas, the calculated energy consumption per tonne of CO2 captured is only 286 kWe/tonne CO2, and the area of membrane required is only 3400 m2/(tonne/h) CO2 at a CO2 capture rate of 80%. The membrane process, when used on cement plant flue gas, needs half of the membrane area of the coal plant (Figure 1) and uses 72 kWe/tonne CO2 capture less power while achieving a higher capture rate. The economic section that follows, will show the impact of these changes on the cost of capture.

CO2 Capture at Steel Mills A second promising near-term application of membrane capture technology is large steel mills.11 About 30% of the world’s steel is made from recycled scrap using electric arc furnaces. The remaining 70% is made by reducing iron ore in a blast furnace (BF) and then converting the iron to steel in a basic oxygen furnace (BOF). The bulk of the industry’s CO2 emissions come from this second BF-BOF processes. A simplified block diagram showing the main emission sources is shown in Figure 5.29 Total CO2 emissions from a BF-BOF steel mill are about 1.8 tonnes of CO2/tonne of steel produced. The five largest emission points are shown in Figure 5. There are three main steps in the production process. The first step is a series of operations to prepare the raw materials. The ore is ground, sintered and pelletized. Limestone is converted to lime and coal into coke. The off-gas from the coke plant contains H2, CO, CH4, N2 and CO2, and provides the fuel for the lime kiln and the ore sintering operation.

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Figure 5.

Simple block diagram of a blast furnace (BF) and basic oxygen furnace (BOF)

steel production process. Total CO2 emissions are about 1.8 tonnes CO2/tonne of steel produced. CO2 emissions from the five largest discharge points are shown with the CO2 concentration in the gas and the mass of CO2 (kg)/tonne of steel produced.29

In a second step, the prepared ingredients are loaded into the top of a blast furnace while heated air, sometimes enriched with oxygen, is blown in the bottom. Some of the oxygen in the air burns coke to generate heat. At the high temperatures created, a series of reducing reactions occur between the iron ore (Fe3O4) and carbon to produce iron and CO2, CO and other off-gases. The gas from the process is removed as blast furnace off-gas from the top of the furnace. The gas contains ∼20% CO2, ∼25% CO, 2-5% H2 and 50-55% N2. Much of this off-gas is used to fuel

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high temperature stoves which heat the air being sent to the blast furnace. The remaining blast furnace gas, together with any leftover gas from the coke ovens, is used in a steam power plant to make electricity. Blast furnace off-gas is the major source of steel plant CO2 emissions, because the gas contains high levels of CO2 and CO; when burnt with air, the combustion exhaust gas produced contains 25-30% CO2. In a final section of the steel plant, molten iron from the blast furnace is mixed with various additives, depending on the type of steel being made, and some carbon is removed by blowing oxygen through the molten metal. Four of the five main emission streams shown in Figure 5 contain more than 20% and these streams represent 75% of the total CO2 emissions from the steel mill. The streams containing 20 to 25% CO2 are best treated by a two-stage membrane process of the type illustrated in Figure 4. Streams containing more than 25% could be treated by a partial two-stage process of the type shown in Figure 6.

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Figure 6. A simplified flow diagram of a two step-two stage membrane system that can be used to capture CO2 from high concentration feed gas such as that produced by combustion of blast furnace off-gas. The CO2 condensation is at 30 bar and -25°C.

The feed stream for the Figure 6 design is the exhaust gas from the blast furnace hot stoves used to heat the air to the furnace. The Toshiba report25 gives this gas as 28.5% CO2, 2.5% O2, 65.2% N2 and 3.8% H2O, and this composition was used in our calculations. The gas flow is very large, ∼400,000 STD m3/h, containing ∼220 tonne/h of CO2, equivalent to the CO2 produced by a 250 MWe coal power plant. A process design similar to that sometimes used to remove CO2 from natural gas can be used.30 The feed gas is sent to two sets of membrane modules. The first set reduces the CO2 concentration from 28% CO2 to 17% CO2, producing a permeate stream that contains 68% CO2. The second set of modules reduces the CO2 concentration from 17 to 8% CO2. This represents about 80% CO2 capture. The permeate from the second set of modules is then sent to a second membrane stage to produce a twice-enriched permeate that contains 81% CO2. This gas is mixed with the first-stage permeate and both streams are sent to the compression-condensation system that performs the final separation and produces high-pressure liquid CO2. The net result is the process uses about 235 kWe/tonne of CO2 captured while requiring 2780 m2 of membrane/tonne to perform the separation. As with the cement plant example, these energy and capital requirements are much less than those needed for a membrane system treating coal power plant flue gas.

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Process Costs In this section, we will calculate the expected cost of CO2 capture for the cement and steel plant processes shown in Figures 4 and 6. We have used a relatively simple approach for these cost calculations. The analysis considers the capital and operating costs of only the membrane capture process, and is useful for rapidly highlighting the sensitivities for important process design variables. The key assumptions used in our calculations are shown in Table 2. The membrane CO2 permeance and selectivity values used in these calculations are those obtained in earlier field tests with coal flue gas. Membrane performance improvement is an area of continuing development. Higher CO2 permeances have already been achieved in lab tests and this improvement will reduce costs significantly. Increasing the membrane module CO2/N2 selectivity in actual use is also possible, but has a lesser impact on process costs. The membrane skid cost of $50/m2 and module replacement cost at $25/m2 reflects the costs that can be achieved in large industrial membrane applications such as water desalination and nitrogen production from air. The use of large membrane elements; manifolding of feed and product streams; and methods of grouping vessels into easily configurable, transportable and modular skids are also assumed. Table 2.

Assumptions Used in the Design Calculations

category

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value ($)

18


units


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polytrophic compressor, turbo expander, and vacuum pump efficiency

80

%

compressor and vacuum unit cost

1000

$/kW e

refrigeration/cooling system cost

1000

$/kW e

turbo expander cost

1000

$/kW e

membrane CO2 permeance

1500

gpu

membrane CO2/N2 selectivity

25

-

replacement membrane module cost

25

$/m

2

membrane skid cost

50

$/m

2

equipment installation factor

100

%

capital depreciation/interest

12

%/year

cost of power

0.05

$kW e

The compressor, vacuum pump, and turbo expander efficiencies and costs are average values for large gas processing systems. The costs of this equipment shown in Table 2 represent average values for large-scale machines from a survey of suppliers. An average installation factor of 100% has been assumed for all the large equipment items, including the membrane skids. This number is similar to that used in many CO2 capture techno-economic reports.31 However, in practice, the installation multiplier for the membrane equipment is likely to be less. These skids will be manufactured in large fabrication shops and shipped to the plant site as container-sized units, requiring minimal site work to install. The ability to use this type of modular construction in membrane systems is a significant advantage of this technology.

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A breakdown of the cost components for each design is given in Table 3.

Not

unexpectedly, energy is the largest contributor to operating capture cost. Forty percent of the capture cost is the cost of electricity used by the rotating equipment. Interest and depreciation charges make up another 35 to 40% of the cost, and two-thirds of this charge is also related to the capital cost of the power consuming equipment (blowers, vacuum pumps, compressors, turbo expander and refrigeration units). The cost of the membrane skid contributes about a third of the major equipment costs. Based on a three-year lifetime module replacement, membrane module costs are only ~10% of total operating costs. Good membranes are the key component of this technology, but are only a fraction of final process cost.

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Table 3.

Capital and Operating Costs of the Process Designs in Figures 4 and 6

Installed as Retrofits to Existing Cement and Steel Plants. All Costs are Normalized to a $/tonne of CO2 Captured.

system characteristics

cement plant

steel mill

coal power plant

capture unit

capture unit

capture unit

(Figure 4)

(Figure 6)

(Figure 3)

% CO2 capture

80%

80%

80%

net power consumption kW e/tonne CO2 captured*

286

235

328

3400

2780

3300

2

membrane area m /(tonne/h) CO2 captured

capital expenses

($1000/(tonne/h) capacity)

membrane skid, including modules at $75/m

2

255

209

248

compression/vacuum equipment at $1000/kW e

266

215

335

refrigeration cooling equipment at $1000/kW e

20

20

20

balance of plant (direct contact cooler, manifolding to exhaust)

200

200

200

major equipment costs

741

624

803

installation/site work at 100% of major equipment

741

624

803

1482

1248

1606

14.3

11.8

16.4

module replacement (3 year life at $50/m )

6.7

5.5

6.4

operation/maintenance at 3% of capital expense/y

5.3

3.7

4.8

interest/depreciation at 12% of capital expense/y

21.2

15.0

19.3

43.2

36.0

46.9

3

total capital expenses ($10 /(tonne/h) CO2 captured)

operating expenses ($/tonne CO2 captured) power at ¢5 cents/kW e-h 2

total capture cost ($/tonne CO2 captured) *

The net power consumption value is the power consumption of the vacuum pumps,

compressors, refrigeration and cooling equipment, minus the energy recovered by the turbo expansion units.

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The costs reported in Table 3 are for 80% CO2 capture from cement or steel flue gas. As mentioned earlier, based on studies of capture from coal flue gas, membranes are expected to be most cost-effective at slightly lower capture rates (50% - 70%). As shown in Figure 7, this is also true for capture from cement or steel using the Figure 4 or Figure 6 designs. The lowest capture costs are observed at the lowest capture rate examined (50%), and these costs begin to increase steeply at capture rates greater than 70%. Even so, at 80% capture, the costs are in the $40 to $50/tonne CO2 range. If lower capture rates are acceptable, another $10/tonne CO2 reduction in cost can be achieved. These values are significantly lower than estimates for amine absorption plants operating on the same type of gases. Even taking into mind that the costing methodology is relatively simple and that this paper is written by membrane enthusiasts, the numbers are encouraging.

60

55

Cement

50

CO2 captured cost, $/tonne

45

Steel

40

35

30 40

50

60

70

80

90

100

CO2 capture rate, %

Figure 7.

The effect of CO2 capture rate on the CO2 capture cost for cement and steel mill

industries.

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Some Final Thoughts Global climate change caused by CO2 emissions to the atmosphere is now generally accepted as a clear and present danger. Many solutions to the problem have been suggested, and it is likely that more than one option will be needed. All of these solutions have one element in common, they are not cheap. A coal power plant produces about 1.25 MWe of power for every tonne of CO2 emitted to the atmosphere. The value of this power at $0.05/kWh is about $60. CO2 capture, even at the DOE target cost of $40/tonne, is going to have a big impact on the price of coal-produced electricity. The situation is significantly better at cement and steel mills. A cement plant produces about 1 to 1.2 tonnes of cement per tonne of CO2 emitted to the atmosphere. In the U.S., the value of the cement produced is ∼$100-120. If the CO2 can be captured at a cost of $40/tonne, it will have a significant, but not insurmountable impact on cost. Also, as mentioned earlier, the cement produced slowly captures CO2 from the atmosphere. If these negative emissions can be converted into offsetting credits, the net impact of capture on the cement producer can be cut. Steel plants produce about 0.55 tonnes of steel for every tonne of CO2 emitted to the atmosphere. The value of this steel at $600/tonne of steel is about $330. Our calculations suggest that the bulk of this CO2 can be captured at around $40/tonne. It follows that the cost of CCS capture at steel plants could be as low as ~10% of the price of the product. Our conclusion then is that CO2 capture at cement and steel plants is a very promising target for today’s membrane technology.

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References 1.

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Acknowledgements

The work reported in this paper is based on insight gained at Membrane Technology and Research, Inc. while working on U.S. Department of Energy Contract DE-FE0026414.

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Table of Content Graphic

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CO2 Capture from Cement Plants and Steel Mills using Membranes

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