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Carbon Capture and Utilization in the Industrial Sector Pete Psarras, Stephen Comello, Praveen Bains, Panunya Charoensawadpong, Stefan Reichelstein, and Jennifer Wilcox Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b01723 • Publication Date (Web): 31 Aug 2017 Downloaded from http://pubs.acs.org on September 3, 2017

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Environmental Science & Technology

Carbon Capture and Utilization in the Industrial Sector

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Peter C. Psarras,1 Stephen Comello,2 Praveen Bains3, Panunya Charoensawadpong3, Stefan Reichelstein2, and Jennifer Wilcox1*

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1

Department of Chemical and Biological Engineering, Colorado School of Mines.

2

Graduate School of Business, Stanford University.

3

Department of Energy Resources Engineering, Stanford University.

*Correspondence to: [email protected]

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Abstract: The fabrication and manufacturing of industrial commodities such as iron, glass and

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cement is carbon-intensive. A major reason capture of carbon dioxide from flue gases of

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industrial processes has not been widely adopted as a climate mitigation strategy is due to the

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lack of economic incentives for capturing CO2 on a scale that will impact climate. Yet,

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abatement opportunities do exist for the industrial sector, provided the scale of such processes is

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aligned well with CO2 utilization. This is important given that this sector accounts for 23% of

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total global emissions. This work develops a model that examines the full cost of separating,

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compressing and transporting CO2 of various industrial processes (sources), and pairing them

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with appropriate utilization opportunities (sinks). We find that – given the relatively higher

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concentrations of CO2 in flue gases from industrial processes – the full cost of abatement is

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lower than that of the power sector. Further, we find truck transportation is generally the low-

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cost alternative compared to pipeline transport for small volumes indicative of this kind of

ACS Paragon Plus Environment


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capture activity (100 kt CO2/a). We apply this methodology to a regional case study, which

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shows steel and cement manufacturing as having the lowest levelized cost of abatement.

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Introduction: The capture of CO2 from flue gases is viewed as one potential instrument to

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reduce global CO2 emissions. In terms of research, development and deployment, most of the

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existing work on carbon capture has focused on fossil-fuel based power generation (coal and

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natural gas). Yet abatement from industrial emissions has been largely overlooked, ignoring a

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substantial source of carbon dioxide. In 2013, the global industrial sector emitted approximately

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5.5 gigatonnes of carbon dioxide (Gt CO2), or 23% of total global CO2 emissions1 (see Figure S1

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for US breakdown)2. These emissions are the by-product of the production of commodities such

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as glass, cement, ammonia and steel – materials that form the essential fabric of the modern

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economy (2). To date, these commodities have few viable substitutes. Further, unlike the

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electricity sector, where mitigation can be achieved through a shift to cleaner, low-carbon energy

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sources such as wind or solar, there are no economic pathways that lead to zero CO2 emissions

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for most industrial commodity manufacturing. While overall production from such Essential

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Industrial Processes (EIPs) has declined in the US, it is projected to increase globally 45-60% by

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2050 to meet the demands of a rising global population and economic activity 3. We identify the

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following processes (products) as EIPs: aluminum, ammonia synthesis, mixed carbonate use,

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cement, biofuels (e.g., ethanol), ferroalloys, glass, iron and steel, lead, lime, magnesium,

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petrochemicals, phosphoric acid, pulp and paper, refining, silicon carbide manufacturing, soda

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ash production, titanium oxide, and zinc smelting (Figure 1).

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Industrial processes often yield exhaust streams containing higher CO2 content than the

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flue exhausts from fossil-fuel fired electricity production (e.g. coal and natural gas). It is


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generally accepted that there is an inverse relationship between cost of CO2 separation and initial

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dilution of a mixed feed stream

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may offer more economical abatement than what is projected in similar applications within the

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power sector.

4, 5

. As a consequence, carbon capture from industrial processes

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To assess the economic potential of carbon capture applied to EIPs, this study provides a

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cost analysis that aggregates the three major components of the carbon capture supply chain:

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separation, compression, and transport. We estimate the full economic cost, referred to as the

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levelized cost of CO2 separation (in dollars per tonne of CO2 captured). We then employ a geo-

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referencing approach, which links industrial sources to current and potential future CO2 sinks

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(utilization opportunities), to identify least cost pathways for abatement, given a local mix of

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supply and demand 6. The aim is to classify these EIPs based on carbon-capture economic

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viability for carbon capture, which is ultimately a combination of industry- and site-specific

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factors. Overall, our study identifies opportunities for CO2 emission reductions from industrial

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sources. The availability of low cost capture opportunities in a particular region may lead to an

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expanded CO2 commodity market, potentially displacing carbon dioxide production from natural

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reservoirs and/or specialty chemical manufacturing facilities. This replacement would have the

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effect of reducing overall CO2 emissions from an overall economy perspective7. Because prices

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from current CO2 sources such as natural reservoirs and select industrial facilities are low

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($7/tCO2 – $25/CO2)8 public policy in the form of carbon regulations and/or pricing may

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ultimately have to play a supportive role in enabling the kind of market we examine in this study.

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Methods

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Estimating the levelized Cost of CO2 Capture for Utilization: We calculate the full economic

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cost of carbon dioxide capture for utilization by using the general levelized product cost concept

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introduced in Ref.

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per tonne of CO2 of separating/capturing, compressing and transporting CO2. Our model does

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not include storage costs, because our end route is CO2 utilization, not geologic storage. This

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cradle-to-gate approach assigns all costs associated with utilization (e.g., further sweetening for

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use as a feedstock or injection in the case of EOR) to the sink operator. The LCO2 metric

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considers all fixed, variable and capacity related costs, in addition to discount rates and the effect

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of corporate income taxes, that must be incurred in order to deliver one tonne of purified CO2.

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The LCO2 concept is modular by construction and thus can be calculated for each element the

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carbon dioxide value chain (separation, compression and transport). The LCO2 is essentially a

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break-even metric, that is, the average price that would need to be received per tonne of CO2

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over the lifetime of a facility to achieve a net present value of zero on the initial investment in

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equipment and facilities. The three components of the levelized cost of CO2 capture and

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utilization are represented formally as:

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. Specifically, we refer to LCO2 as the levelized cost, measured in dollars

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= + + 87 88

where:

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•

LCS is the levelized cost of CO2 separation from flue gas [$/tCO2]

90

•

LCC is the levelized cost of CO2 compression [$/tCO2]


Eq. 1

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•

LCT is the levelized cost of CO2 transportation [$/tCO2]

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Generally, the cost of separation represents 60-80% of the total LCO2, with the cost of

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transportation being the most variable component based on the distance between source and sink.

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We now describe the calculation of each of these cost components.

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Levelized Cost of CO2 Separation: An inventory of the reactions for each EIP is provided in

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Table 1. These industrial processes can produce exhaust streams with higher CO2 content than

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power generation (typically 4-35% concentration), a factor that lends to a lower theoretical

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minimum work of separation

10

(see Supplemental Information). Though the ratio of minimum

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work to real work (embodied in the second-law efficiency) scales non-linearly with dilution, CO2

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separation costs are generally found to be inversely related to the CO2 purity of the treated

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stream. This principle was first illustrated in the works of Thomas Sherwood, whereby the

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market price of various minerals were shown to scale inversely with concentration of that

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mineral11. Naturally, a single-parameter model is blind to several distinguishing process

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characteristics, such as separation technology or stream impurities. However, in a CO2 separation

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process, the balance of energy consumption (and thus cost) resides in the first steps of physical

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separation and – when applicable – regeneration of the separating agent. For these first-step

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dominant processes, energy and cost is shown to be most sensitive to target dilution, hence the

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effectiveness of the single-parameter Sherwood approach, and its continued use in cost

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modeling.4, 12-14 We expand upon this principle to build a cost model based on current capture

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costs and conditions. Given cost estimates for CO2 capture technologies from power generation,

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we use the Integrated Environmental Control Module (IECM)

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Specifically, the IECM provides estimates for the facility and operating costs (including fuel


15

to calibrate the model.


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costs) of electricity generation and carbon dioxide capture equipment for natural gas combined

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cycle (NGCC), sub-critical pulverized coal (PC) and integrated gasification combined cycle

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(IGCC) systems of various capacities (net power outputs), capture efficiencies and flow rates.

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Based on the methodology described and data provided in the Supplementary Information, these

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model output costs are used to determine the levelized cost of separation, LCS, for each

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combination of generation technology, peak capacity, capture efficiency and flow rate. In this

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study, 24 estimates of LCS (and LCC, discussed in the following page) were generated, based on

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the 3 generation technologies (NGCC, PC, IGCC), 2 capacities each (large and small) and 4

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capture rate (90%, 80%, 70%, 60%). These estimates became the basis for a cost equation using

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a multivariate regression, with LCS as the independent variable and capture rate (%), flue CO2

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concentration (%) and flow rate (tonnes/day) as the dependent variables (see also Supplementary

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Information). The resulting linear estimation yields:

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= 80.94 − 0.25 − 80.63 − 0.0006

Eq. 2

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This relationship is applied to each EIP to estimate LCS, assuming a 90% capture rate. These

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results, together with typical EIP conditions, are summarized in Table 2 and span a range of $0

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per tCO2 (for pure stream capture) to $70 per tCO2. While the cost of separation shows a clear

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inverse relationship with concentration, flow rate plays a smaller role as industrial flow rates are

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comparable in scale and cost of separation is less sensitive to variations in flow rate as CO2

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concentration increases (Figure 2). Note that literature costs of capture may deviate from

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calculated estimates based on differing assumptions regarding cost of capacity, operational costs

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(including fuel and electricity) and operational conditions. Analysis of model sensitivity to


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several factors has been conducted and is presented in SI. Moreover, Sherwood estimates align

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with processes with relatively low energy penalty and should be considered a lower bound in

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instances that deviate from this system design.

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calcium looping – shown to integrate well in cement facilities – against PCC MEA capture.17, 18

16

As an example, compare oxyfiring with

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TABLE 1. Chemistry and scale of US essential industrial processes.a CO2 (Mt/a) Chemistry Process Combinedb 2.79 3.33 2Al O" + 3C → 4Al + 3CO 14.67 24.40 0.88CH& + 1.26air + 1.24H O → 0.88CO + N + 3H 0.48 1.48 Ca/MgCO" + heat → Ca/MgO + CO 65.79 68.22 CaCO" + heat → CaO + CO 40.80 40.80 C3 H4 O3 + yeast → 2C H7 OH + 2CO + heat 2.09 2.13 Fe O" + 2SiO + 7C → 2FeSi + 7CO Fe O" + 2MnO + 5C → 2FeMn + 5CO Fe O" + 2CrO + 5C → 2FeCr + 5CO Glass 1.18 5.34 various components + heat → CO + glass Iron and Steel 2C + O → 2CO 30.71 83.03 3CO + Fe O" → 2Fe + 3CO Lead 0.75 1.06 2PbO + C → 2Pb + CO 18.94 38.37 Lime CaCO" + heat → CaO + CO Magnesium 0.71 0.71 2MgO + C → 2Mg + CO 15.73 80.14 Petrochem. C H& + 3O → 2H O + 2CO H3PO4 1.72 2.72 CaCO" + H SO& + H O → CaSO& ∙ 2H O + CO 121.96 143.33 Pulp and Paper wood organics + O → CO ; CaCO" + heat → CaO + CO 69.34 188.05 Refining CH4."" OG.&" + 0.26O → 0.65CH4.4 + 0.27H O + 0.34CO SiC 0.12 0.12 SiO + 3C → SiC + 2CO Soda Ash 1.40 5.44 2Na CO" ∙ NaHCO" ∙ 2H O → 3Na CO" + 5H O + CO TiO2 1.44 2.47 2FeTiO" + 7Cl + 3C → 2TiCl& + 2FeCl" + 3CO Zinc 0.63 0.69 ZnO + CO → Zn + CO Total 391.25 691.84 a Source: EPA Greenhouse Gas Reporting Program, 2014 Commodity Aluminum Ammonia Carbonates Cement Ethanol Ferroalloys

b

Combined emissions = process + stationary combustion

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Levelized Cost of CO2 Compression: The IECM also provides estimates for the equipment and

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operating costs required to compress separated CO2. It is understood that the CO2 product is H2O

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saturated and compression costs include dehydration. To calculate the LCC as a function of

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capture efficiency and flow rate (similar to the calculation of LCS), the procedure for NGCC, PC

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and IGCC outlined above is repeated, however this time with compression equipment present.

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The capacity and operational costs calculated for separation are subtracted from the

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corresponding values that include both separation and compression costs. Using the total mass of

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CO2 separated for each calibrating case, we determine the LCC. Finally, in the same approach

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using a multivariate regression the resulting relationship to each EIP, the levelized cost of

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compression is determined. Results show a range between approximately $4 per tCO2 and $10

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per tCO2.

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TABLE 2. Minimum work and Sherwood-derived separation/capture cost estimations for various industries. Source Aluminum Ammonia Carbonates Cement Ethanol (biofuels) Ferroalloys Glass Iron and Steel

Lead Lime Magnesium Petrochemicals Pulp and Paper

CO2 Content (mol %)a

Ref.

Min. Work Estimated Cost (US$/tCO2 (kJ/mol CO2 Captured) b Captured)

4 – 10 6, 19, 20 8.2 – 10.8 30 – 99.9+ 22 0.0 – 5.0 20 24 6.2 14 – 33 25, 26 4.7 – 7.3

45.8 – 65.6 0.0f – 29.0 36.0 28.1 – 39.2

99.9+ 8 – 10 7 – 12 20 – 27

29 31-33 31, 34 25, 35

0.0 8.3 – 8.9 7.7 – 9.3 5.5 – 6.2

0.0f 46.3 – 50.6 44.4 – 54.9 31.4 – 34.2

15 20 15 30 – 99.9+ 8

38 31 31, 39 35, 40 41

7.1 6.2 7.1 0.0 – 5.0 8.9

40.5 34.4 40.7 0.0f – 28.6 48.0


Literature Estimates (2016 US$/t CO2 Captured) 68.2c,d – 76.3c,e 21.2c,g 57.3c,g, 68.4c,g, 54.8h – 95.3i, 12.7j

Ref. 21 23 23, 27, 28 30

21.7k – 24.4k, 23, 36, 37 32.6l – 44.0l, 57.3c,g

31.1m – 35.0m 61.7n

42-43

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Refining

3 – 20

44, 45

6.2 – 11.7

33.5 – 70.4

Silicon Carbide Soda Ash TiO2 Zinc Natural Gas Petroleum Coal

8 36 – 40 13 15 3–5 3–8 10 – 15

48 49 50 38 10, 40 10, 25 40, 52, 53

8.9 4.0 – 4.4 7.5 7.1 10.3 – 11.7 8.9 – 11.7 7.1– 8.3

51.4 25.6 – 26.7 41.2 40.2 57.2 – 69.9 47.0 – 69.0 36.5 – 42.7

a

44.8o, 57.0p 92.8q

45-47

76.3r

51

37.1 – 54.6s

54

Range in composition due to different processes or different capture points within the same process. When not directly reported, values were

estimated from a complete mass balance assuming NG fuel and 15% excess air; b calculated assuming 99.5% purity and 90% capture, Ref. 10; c includes cost of compression; d calculated at 10% CO2 purity; e calculated at 4% CO2 purity; f for near pure streams, separation costs are considered in the compression and dehydration stage; g includes costs for transport and storage; h oxycombustion; i post-combustion MEA; j includes compression and dehydration; k selexol capture from the blast furnace; l post-combustion capture from blast furnace; m capture using precombustion shift technology; n amine capture from boiler; o PCC from gasifier exhaust; p SMR with CCS, cost avoided; q PCC on combined stack (9% CO2), cost avoided; r MEA PCC, 90% efficiency, cost avoided; s PCC from supercritical pulverized coal, includes compression.

158 159 160

Levelized Cost of CO2 Transportation: Generally, there are two methods of transport: pipeline

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and tanker delivery (trucking). Transport via rail could be viable if the source and sink were

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located proximal to railheads, though economics rarely prove favorable over short distances (
6250

Sink Demand (kt CO2 ) 500 250 0.0

Figure 1. National distribution of essential industrial processes. Graduated symbols denote potential CO2 capture volume (at 90% capture rate).



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Figure 2. Prediction of capture costs from power (black circles) of varying gas flow rates (low to high). This data is used to predict levelized costs of capture for several irreplaceable industries (colored circles and diamonds). Not shown are cost points for streams of 99.9+% CO2 purity, for which the cost of capture is assumed to approach zero.

CO2 Sinks Plastics/Polymers Manufacturing Fire Proo ng Refrigeration Industrial Gas Manufacturing Beverage Carbonation Enhanced Oil Recovery Soda Bicarbonate Manufacturing Urea Manufacturing Gum and Wood Chemicals

Sink Demand (kt CO2 per year) < 150 150.01 – 600 600.01 – 1200 >1200

Source Output (kt CO2 ) 15,000 5,000 0.0


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Figure 3. National distribution of CO2 utilization opportunities. Graduated symbols denote CO2 demand. Enhanced oil recovery dominates demand but is geographically isolated from industrial emitters in the Northeast and West coast, where smaller scale opportunities may play a more prominent role. 369

Figure 4. LCO2 and relative quantity delivered to sinks, PA case study. 370 371 372

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