Fuel 104 (2013) 561–574

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Fuel

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Energy penalty of CO2 capture for the Carbonation–Calcination Reaction (CCR)Process: Parametric effects and comparisons with alternative processes

William Wang, Shwetha Ramkumar 1, Liang-Shih Fan ⇑William. G. Lowrie Department of Chemical and Biomolecular Engineering, 140 W 19th Avenue, 125 A Koffolt Labs, The Ohio State University, Columbus, OH 43210, United States

h i g h l i g h t s

" The CCR Process has a lower energy penalty compared to other processes." Thermal energy efficiency is the most sensitive parameter to energy penalty." Energy penalty is sensitive to CO2 compression and insensitive to ASU energy." The CCR Process provides flexibility in electricity output.

a r t i c l e i n f o

Article history:Received 19 December 2011Received in revised form 24 April 2012Accepted 26 April 2012Available online 21 May 2012

Keywords:CarbonationCalcinationHydrationCCRCO2 capture

0016-2361/$ - see front matter � 2012 Elsevier Ltd. Ahttp://dx.doi.org/10.1016/j.fuel.2012.04.043

⇑ Corresponding author. Tel.: +1 614 688 3262; faxE-mail address: fan.1@osu.edu (L.-S. Fan).

1 Currently with ExxonMobil Company.

a b s t r a c t

Process simulations of carbon capture technologies typically examine a limited number of cases and pro-cess variables. In many instances, processes are modeled under the most favorable conditions to improveprocess performance. With no universal standards defined for important parameters such as energyrequirements for carbon dioxide compression and air separation, carbon dioxide purity, and base plantefficiency, great variability can exist during process analysis. This publication is presented in sequel toan earlier study on the Carbonation–Calcination Reaction (CCR) Process, which uses a cyclic calciumcarbonate–calcium oxide–calcium hydroxide reaction scheme. While the first paper focused on the effectof internal parameters, this follow-up publication focuses on the external parameters of coal rank, baseplant efficiency, heat transfer efficiency, compression energy, and air separation energy to determine thecontribution of each to the overall energy penalty. In addition, novel integration options are introduced,effect of the CCR Process on boiler performance is analyzed, and a sensitivity analysis is performed. Spe-cifically, the ASPEN Plus simulations focus on the difference between ideal and realistic conditions. Thecomprehensive simulations allow for a direct comparison of the CCR Process with other processes devel-oped for post-combustion carbon dioxide removal from coal combustion under normalized conditions toremove the effect of external variables. The comparison indicates that the CCR Process always provides alower energy penalty under similar operating conditions.

� 2012 Elsevier Ltd. All rights reserved.

1. Introduction

Fossil fuels, namely coal, natural gas, and oil, are currently thedominant source of energy used for electricity generation in boththe United States and worldwide. Within the United States, fossilfuels are used to generate approximately 70% of the electricity with45% derived from coal [1]. Worldwide, electricity generationsources are similar to the United States. Nearly 70% of the world’selectricity is derived from a fossil fuel source with coal accountingfor 41% of the world’s electricity generation [2]. While coal utiliza-tion comprises a significant fraction of total electricity generation,

ll rights reserved.

: +1 614 292 3769.

it is also responsible for 43% of the world’s carbon dioxide emis-sions [2]. With increasing concern over carbon dioxide emissions,current efforts are focused on processes that can economicallyand efficiently reduce carbon dioxide emissions to the atmosphereusing coal for electricity generation.

Currently, pulverized coal combustion is the principal technol-ogy for electricity generation from coal. Pulverized coal (PC) powerplants represent 99% of all coal-fired power plants in the UnitedStates and over 90% worldwide [3]. With an average thermal toelectric efficiency of 32% (HHV), the efficiency of the United Statescoal fleet is relatively low given the thermodynamic maximum isapproximately 63% based on the Rankine steam cycle [4]. The prev-alence of PC plants for electricity generation and their low operat-ing efficiency leads to considerable carbon dioxide emissions. Forthat reason, the development of post-combustion carbon capture

562 W. Wang et al. / Fuel 104 (2013) 561–574

technologies is required if the goal is to reduce anthropogenic car-bon dioxide emissions. The properties of flue gas from coal com-bustion pose several key challenges that are common to allcarbon capture processes and include a large total volumetric flowrate, dilute concentration of carbon dioxide in the flue gas stream,and existence of impurities [5]. In addition, existing coal-firedpower plants have further restrictions, such as size constraintsand operating conditions necessary for optimal performance, thatincreases the difficulty of developing post-combustion technolo-gies for carbon dioxide (CO2) capture suitable as a retrofit.

The existing options for post-combustion carbon dioxide cap-ture include the use of solvents, typically in the form of amines,oxycombustion, membranes, and solid sorbents [6–8].

Amine-based solvents, such as monoethanolamine (MEA), havebeen used for acid gas conditioning for several decades and arewidely considered as the process most prepared for large-scaledeployment [7,9,10]. However, amine-based solvents are corrosive,susceptible to degradation, and will increase the cost of electricitybeyond targets defined by the United States Department of Energy[9,11]. Oxycombustion is a relatively new concept that replaces airwith oxygen for coal combustion. The products of oxycombustionare primarily carbon dioxide and water, which can be easily con-densed to generate a highly pure CO2 stream. Air infiltration,oxygen purification, boiler performance, and process economicsall pose challenges requiring further research and development[6–8,12]. The selection of membranes that currently exist are notwell-suited for post-combustion CO2 removal due to the propertiesof flue gas. The potential for a low-cost, low-energy, high efficiencymembrane exists but further development is necessary to addressstability issues, low selectivity, permeability degradation, and pooreconomics [6,13]. Two types of solid sorbents are being developedbased on either physical or chemical sorption. Based on experi-mental results, process simulations, and economic analyses, solidsorbents show great promise for CO2 removal from flue gas[13–15]. However, several key challenges require resolution priorto large-scale demonstration and include solids circulation, attri-tion, sorbent regeneration, and heat management [16,17].

The Carbonation–Calcination Reaction (CCR) Process is one suchprocess that utilizes solid sorbents, specifically calcium hydroxide.Developed at The Ohio State University, the CCR Process utilizes acalcium carbonate–calcium oxide–calcium hydroxide cycle forsimultaneous CO2 and sulfur removal. The CCR Process has beenexperimentally verified to remove 90% CO2 at a Calcium:Carbonmol ratio of 1.3 over multiple cycles at the 120 kWth scale from acoal and natural gas co-combustion feedstock [18]. The initial pro-cess simulation studies investigated multiple parameters intrinsicto the CCR Process such as solids circulation, materials consump-tion, and calciner energy requirements under varying purge per-centages and particulate capture device efficiencies for a singlecoal-fired boiler [19]. The solids circulation was shown to be com-parable to existing FCC technologies, which shows the feasibility ofthe commercial-scale reactor design for the CCR Process [19]. Thehigh-reactivity of calcium hydroxide also allows for minimizingthe amount of fresh feed and thermal input to the calciner, bothof which lowers the operating cost, along with reduced reactor size,which lowers the capital cost. This follow-up study investigates theeffect of external variables upon the energy penalty and provides astandard basis for comparing process energy penalty under equiv-alent conditions such that the energy penalty comparison is due so-lely to the carbon capture process.

Within the United States, coal-fired power plants vary widely intheir base net plant efficiency and coal rank used for combustion[20]. Both factors will have an effect on the energy penalty. Further,no standard energy requirements have been established for cryo-genic air separation and CO2 compression. These factors are exter-nal to the carbon capture process yet have a significant impact on

the overall energy penalty where an absolute energy penalty rangeof 5% can be obtained between the highest efficiency and lowestefficiency conditions. Sections 4.2, 4.4, and 4.5 further examinethe effect of the external parameters.

Calcium-based sorbents have been extensively used for removalof acid gases present in a coal-fired boiler. The most recent tech-nologies have focused on CO2 removal using either calcium oxideor calcium hydroxide, which can simultaneously reduce the con-centrations of additional acid gases as described in Section 4.3.Regardless of the sorbent, the high-temperature reactions that oc-cur with a calcium-based CO2 capture process allows for additionalelectricity to be generated. Two factors limit the extent of addi-tional electricity generated. First, additional electricity generationwill create an additional load that will require modification tothe steam turbine cycle. This can be achieved by increasing theload to the existing steam turbine cycle, if possible, decreasingthe boiler load, or re-routing thermal energy to a compatible boiler.Section 4.1 further explores the possibilities. Second, the high-tem-perature heat streams will contain a significant amount of solids.The total amount of heat that can be transferred under high solidsloading will limit the thermal extraction efficiency and is exploredfurther in Section 4.2. The simulations, analysis, and results fromthis second paper in sequence clearly demonstrate the importanceof energy penalty comparisons under realistic and equivalent oper-ating conditions.

2. Calcium-based processes

2.1. Limestone-based process development

The cyclic use of limestone for CO2 removal initially began in the1970s with the CO2 Acceptor Process, which used calcined lime-stone to remove CO2 from the water–gas shift reaction and wasregenerated by combusting residual char from the gasifier in a sep-arate reaction vessel [20,21]. More recent developments include theZero Emission Coal Alliance Process (ZECA) and HyPr-RING, both ofwhich involve the removal of CO2 from the water–gas shift reaction[22–25]. In the ZECA Process, hydrogen is used for coal gasificationto produce methane, which is used to produce hydrogen and CO2

through steam-methane reforming. The process has been devel-oped and analyzed but no large-scale demonstrations have beenconducted. HyPr-RING is similar to the CO2 Acceptor Process. Inthe HyPr-RING process, CaO is injected with coal and steam into agasifier where CaO hydration, steam gasification, and hydrogenproduction occur [24,26]. Bench-scale studies are still on-going[26].

2.2. CaO/CaO3 process

A traditional calcium oxide/calcium carbonate (CaO/CaCO3)process utilizes naturally occurring limestone in a repetitive cycleto separate and sequester carbon dioxide from the flue gas of acoal-fired power plant as shown in Reactions (1) and (2) givenbelow:

CaOðsÞ þ CO2ðgÞ ! CaCO3ðsÞ DH� ¼ �178 kJ=mol ð1Þ

CaCO3ðsÞ ! CaOðsÞ þ CO2ðgÞ DH� ¼ þ178 kJ=mol ð2Þ

The carbonation reaction, Reaction (1), is an exothermic reactionoccurring between 500 �C and 650 �C for reasonable kinetics and90% CO2 removal from a coal combustion flue gas stream. The cal-cination reaction, Reaction (2), is the reverse of Reaction (1) and oc-curs at temperatures greater than 900 �C in an atmosphere of pureCO2. When integrated into a coal-fired power plant, high-qualityheat can be extracted from both reactions to generate additional

W. Wang et al. / Fuel 104 (2013) 561–574 563

electricity via additional steam generation and for general heattransfer purposes. The heat of reaction can be directly extractedfrom Reaction (1) since the reaction is exothermic, and latent heatcan be recovered from Reaction (2) by cooling the products. SinceReaction (2) occurs at a temperature greater than Reaction (1), itis not possible to transfer the exothermic heat of (1) to the endo-thermic reaction of (2). The energy for Reaction (2) is typically pro-vided through oxycombustion of a fossil fuel, which allows for ahighly pure stream of CO2.

The calcination of limestone (CaCO3) has been occurring forcenturies, mainly for use in the construction industry [27]. Morerecently, the industrial sector has dominated the use of lime(CaO) [28]. Between the construction sector and industrial sector,a significant amount of research has been performed on limestonecalcination and its subsequent byproducts, lime and hydrated lime(calcium hydroxide, Ca(OH)2). The commercial-scale equipmentenabling limestone calcination has been developed, while lab-scaleresearch has examined the physical transformations that occurduring calcination over a wide range of conditions [27]. Whileimpossible to predict the product reactivity, it has been well-estab-lished that the high-temperature calcination reaction necessarilyinduces thermal sintering of the calcium oxide product under typ-ical operating conditions [29–33].

When using calcium-based sorbents in a CO2 capture process,the raw material is limestone. Following calcination, the producedlime is then exposed to CO2 in the flue gas for carbonation, andReactions (1) and (2) occur in a cyclic fashion, as shown in Fig. 1.The carbonation reaction has been studied extensively for cyclicbehavior and always concluded that thermal sintering of the cal-cined CaO leads to a natural decay in the capture capacity of lime-stone towards CO2 over multiple cycles [34–41].

For post-combustion CO2 control, the CaO/CaCO3 process can bean effective means of removing CO2 from flue gas, based on exper-iments, simulations, and economics. However, the operating per-formance of the CaO/CaCO3 process is far from ideal. Under idealconditions, a 1:1 Calcium:Carbon (Ca:C) mol ratio relationship ex-

Fig. 1. Schematic of a CaO–CaCO3 process.

Fig. 2. Pilot-scale facility of 1.7 MWth demonstration (left) and dua

ists, which translates to a Ca:C mol ratio of 0.9 for 90% CO2 re-moval. Based on experimental results in a 30 kWth test facility, aCa:C mol ratio greater than 8 is necessary for 90% CO2 removalwhen using dual fluidized beds for carbonation and calcination[42,43]. Even though a high solids circulation rate is necessary inthe CaO/CaCO3 process, a low energy penalty and promising preli-minary economics have been obtained [44–46]. The results haveled to the construction of a 1.7 MWth pilot scale facility in Spainto demonstrate the CaO/CaCO3 process at an existing circulatingfluidized bed power plant. Known as the CaOling Project, the goalof the pilot-scale facility is to validate the results of prior bench-scale work and provide data for future scale-up [47]. A generalschematic of the reactor set-up as well as an image of the pilot-scale facility are shown in Fig. 2 [48].

Overall, the CaO/CaCO3 process can be an economical pathwayfor carbon capture and storage from a coal-fired power plant; how-ever, the significant deviation from ideality necessarily increasescosts and complexity.

2.3. Sorbent reactivity improvement

Several methods to increase the long-term reactivity and stabil-ity of CaO have been attempted. Doping of CaO, solid supports, andreactivation techniques are all currently under development andrefinement [49–54]. One promising method, based on both exper-imental results and process simulations, for the removal of CO2

from a coal-fired power plant flue gas utilizes calcium hydroxideformed through the hydration of calcium oxide [18,19,55,56]. A po-sitive feature of CaO reactivation through hydration is the exten-sive research that has been completed, which reduces theremaining research necessary for implementation. The hydrationreaction, shown in Reaction (3) given below, is a commercial pro-cess with a detailed understanding of process chemistry:

CaOðsÞ þH2O ! CaðOHÞ2ðsÞ DH� ¼ �109 kJ=mol ð3Þ

The CCR Process, developed at The Ohio State University, utilizescalcium hydroxide as the sorbent for the carbonation reaction.The individual unit operations comprising the CCR Process alongwith a block flow diagram have been detailed elsewhere [19].

By using calcium hydroxide as the solid sorbent instead of cal-cium oxide, the CCR Process is an improvement over the CaO/CaCO3

Process. A 120 kWth facility has been constructed at The Ohio StateUniversity and demonstrated that a 1.3:1 Ca:C mol ratio canachieve 90% CO2 removal using a coal and natural gas mixture asthe feedstock [18]. The CCR Process combines the superior reactiv-ity of Ca(OH)2 compared to CaO with the unique physical and chem-ical properties of Ca(OH)2 to produce an effective process toseparate CO2 from a flue gas stream. Prior research has demon-

l-fluidized bed reactor set-up (right) (adapted from Ref. [48]).

564 W. Wang et al. / Fuel 104 (2013) 561–574

strated the superior reactivity of calcium hydroxide compared withcalcium oxide towards acid gases such as SO2 and CO2 [18,57,58].Steam reactivation of CaO as a means to enhance sorbent reactivityhas also been studied and concluded that hydration improves sor-bent reactivity [59–62]. With a mean particle size of less than10 lm, which is achieved through the initial hydration reactionmechanism, particle attrition during solids circulation is anon-issue. The small particle size also improves sorbent reactivityby providing a large surface area to volume ratio. With the appro-priate reactor and overall process design, the positive attributesof calcium hydroxide as a sorbent can be used to construct a highlyefficient post-combustion CO2 capture process.

The wide variations in calcium-based processes allows for greatflexibility in process design. While all processes begin with calciumcarbonate, the actual sorbent for CO2 capture can be modified toimprove sorbent reactivity. The carbonator reactor has onerequirement-vigorous gas–solid contact-and can be achieved witha number of fluidized bed reactor designs. The calciner also hasonly one requirement-the production of a highly pure CO2 gasstream-and can be achieved with either a direct-fired or indirect-fired calciner operating with any number of fuels, including, butnot limited to, coal, petroleum coke, and natural gas [54,63–66].

3. Aspen simulation methodology

3.1. Base power plant

The combustion of three typical US coals was modeled usingAspen Plus 2004.1 produced by AspenTech. The composition of

Table 1Composition of Pittsburgh #8 coal.

Proximate analysis Wt.% As-received Wt.% dry

Moisture 5.2Fixed carbon 48.1 50.7Volatiles 38.1 40.2Ash 8.6 9.1HHV (BTU/lb) 12,540 13,228

Table 2Composition of Illinois #6 coal.

Proximate analysis Wt.% As-received Wt.% dry

Moisture 11.12Fixed carbon 44.19 49.72Volatiles 34.99 39.37Ash 9.70 10.91HHV (BTU/lb) 11,666 13,126

Table 3Composition of Powder River Basin coal (Spring Creek).

Proximate analysis Wt.% As-received Wt.% dry

Moisture 24.1Fixed carbon 32.7 43.1Volatiles 38.9 51.2Ash 4.3 5.7HHV (BTU/lb) 9190 12,110

Pittsburgh #8, Illinois #6, and a Powder River Basin (PRB) coal isshown in Tables 1–3, respectively. The choice of coals will allowfor an accurate analysis of energy penalty due solely to the post-combustion CO2 capture process by removing variations in coalrank, power plant efficiency, and additional electricity consumingequipment that may be necessary such as Air Separation Units(ASUs) and CO2 compressors. The databanks, global property meth-od, property models, and coal combustion process have been de-tailed elsewhere [19].

The baseline subcritical pulverized coal-fired power plant has abase net electricity generation of 500 MWe with a target efficiencyof 35.8% (HHV), which is a general average for subcritical coal-firedpower plants [67–70]. The boiler efficiency is obtained after thecompletion of the Aspen simulation and varies based on coal com-position, which affects the actual net efficiency. 20% excess airentering at ambient temperature and pressure is split into PrimaryAir and Secondary Air prior to entering the Air Pre-Heater (APH).The Primary Air and Secondary Air split fraction and final temper-ature exiting the APH are based upon general guidelines used forcoal combustion, which is dependent upon the coal properties.Since the simulations generate 100% fly ash, while a typical PCpower plant generates a mixture of fly ash and bottom ash, the fluegas exiting the APH is sent to a separator to reduce the fly ash con-tent [71]. The steam turbine cycle and auxiliary PC power plantelectrical consumption were not modeled but were factored intothe final results through general deductions using average efficien-cies of 43% and 6.1%, respectively [67–69].

A supercritical PC power plant with a target efficiency of 39.0%(HHV) was modeled using Pittsburgh #8 coal to investigate the ef-

Ultimate analysis Wt.% As-received Wt.% dry

Moisture 5.2Ash 8.6 9.1Carbon 70.2 74Hydrogen 4.8 5.1Nitrogen 1.5 1.6Chlorine 0 0Sulfur 2.2 2.3Oxygen 7.5 7.9

Ultimate analysis Wt.% As-received Wt.% dry

Moisture 11.12Ash 9.70 10.91Carbon 63.75 71.72Hydrogen 4.50 5.06Nitrogen 1.25 1.41Chlorine 0.29 0.33Sulfur 2.51 2.82Oxygen 6.88 7.75

Ultimate analysis Wt.% As-Received Wt.% dry

Moisture 24.1Ash 4.3 5.7Carbon 53.4 70.3Hydrogen 3.8 5.0Nitrogen 0.73 0.96Chlorine 0 0Sulfur 0.27 0.35Oxygen 13.4 17.69

W. Wang et al. / Fuel 104 (2013) 561–574 565

fect of power plant efficiency on the CCR Process. The supercriticalcase used similar guidelines as the subcritical case with the excep-tion of a 47% steam turbine cycle efficiency and 6.5% auxiliary con-sumption. Fig. 3 shows the general set-up of the baseline PC powerplant, while Table 4 provides the results for the baseline powerplants. Table 5 provides the flue gas composition of the major com-ponents at the exit of the boiler. Trace pollutants typically found inthe ppm range of coal flue gas are present but not reported.

3.2. CCR Process integration

To incorporate the CCR Process for simultaneous CO2 and SO2

removal into a coal-fired power plant, additional unit operationsand assumptions are necessary. Simulations under multiple condi-tions were modeled. Three cases were considered: Ideal, Expected,and Acid. The Ideal case was only modeled for Pittsburgh #8 coal.Although the values used in the Ideal case are not realisticallyachievable, the results yield valuable information by placing a min-imum on the energy penalty and revealing the effect of individualinefficiencies on the energy penalty. The Expected case models theCCR Process using expected values and industrial-based practices.For the Acid case, the Carbonator was modeled as an RGibbs reac-tor to determine the effect of Ca(OH)2 on the removal of all acidgases present in flue gas. The Acid case is modeled only for Illinois

Fig. 3. Unit operations for Aspen s

Table 4Results for PC base plant simulations.

Coal Pitt #8-sub

Feedrate (tph) 190Boiler (MWth) 1238.19Boiler efficiency 88.66%Steam cycle efficiency 43.0%Gross electricity (MWe) 532.42Internal electricity consumption 6.10%Net electricity (MWe) 499.94Net efficiency 35.80%

#6 coal since it is the only coal containing chlorine, which becomeshydrochloric acid (HCl). Within each case, the thermal energy forthe calciner was obtained either from the PC plant flue gas (indi-rect-fired), natural gas oxycombustion, or coal oxycombustion.For each calciner configuration, the thermal extraction from theCCR Process varied from 100% to 80%. At 100%, the thermal extrac-tion is ideal and at a maximum. The thermal extraction refers tothe percentage of thermal energy that is generated from the CCRProcess and transferred to the steam turbine cycle. In reality, heattransfer equipment will dictate these efficiencies. Fig. 4 provides aflow chart of the Aspen simulations performed. Fig. 5 shows a tem-plate for the CCR Process Aspen simulations. Table 6 provides thestatic unit operations that remain constant across all simulations.Tables 7–9 provide the conditions for the Ideal case, Expected case,and Acid case, respectively.

4. Process simulations results

4.1. Power plant integration

One of the greatest advantages of the CCR Process, and calciumprocesses in general, is its ability to generate additional electricitywithout modifications to the size and capacity of the existing boiler.This allows for great flexibility of the CCR Process integration with

imulations of PC power plant.

Illinois #6-sub PRB-sub Pitt #8-super

204 264 1751235.76 1241.80 1140.488.59% 87.32% 88.66%43.0% 43.0% 47.0%531.38 533.97 535.996.10% 6.10% 6.50%498.96 501.40 501.1535.77% 35.26% 38.96%

Subcritical Power Plant

Expected Values Ideal Values

PRBIll #6Pitt #8

Supercritical Power Plant

Pitt #8

Expected Values

Pitt #8

Acid

500 MWe

Fig. 4. Flow chart for Aspen simulations for 500 MWe coal-fired power plant.

Table 5Flue gas composition (vol.%) for Pittsburgh #8, Illinois #6, and PRB coal.

Coal type Pittsburgh #8-sub Pittsburgh #8-super Illinois #6 PRB

Coal flue gas componentNitrogen (N2) 75.2 75.2 74.4 71.8Carbon dioxide (CO2) 13.5 13.5 13.3 13.9Water (H2O) 6.4 6.4 7.4 10.2Oxygen (O2) 3.4 3.4 3.4 3.17Carbon monoxide (CO) 0.6 0.6 0.6 0.38Nitrogen oxide (NO) 0.6 0.6 0.6 0.46Sulfur dioxide (SO2) 0.2 0.2 0.2 0.027Hydrogen (H2) 0.1 0.1 0.07 0.054Hydrochloric acid (HCl) 0.0 0.0 0.02 0.0Total ash (tons per hour) 16.3 15.1 19.8 11.4Total C (kmol/h) 10,067 9273 9822 10,639

Fig. 5. Process flow diagram of the CCR Process.

566 W. Wang et al. / Fuel 104 (2013) 561–574

Table 6Static conditions for modeling the CCR Process.

Unit operation Aspen plus model Specification

Heat exchangers (M)HeatX Heat exchange two streamsPCD-1 SSplit 90% fly ash removalCARB RStoic 90% CO2/100% SO2 removal

No energy generationPCD-2 SSplit 98% gas–solid separation efficiency

Operating T = carbonator TPURGE FSplit Splits stream based on mass fraction

Operating condition = 3%MIX Mixer Combines recycle stream and fresh feed stream with respect to mass and energyCALCINER RGibbs Products based on thermodynamicsPCD-3 SSplit Gas–solid separation efficiency = 99.5%

Operating T = calciner operating TASU SEP2 Separates O2 from air

O2-IN at 7.5% excess O2 for CALCINERHYDRATOR RGibbs Products based on thermodynamicsHX-1, HX-2, HX-3 Heater Cools gas to 350 �CCO2 purity Minimum 95% mol purity (dry)ASU Ref. [72] 200 kW h/tonne O2 and 167 kW h/tonne O2

Steam Ref. [71] Quality = 0.925Pressure = 200 Hg, T = 38 �CObtained from outlet of low-pressure turbine

Table 7Ideal conditions parameters.

Unit operation Aspen plus model Specification

Heat exchangers (M)HeatX Operates with less than 5 �C approach TCARB RStoic Ca:C mol ratio = 0.912

Operating T = 650 �CCALCINER RGibbs Operating T = minimum THYDRATOR RGibbs Operating T = 500 �C

H2O:Ca mol ratio = 1:1CO2 compression Refs. [73–75] 119 kW h/tonne and 75 kW h/tonne CO2 to compress to 14 MPaThermal energy From CCR 100% extraction

Table 8Expected conditions parameters.

Unit operation Aspen plus model Specification

Heat exchangers (M)HeatX Operates with minimum 10 �C approach TCARB RStoic Ca:C mol ratio = 1.4:1

Operating T = 625 �CCALCINER RGibbs Operating T = 1000 �CHYDRATOR RGibbs Operating T = 500 �C

H2O:Ca mol ratio = 1.3:1CO2 compression Refs. [75–77] 119 kW h/tonne and 100 kW h/tonne CO2 to compress to 14 MPaThermal energy From CCR 100%, 90%, and 80% extraction

Table 9Values for modeling the CCR Process Acid case.

Unit operation Aspen plusmodel

Specification

Expected values exceptCARB

CARB RStoic AndRGibbs

Products based onthermodynamicsT = 625 �C

HX-2 RGibbs T inlet = 625 �C, Toutlet = 350 �CModel possible rxns. in HX-2

W. Wang et al. / Fuel 104 (2013) 561–574 567

respect to electricity generation. The existing boiler can operatewith reduced capacity while maintaining the identical net electric-ity output as the base plant or additional electricity can be gener-

ated after the installation of the carbon capture process. Theadditional electricity generation can be handled in a variety ofways. One possibility is the installation of a new steam turbine cy-cle to process the additional electricity. Another possibility,although quite doubtful, is the additional electricity can be pro-cessed by the existing steam turbine cycle. One final possibility uti-lizes a coal-fired power plant as a whole, where multiple boilerstypically exist. On average, the CCR Process can increase the elec-tricity generation by 20–30% over the base plant. A cursory exami-nation of coal-fired power plants in the state of Ohio shows thatapproximately four power plants have a boiler with a capacity inthe range of 20–30% of the largest boiler [76]. The possibility existsto completely shut down the small-load boiler, install the CCR Pro-cess onto the large boiler, and utilize the CCR Process heat to replacethe small-load boiler. The overall carbon capture percentage in-creases since one entire boiler is offline while overall electricitygeneration remains constant.

568 W. Wang et al. / Fuel 104 (2013) 561–574

The additional electricity generation originates from the ther-mal energy necessary for operating the calciner, and it is taken intoaccount when calculating the energy penalty of the carbon captureprocess. Three net electricity generation terms arise: (1) Base NetElectricity Generation – the electricity delivered to the grid of thebase coal-fired power plant (2) CCR Process Net Electricity Gener-ation – the electricity delivered to the grid of the power plantequipped with the CCR Process (3) Modified Base Net ElectricityGeneration – the electricity delivered to the grid of a fictitiouscoal-fired power plant operating with the same efficiency as thebase but with an increase in thermal energy input equivalent tothe calciner. The Modified Base Net Electricity Generation is ob-tained by assuming the thermal energy used to operate the calcin-er would be otherwise used to generate electricity in the absenceof the CCR Process. The energy penalty is then defined using theModified Base Net Electricity Generation to account for the addi-tional thermal energy input into the system.

4.2. Ideal case results

The Ideal case uses the most favorable conditions possible for90% CO2 removal and 100% SO2 removal. Reactor temperatures ap-proach thermodynamic limits to achieve the desired level of reac-tion conversion and additional unit operations operate withminimal loss in efficiency. Modeling the Ideal case is importantfor two reasons. First, the Ideal case establishes a minimum energypenalty for the CCR Process integration into a PC plant. Second,while the values used in the Ideal case may never be achievable,the results of the Ideal case can be compared with the Expectedcase to observe the impact of inefficiencies. Table 10 provides theresults from the Ideal case simulations.

Since the Net Electricity term is prior to ASU separation energyand CO2 compression energy, it is analogous to the Modified BaseNet Electricity Generation. Comparing the two values providesthe energy penalty based solely on electrical generation. Thecoal-fired calciner case generates more net electricity than theModified Base plant, which is possible due to the ideal conditionsof the simulations, specifically 100% thermal transfer efficiency,whereas a coal-fired boiler is slightly under 90%. The indirect-firedcalciner obtains its thermal energy from the PC plant flue gas andrecovers the electricity generation lost from the flue gas that isused for calcination instead of electricity generation through theCCR Process thermal energy. The natural gas-fired calciner hasthe highest Net Electricity energy penalty, yet it is still less than1.5%. The major contributor to the energy penalty is CO2 compres-sion, totaling approximately 6% of the Modified Base Net ElectricityGeneration. Fig. 6 shows the individual contributions to the overall

Table 10Simulation results for Ideal case.

Calciner fuel Indirect (fluegas)

Naturalgas

Coal

Electricity from boiler 365.3 585.7 581.0Electricity from CCR (MWe) 167.2 181.8 195.1Gross electricity (MWe) 532.5 767.5 776.1Net electricity (MWe) 500.0 720.7 728.8CO2 compression @ 75 kW h/tonne CO2

(MWe)29.2 39.4 45.4

Cryogenic ASU @ 167 kW h/tonne O2

(MWe)0.0 29.4 30.0

CCR Process Net Electricity Generation(MWe)

470.8 651.9 653.4

Calciner fuel consumption (MWth) 512.6 646.2 600.5Modified Base Net Electricity

Generation (MWe)499.94 731.28 714.92

Energy penalty 5.8% 10.9% 8.6%

energy penalty at varying levels of CO2 compression energy andASU separation energy. 119 kW h/tonne CO2 is the current CO2

compression energy requirements, while 75 kW h/tonne CO2 rep-resents the minimum based on thermodynamics [73–75]. The indi-rect calciner does not require an ASU, so its energy consumption isalways zero.

The lowest total energy penalty possible is slightly less than 6%and occurs when the calciner is indirect-fired and the CO2 com-pression energy is at the theoretical minimum of 75 kW h/tonneCO2. The energy penalty is comprised solely of CO2 compressionenergy. In general, the total energy penalty is highly sensitive tothe CO2 compression energy, where at least half the energy penaltyis a result of CO2 compression. Any improvements to the reductionof CO2 compression energy will decrease the overall energy pen-alty. Even though the ASU energy requirements are greater thanCO2 compression on a mass basis, the amount of O2 separated issignificantly less than the CO2 compressed. This makes improve-ments to ASU separation energy fairly insensitive to the overall en-ergy penalty. The reduction from 200 kW h/tonne O2 to 167 kW h/tonne O2, which is a 16.5% reduction, translates to less than 1% en-ergy penalty reduction. The Ideal case clearly demonstrates the sig-nificant role CO2 compression energy plays and the minimalimpact ASU energy minimally has on the energy penalty. Contribu-tions to the energy penalty by the CCR Process are explored furtherin the Expected cases.

4.3. Expected case results

In the Expected case, Pittsburgh #8, Illinois #6, and a PRB coalwere modeled under identical CCR conditions, listed in Table 8.Slight variations in input values to the Boiler were necessary basedon coal properties. The Expected case also includes an additionalfactor to account for non-ideal heat transfer and uses realisticassumptions. Figs. 7–9 provide the breakdown in energy penaltyfor Pittsburgh #8, Illinois #6, and PRB coal, respectively. The CO2

compression energy and ASU energy are fixed at 119 kW h/tonneCO2 and 200 kW h/tonne O2 while the heat extraction efficiencyfrom the CCR Process varies from 100% to 80%.

Several results can be obtained from the simulations performedon the Expected cases. The indirect-fired calciner with 100% heatextraction always provides the lowest energy penalty, which isdue solely to the absence of the ASU. However, an indirect-firedcalciner is not commercially available, will reduce the power plantoutput, and becomes unfavorable at lower CCR thermal extractionefficiencies. The difference in energy penalty between a coal-firedand natural gas-fired calciner is minimal, with the coal-fired cal-ciner having a slightly lower energy penalty; however, there willbe a difference in materials circulation since natural gas combus-tion does not generate sulfur or ash byproducts. Overall, the pro-cess economics will determine the calciner fuel. Regardless ofthermal energy source for the calciner or coal composition forthe boiler, the maximum energy penalty of the CCR Process whenintegrated into a PC plant will be slightly greater than 24% whenusing acceptable values for CO2 compression and air separationalong with achievable thermal extraction efficiencies.

Given the volume of CO2 produced and the elevated pressurenecessary for sequestration, the CO2 compression energy has a sig-nificant impact on the overall energy penalty. Since no standardvalue exists, the energy penalty of carbon capture processes basedon simulations can vary widely by simply varying the CO2 com-pression energy requirements. This was clearly demonstrated inthe Ideal case where the effect was magnified since the compres-sion energy was set to the thermodynamic minimum. The Depart-ment of Energy consistently uses a value of 80 kW h/tonne CO2,while 100 kW h/tonne CO2 is considered more reasonable[68,74,77,78]. For the Expected cases, the effect of CO2 compres-

Fig. 6. Energy penalty for the Ideal case.

W. Wang et al. / Fuel 104 (2013) 561–574 569

sion energy is examined by varying it from 119 kW h/tonne CO2 to100 kW h/tonne CO2 and achieves two goals: the effect of CO2 com-pression energy on energy penalty is revealed and the CCR Processenergy penalty can be more fairly compared to competing technol-ogies. Table 11 provides the labels for Figs. 10–12.

Figs. 10–12 show the effect of thermal energy extraction, ASUenergy, and CO2 compression energy on energy penalty for Pitts-burgh #8, Illinois #6, and PRB coal, respectively. Case A corre-sponds to the three coals used in Figs. 7–9 without the detaileditemization of the energy penalty.

From Figs. 10–12, the sensitive and insensitive parameters withrespect to energy penalty can be determined. The most importantparameter affecting energy penalty would be the thermal extrac-tion efficiency from the CCR Process. For every 10% decrease inthermal extraction efficiency, the energy penalty will increase by

Fig. 7. Energy penalty for Pittsburgh

approximately 5% for the indirect-fired calciner, 3.4% for the natu-ral gas calciner, and 3.7% for the coal-fired calciner, irrespective ofcoal used for combustion. For a given CCR thermal efficiency andcalciner type, the reduction in energy penalty between Case Aand Case D are nearly identical for all three coals. The energy pen-alty for the indirect-fired calciner decreases 1.5%, the natural gascalciner decreases 2.3%, and the coal-fired calciner decreases2.6%. The reduction in energy penalty due to the decrease in ASUenergy consumption is slightly less than 1%, and the remaining de-crease in energy penalty is due to the reduction in CO2 compres-sion energy, again demonstrating the significant impact CO2

compression energy has on the energy penalty. For the PRB coal,the reduction in energy penalty between Case A and Case D isslightly greater for the coal-fired calciner, but the ASU portion re-mains identical at 1%. For any given condition, the PRB coal will

#8 coal for the Expected case.

Fig. 8. Energy penalty for Illinois #6 coal for the Expected case.

Fig. 9. Energy penalty for PRB coal for the Expected case.

Table 11Legend for Figs. 10–12.

Symbol A B C D

CO2 compression (kW h/tonne CO2) 119 119 100 100ASU energy (kW h/tonne O2) 200 167 200 167Symbol

Calciner thermal energy Indirect-fired Natural gas Coal

570 W. Wang et al. / Fuel 104 (2013) 561–574

have the highest energy penalty, followed by Pittsburgh #8, andlastly Illinois #6. Depending on the condition, the difference canbe as low as 0.5% or greater than 2%. For the coal-fired calciner at80% thermal efficiency, the PRB coal for Case A has an energy pen-

alty around 25%, while the Illinois #6 coal for Case D has an energypenalty around 20%. Based on the analysis provided, multiple fac-tors that are external to the CCR Process have a significant impacton the energy penalty.

Fig. 10. Pittsburgh #8 energy penalty sensitivity analysis.

W. Wang et al. / Fuel 104 (2013) 561–574 571

4.4. Presence of acid gases

In the case of using an Illinois #6 coal, or any coal containingadditional components that may form acid gases, the CCR Processhas the inherent advantage of removing the acid gases or theircomponents. For a coal-fired boiler, the two main concerns are sul-fur trioxide (SO3), which forms sulfuric acid, and chlorine, whichforms hydrochloric acid (HCl). The ability of calcium-based sor-bents to remove both HCl and SO3 have been well-studied [79–83]. By removing the acid gases present in the flue gas, a lower exitflue gas stack temperature is allowable since the acid gas dewpointtemperature is no longer a concern. Typically, this only affects sul-furic acid since the hydrochloric acid dewpoint is slightly greaterthan ambient conditions. Between 300 �C and 350 �C, a mixtureof sulfur trioxide and sulfuric acid will exist with sulfur trioxidebeing the dominant form [84,85].

Fig. 11. Illinois #6 energy pen

At the exit of the Boiler, the flue gas from the combustion of Illi-nois #6 coal will generate 1.1 ppm SO3 and 217 ppm HCl. Whenplaced into the Carbonator with the Ca(OH)2 from the Hydrator,the SO3 concentration decreases to 0.017 parts per trillion whileHCl remains constant. From the gas outlet of the PCD located atthe exit of the Carbonator (PCD-2), the CO2/SO2 lean flue gas willbe in contact with the solids not collected by the PCD. Between625 �C and 350 �C, the gas–solid mixture can continue to react inthe ductwork and heat exchanger. The gas–solid mixture fromthe outlet of PCD-2 was modeled in a Gibbs reactor with an inlettemperature of 625 �C and outlet temperature of 350 �C to observethe change in acid gas concentrations. The SO3 concentration is re-duced to virtually zero, while the concentration of HCl is reducedto 85 ppm. This shows the CCR Process has the possibility of signif-icantly reducing the concentration of additional acid gases presentin the flue gas stream, which would allow for lower exit tempera-

alty sensitivity analysis.

Fig. 12. PRB coal energy penalty sensitivity analysis.

572 W. Wang et al. / Fuel 104 (2013) 561–574

tures from the Air Pre-Heater and increase boiler efficiency. Exper-iments at the conditions present in the CCR Process simulationsneed to be conducted for verification.

4.5. Effect of base plant efficiency

The final parameter examined is the effect of power plant effi-ciency on energy penalty. Increasing the power plant efficiency de-creases the energy penalty in two ways. First, the amount of CO2

produced from coal combustion decreases as net thermal to elec-tric efficiency increases. Second, since the base plant net efficiencyis higher, the reduction in efficiency due to the integration of thecarbon capture process has a lower impact. Fig. 13 shows the effectof net power plant efficiency on energy penalty under the identicalconditions of 90% CCR thermal efficiency, 119 kW h/tonne CO2, and

Fig. 13. Effect of power plant efficienc

200 kW h/tonne O2 for a Pittsburgh #8 coal using the assumptionsfor the Expected case. The integration of the CCR Process intopower plants with initially higher net efficiencies will result in amodest decrease in energy penalty; however, the percent reduc-tion in energy penalty is lower than the percent gain in powerplant efficiency.

4.6. Summary of results

Overall, the CCR Process provides a superior performance com-pared to competing carbon capture technologies under similar oper-ating conditions. Table 12 provides a list of post-combustion carboncapture processes, their respective energy penalty, and source of ref-erence. When comparing the CCR Process to the traditional CaO/CaCO3 cycle, the simulations were performed based on experimental

y on CCR Process energy penalty.

Table 12Comparison of CCR Process to competing technologies on a similar basis.

CO2 control technology Base plant efficiency Energy penalty (%) Reference

Econamine FG Plus Montana PRB-32.6% 32.5 Refs. [77] – Cases 7 and 9CCR Process Spring Creek PRB-32.9% 22.5Econamine FG Plus Illinois #6–36.8% 32.3 Refs. [68] – Cases 9 and 10CCR Process Illinois #6–35.8% 21.0Econamine FG Plus Illinois #6–39.1% 30.4 Refs. [68] – Cases 11 and 12CCR Process Pittsburgh #8–39.0% 20.0Advanced MEA Conesville-35.01% 26.6 Refs. [69] – Case 1ACCR Process Illinois #6–35.8% 21.0Traditional CaO/CaCO3 Pittsburgh #8–35.8% 20.7 Refs. [25]CCR Process Pittsburgh #8–35.8% 16.1Average amine-based US Bituminous-39.3% 26.4 Refs. [86]CCR Process Pittsburgh #8–39.0% 21.5Average oxycombustion US Bituminous-40.4% 24.5 Refs. [86]CCR Process Pittsburgh #8–39.0% 21.5

W. Wang et al. / Fuel 104 (2013) 561–574 573

results and published data since prior simulations have used unusu-ally low Ca:C mol ratios (3–5) for high CO2 removals (75–96%) thatwould not allow for a realistic comparison [42,43,87–89].

5. Conclusions

The CCR Process has numerous parameters that affect the en-ergy penalty of the process. The base power plant efficiency hasthe greatest effect on the energy penalty, where a higher base effi-ciency necessarily reduces energy penalty. The CCR Process ther-mal extraction efficiency is the most sensitive internal variableaffecting the CCR Process, where a 10% decrease in efficiency in-creases the energy penalty between 3% and 5%. The most sensitiveexternal parameter affecting the energy penalty is the energy re-quired for CO2 compression. Reducing the CO2 compression energyfrom 119 kW h/tonne CO2 to 100 kW h/tonne CO2 reduces the en-ergy penalty of the process by approximately 1.5%. Although oxy-combustion is used in the calciner, the ASU energy requirementshave only a minimal impact on the energy penalty. Given the com-plexity and underlying assumptions required to model a carboncapture process, it is important to ensure that competing technol-ogies are modeled under similar conditions in order to generate areasonable comparison. With achievable design considerations,the CCR Process consistently provides a lower energy penalty. Thisallows for additional inefficiencies in the process unknowns whilemaintaining a competitive advantage over other technologies.

Acknowledgements

The financial assistance provided by The Ohio Coal Develop-ment Office (OCDO) of the Ohio Air Quality Development Authority(OAQDA) in support of the CCR Process demonstration is gratefullyacknowledged.

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