Retrofitting the Regulated Power Plant: Optimizing EnergyAllocation to Electricity Generation, Water Treatment, and CarbonCapture Processes at Coal-Fired Generating FacilitiesDaniel B. Gingerich† and Meagan S. Mauter*,†,‡

†Department of Engineering and Public Policy, Carnegie Mellon University, 5000 Forbes Ave., Pittsburgh, Pennsylvania 15213,United States‡Department of Civil and Environmental Engineering, Carnegie Mellon University, 5000 Forbes Ave., Pittsburgh, Pennsylvania15213, United States

*S Supporting Information

ABSTRACT: Minimizing the human health and environmental impacts fromelectricity generation at existing coal-fired power plants (CFPPs) will requireextensive plant retrofit, but the separations technologies for reducing CO2 andwastewater emissions at CFPPs are energy intensive. This paper quantifies theelectricity generation efficiency and revenue implications of allocating electricity,steam, or residual heat to these emission control processes under several differentregulatory scenarios. We develop an energy balance model of the NationalEnergy Technology Laboratory’s 550 MW CFPP without carbon capture (CC)and add models of five CC technologies (one electricity driven and four thermalprocesses) and five wastewater treatment (WT) technologies (one electricity driven and four thermal processes) to comply withthe Clean Power Plan and Effluent Limitation Guidelines emissions regulations. Plant revenue is maximized by utilizing residualheat for WT or CC, but the optimal allocation of limited residual heat resources depends on the current regulatory environment.If both CC and zero liquid discharge WT regulatory standards are in place, the plant maximizes revenue by allocating residualheat and steam to amine-based CC and electricity to mechanical vapor recompression WT.

KEYWORDS: Carbon capture, Flue gas desulfurization wastewater, Coal-fired electricity generation, Waste heat, Power plant retrofit

■ INTRODUCTION

Reducing carbon and aqueous emissions at coal-fired powerplants (CFPPs) in the United States will require installation ofnew carbon capture and wastewater treatment systems. Theseair and water separations systems require energy, either in theform of heat or electricity,1−6 and may significantly reduce thegeneration efficiency and revenue of CFPPs. Though recentwork has explored the application of residual heat-drivenseparation processes to reduce auxiliary power loads for carboncapture7 and water treatment,8,9 there is not sufficient residualheat to fully meet all process demands. A systematicreevaluation of the use of all thermal and electricity sourcesat CFPPs will aid power plant designers in maximizing theefficiency and cost effectiveness of emissions control retrofitsduring the transition to a more sustainable grid.Electricity generation from coal combustion produces three

potentially usable energy sources. The first is high-quality steamfed to the high pressure (HP), intermediate pressure (IP), andlow pressure (LP) turbines, which ranges in enthalpy from3470 to 1980 kJ/kg.10 The second source is electricityproduced by the generator. The third energy source is residualheat discharged to the environment (e.g. in the exhaust gas ofCFPPs with a flue gas desulfurization (FGD) unit at an averagetemperature of 128 °C).8 Any of these three energy sources

could conceivably be allocated to meet the energy demands ofcarbon capture and wastewater treatment processes.CFPPs are the largest stationary sources of CO2 emissions in

the U.S., and carbon capture will be a critical component ofstrategies for lowering greenhouse gas emissions in the short tomedium term.11−13 Although solvents, sorbents, and mem-branes are all being explored as solutions for carbon capture,14

the most established technologies are amine solvent adsorptionsystems, including the well-studied monoethanolamine (MEA)system.3,15 In a MEA system, CO2 absorbs into a lean MEAsolution. The CO2-rich solvent solution is then regenerated in adistillation column, producing streams of concentrated CO2

and lean MEA solvent.16 The energy for distillation is typicallyprovided by steam that would otherwise drive the low-pressureturbine. MEA solvent regeneration imposes a significant energypenalty on CFPPs4 and reducing the penalty through heatintegration and system analysis remains a fruitful area ofresearch.17,18

In addition to emitting CO2, CFPPs discharge over 200million cubic meters of wastewater containing arsenic, lead,mercury, selenium, and dissolved solids to receiving water

Received: November 18, 2017Revised: January 4, 2018Published: January 24, 2018

Research Article

pubs.acs.org/journal/ascecgCite This: ACS Sustainable Chem. Eng. 2018, 6, 2694−2703

© 2018 American Chemical Society 2694 DOI: 10.1021/acssuschemeng.7b04316ACS Sustainable Chem. Eng. 2018, 6, 2694−2703

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bodies annually.19,20 These wastewater streams are produced influe gas mercury control, ash transport, coal combustionresidual management, and flue gas desulfurization (FGD)processes.19,21 FGD wastewater is the most environmentallysignificant of these wastewater streams, containing two-thirds oftoxic metal discharge on a toxicity-weighted mass basis.19

Under the recently promulgated Effluent Limitation Guidelines(ELGs), the EPA expects plants to comply with new regulatorystandards for FGD wastewater discharges using a combinationof chemical precipitation and biological treatment or electricity-driven mechanical vapor recompression (MVC) and crystal-lization.5 In addition to these electricity-driven processes totreat FGD wastewater, plants can also choose from a range ofthermally driven deionization processes. These thermalprocesses include evaporative technologies, such as multistageflash distillation (MSF),22 multiple effect distillation (MED),23

thermal vapor recompression (TVC),24 and the hybrid thermal-membrane processes ammonia carbon dioxide forward osmosis(FO).8,25 These thermal technologies could be powered withhigh-quality steam, creating a parasitic loss and a trade-offbetween electricity generation and wastewater treatment.Alternatively, residual heat from the flue gas may be capturedfor thermal wastewater treatment processes, though the supplyof this heat is limited. A quantitative understanding of theefficiency and water treatment potential of electrical, thermal,and residual heat energy sources will allow power plants tooptimize heat allocation and minimize the cost of wastewatertreatment.To the best of our knowledge, tools for making holistic

energy and environmental compliance decisions for air, water,and CO2 standards at CFPPs have not been developed. Thoughmodels of energy consumption and associated parasitic lossesof carbon capture are well studied in the literature,7,17,26−30

similar models for water treatment are limited to eithercombined electricity generation and desalination systems ortrigeneration systems31−33 and do not model FGD wastewatertreatment. Finally, while past work has evaluated the use ofresidual heat to reduce the energy intensity of carboncapture,7,34 we are unaware of models to optimize residualheat allocation across multiple control processes. As a result,there is a need for environmental compliance decision supporttools that consider multiple emissions control processes andenergy sources simultaneously in order to reduce the overallenvironmental burden of coal generation.This study develops a model to quantitatively evaluate the

trade-offs between dispatching the three energy streamsavailable at CFPPs to electricity generation, carbon captureand compression, and wastewater treatment processes in aretrofit of the National Energy Technology Laboratory’s 550MW pulverized coal combustion power plant model.10 We firstbuild mass- and energy-balance models of the turbines in themodel plant. We then vary the allocation of energy sourcesamong three “sinks”: the turbine for electricity generation, thesolvent regeneration for carbon capture, and the wastewatertreatment unit. Using this method, we estimate the maximumamount of electricity generation, carbon capture, and waste-water treatment that can be performed with the available fuelenergy. Finally, we employ these estimates to maximize revenueby optimizing the allocation of enthalpy to plant processesunder a range of likely prices for electricity delivered to the grid,captured carbon, and treated water.

■ MATERIALS AND METHODS550MW CFPP Base Model. We selected the National Energy

Technology Laboratory’s model of a 550 MW pulverized coalcombustion plant without carbon capture as the base model plantfor retrofit.10 Versions of this model are frequently used in theliterature35−37 for studying the impact of carbon capture retrofits andchanges in power plant operation. The steam produced in the boiler isused to drive three turbines: a high-pressure turbine (596 GJ/h ofenergy fed to the turbine), an intermediate-pressure turbine (590 GJ/hof energy), and a low-pressure turbine (1050 GJ/h of energy). Notethat steam leaving the HP turbine is reheated in the boiler beforeentering the IP turbine. These turbines connect to generators wheremechanical energy is converted into electrical energy at a rate of 550MW per hour. Details of the turbines, stream flows between theturbines, (enthalpy content, temperature, pressure, and flow rates),and steam extractions from the turbines are published in the originalNETL report.10

We use an energy balance approach to calculate the electricitygeneration, carbon capture, and water treatment using high qualitysteam (Figure 1). We first employ this model to evaluate the system

trade-offs between dispatching steam for electricity generation, SE, ordispatching steam for carbon capture, SC, or wastewater treatment, SW.Second, we investigate the financial trade-offs of using steam forelectricity generation and environmental controls. Finally, wemaximize the revenue of the plant by varying the allocation steam,electricity, and high-temperature residual heat to comply with carboncapture and effluent limitation guideline (ELG) regulations for FGDwastewater.

Quantification of Plant Energy Sources. Three different energysources can power carbon capture and water treatment emissionscontrol processes: high quality steam dispatched from the turbines,electricity produced at the generator, or residual heat recovered fromthe exhaust gas. To model steam dispatch for environmental controls,we assume that steam is withdrawn prior to entering the HP, IP, or LPturbines and is returned to the steam cycle after the turbine. In thecase of the HP and IP turbines, the enthalpy content of the steamupon return is assumed to equal the steam as it leaves that turbine(Figure 1).38 For the LP turbine, the steam is returned to the steam

Figure 1. Energy balance for the NETL 550 MW Turbines. Thisstructure of this energy balance is equivalent for the HP and IPturbines. In the LP turbine, exiting steam is diverted to the condenser,whereas the steam leaving the water treatment and carbon capture unitis returned to the steam cycle after the condenser.

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cycle after the condenser and is assumed to have an enthalpy contentequal to the water entering the first preheater.4

Next, we calculate the hourly electricity generation by steam thatenters the turbine, E in kWh/h, by multiplying an assumed efficiency,η, of 90% in converting extracted enthalpy into electricity; the amountof steam sent to the turbines, SE; the mass flow rate of the steam, m inkg/h; and the change in enthalpy of the steam in and out of theturbine, hin,E and hout,E, respectively, in kJ/kg (eq 1).

η= − ×E S m h h( )1 kWH3600 kJE in E out E, ,

(1)

The model dispatches enough steam to the IP and LP turbines to meetthe feedwater preheating and deaerator steam extraction requirements.A small fraction (2.7% or 49 GJ/h) of steam is diverted from the IPand LP turbines for boiler water deaeration and feedwater preheating.Holding allocation to preheating and the deaerator constant is a usefuland widely used simplifying assumption that eliminates the need tooptimize energy flow rates into the initial turbine.39 Finally, wecalculate the quantity of residual heat that can feasibly be recoveredfrom the exhaust gas before acid mist begins to condense, as reportedin previous work.40 There is 243 GJ of residual heat available at themodel plant at a temperature of 128 °C. We do not considerpotentially recoverable residual heat from other sources, includingcarbon capture solvent regeneration, CO2 compression,

41 or exhaustgas upstream of the FGD system.1,42

Energy Consumption of Carbon Capture Processes. The casestudy NETL 550 MW CFPP generates 856 kg/MWh of CO2.

10 Theplant must capture 221 kg/MWh in order to comply with themaximum CO2 emissions rate of 1400 lb/MWh that was to berequired of plants under the Clean Power Plan.43 We assume that theupper bound of CO2 recovery is 90%, regardless of carbon capturetechnology.6,10

We first quantify the trade-offs between allocating steam toelec t r ic i ty genera t ion or carbon capture us ing MEAsolvents,1−4,6,44,45 the solid sorbent Zeolite 13X,3 the hinderedamine Mitsubishi Heavy Industry KS1 solvent,42 and the tertiaryamine Shell CANSOLV CO2 Capture system (Cansolv).10 The rate ofcarbon capture, Cj in metric tons of CO2 (tonne CO2) per hour, foreach technology j, is determined by dividing the rate of enthalpydiverted to carbon capture by the heat duty requirements of thecarbon capture process, HC,j in kJ/tonne CO2 (eq 2). We useliterature-reported values from simulations for HC,j of 3.54 GJ/tonneCO2 for MEA,44 2.72 GJ/tonne CO2 for KS1,

42 2.48 GJ/tonne CO2for Cansolv,10 2.85 GJ/tonne CO2 Zeolite 13X,46 and thethermodynamic limit of MEA capture of 1.9 GJ/tonne CO2.

2 Thesesimulations may exclude inefficiencies present in real-world systems,but their use in this study is necessary for making direct comparisonsto technology options that have not been piloted or installed at plants.Table S1 in Supporting Information (SI) Section S1 providescomplete descriptions of each process and the calculated values forequivalent electrical energy consumption.

=−

CS m h h

H

( )j

C in C out C

C j

, ,

, (2)

These steam dispatch requirements are used to calculate theparasitic losses or the electricity that would have been generated hadthe steam been used for electricity generation rather than diverted tocarbon capture. We calculate the average parasitic loss, P in kWh/tonne CO2, when carbon capture, C, equals some χ tonne CO2/h ofcapture, using eq 3, where EC=χ and EC=0, in kWh/h, is the electricitygeneration under carbon capture and no carbon capture scenarios,respectively.

χ=

−χ= =PE EC C 0

(3)

This parasitic loss does not include electricity consumed incompressing CO2 for transport and storage, as the technologies

considered produce a concentrated CO2 stream at approximately thesame pressure.

Next, we calculate the amount of carbon capture that can be drivenby residual heat in the exhaust gas by replacing the numerator of eq 2with the quantity of residual heat that can be safely recovered. Finally,we calculate the auxiliary loading, Ai in kWh/h, for electricity-drivencarbon capture by multiplying the estimated electricity consumption ofan idealized post-combustion CO2−N2 membrane separation process,aj, modeled at 0.19 MWh/tonne CO2,

28 by the mass of carboncaptured, in tonne CO2/h (eq 4).

=−

A aS m h h

H

( )j j

C in C out C

C j

, ,

, (4)

We also calculate an auxiliary loading associated with pressurizingcaptured carbon, Ai,press in kWh/h, using eq 5 as the product ofcompression electricity consumption, aj,press in kWh/tonne CO2, andthe mass of carbon captured, in tonne CO2/h.

=−

A aS m h h

H

( )i press i press

C in C out C

C j, ,

, ,

, (5)

For thermal carbon capture technologies, ai,press is equal to 86 kWh tocompress 1 tonne of CO2 from 3 to 150 bar; for membrane separationtechnologies, ai,press is equal to 73 kWh to compress 1 tonne of CO2from 5 to 150 bar.34 We do not calculate the auxiliary loadingassociated with transporting or storage of captured carbon. We also donot allow multiple carbon capture technologies to be implemented atthe same plant, as the capital and operational costs of building paralleladsorption and membrane-based carbon capture systems are likely toexceed any revenue gains from allocating a mix of different processes.

Energy Consumption of Water Treatment. Wastewater exitsthe FGD unit of the case study plant at a volumetric flow rate of 111.6m3/h and a temperature of 56 °C.10 Beyond filtration for gypsumrecovery, NETL does not include FGD wastewater treatment in theplant model.10 However, a survey of plants performed as part of theELG promulgation found that a majority of CFPPs will need to installadditional treatment to comply with the ELGs.5 As detailed above,plants will either install secondary treatment or zero liquid discharge(ZLD) systems. ZLD treatment trains typically follow primarytreatment with water softening; water deionization via thermal,mechanical, or membrane processes; and crystallization. To costeffectively crystallize the solids, the water deionization step mustachieve approximately 65% recovery. The present work considers onlythe energy inputs to the water deionization step, which is the greatestcontributor to energy consumption in the ZLD treatment train.

We estimate the wastewater deionization capacity, Wi in m3/h, ofsteam-driven processes by dividing the rate of enthalpy allocated towater deionization by the heat duty requirements for water treatmenttechnology i, Hw,i in kJ/m3 (eq 6). We use simulated heat duties forthermal water deionization at 65% recovery8,47,48 and 56 °C feedtemperatures of 476 MJ/m3 for multi-effect distillation (MED), 1071MJ/m3 for multistage flash distillation (MSF), 313 MJ/m3 for thermalvapor recompression (TVC), and 409 MJ/m3 for forward osmosis(FO). These simulations may exclude inefficiencies present in real-world systems, but their use in this study is necessary for making directcomparisons to technology options that have not been piloted orinstalled at plants. The equivalent electrical energy consumption forthese technologies is reported in Table S2 of SI Section 2. We use heatexchangers to generate the steam used in the thermal water treatmentprocesses, rather than directly using steam from the turbines. For allturbine-water treatment technology pairs, we set the temperature ofworking fluid to the temperature that produces the minimum heatduty. This is accomplished by adjusting the mass of the steam used inthe heat exchanger loop.

=−

WS m h h

H

( )i

W in W out W

w i

, ,

, (6)

These steam dispatch requirements are used to calculate theparasitic losses incurred by allocation steam to wastewater deionization

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processes. We calculate the average parasitic loss, P in kWh/m3, whenwater production, W, equals ω m3/h of production, using eq 7.

ω=

−ω= =PE EW W 0

(7)

Next, we estimate the wastewater deionization potential of residualheat by replacing the numerator of eq 5 with the amount of residualheat that can be safely recovered from the exhaust gas. Finally, wecalculate the auxiliary electricity consumption of the thermal andelectrical wastewater deionization processes, Ai in kWh/h, bymultiplying electricity consumption per cubic meter of water, ai inkWh/m3, by the volume of water being treated, V in m3/h (eq 8).Additional auxiliary electricity consumption of the thermal technolo-gies are reported in Table S2 of SI Section 2.8,47,49 In addition, weconsider the electricity consumption of the two electrical processesthat the EPA identified as best available technologies in the final ELGrule.50 Chemical precipitation and biological treatment (CBPT) has anestimated electricity requirement of 0.71 kWh/m3,48 while mechanicalvapor recompression has an estimated electricity requirement of 21kWh/m3 at a 65% recovery and feed temperature of 56 °C.48

= A a Vi i (8)

Note that while we consider both the thermal and electricityconsumption of water deionization processes, we do not allowmultiple water deionization processes to be installed at the plantsimultaneously. In other words, the plant cannot treat half of the FGDwastewater volume using a thermal process and the other half of thevolume using an electricity-driven process.Revenue Impacts of Steam Allocation. We evaluate the effects

of steam allocation SE, SW, and SC on hourly revenue, R in $/h, fromthe retrofitted 550 MW plant. To do so, we multiply the production ofelectricity, E in kWh/h and water, W in m3/h, and captured carbon, Cin tonne CO2/h, above the minimum emissions emissions controlrequirements for the plant,Wrequired in m

3/h and Crequired in tonne CO2/h, by the price for electricity, the price for treated water, and a price ofcarbon (eq 9).

= − + − + −R e E A C w W W c C C( ) ( ) ( )i press required required, (9)

We derive eq 10, the objective function for our optimization, bycombining eq 9 with eqs 1, 2, and 6. The decision variables in this

model (SE, SW, and SC) are constrained to be between 0 and 1 with thesum of the three equal to one (eqs 11−14).

η= − × −−

+−

− +−

−

⎡⎣⎢⎢⎛⎝⎜

⎞⎠⎟

⎤⎦⎥⎥

⎛⎝⎜⎜⎡⎣⎢⎢

⎤⎦⎥⎥

⎞⎠⎟⎟

⎛⎝⎜⎜⎡⎣⎢⎢

⎤⎦⎥⎥

⎞⎠⎟⎟

R e S m h h kWhkJ

aS m h h

H

wS m h h

HW c

S m h hH

C

max ( )1

3600

( )

( ) ( )

RE in out i press

C in C out C

C j

W in out

w irequired

C in out

C j

required

,, ,

,

, ,

(10)

Subject to

≤ ≤S0 1E (11)

≤ ≤S0 1W (12)

≤ ≤S0 1C (13)

+ + =S S S 1E W C (14)

As noted above hin,E, hin,W, and hin,C are equal for all three turbines,while hout,E, hout,W, hout,C are equal only for the HP and IP turbine.

We assume a constant price for electricity, e, of $0.043/kWh. Wetreat the price of water, w in $/m3, and the shadow price of carbon, c in$/tonne CO2, parametrically based on six different regulatoryenvironments. The parametric carbon prices are carbon prices of$0/tonne CO2 (for a scenario without carbon regulations) and$59.44/tonne CO2 (the social cost of carbon in 2030, when the CleanPower Plan was scheduled to come into effect, with a 3% discountrate).51 The two wastewater treatment scenarios are for a chemicalprecipitation and biological treatment (CPBT) standard under theELGs with an expected w of $0.05/m3 or zero liquid discharge (ZLD)standard under the ELGs with an expected w of $2.62/m3.48 To thesefour scenarios, we add two additional scenarios with wastewatertreatment, but no carbon capture. A summary of the 66 regulatoryscenarios and technology options can be found in SI Section 3 andTable S3. If the plant does not meet its water treatment or carboncapture requirements, the plant can either pay for off-site watertreatment at these prices or purchase carbon credits in a cap and trademarket. Alternatively, if the plant exceeds its requirements, it can offerindustrial water treatment services or sell carbon credits in a cap andtrade market.

Figure 2. Parasitic losses from (A) carbon capture and compression and (B) FGD wastewater treatment processes. For carbon capture technologies,we compare the most efficient thermal process (Cansolv) to the most efficient electricity driven membrane separation process. These estimatesinclude 10.5 MW and 8.9 MW of auxiliary electricity generation penalties for CO2 compression in the Cansolv and membrane separation processes,respectively. (See SI Section 1.3 and Figure S1 for calculations of the relative efficiency of four thermal carbon capture technologies). For wastewatertreatment technologies, we compare the parasitic loads of waste heat and electricity driven forward osmosis, electricity driven mechanical vaporrecompression, and steam and electricity driven thermal vapor recompression. (See SI Section 2.3 and Figure S3 for calculations of the relativeefficiency of four different thermal separation processes). Estimates of electricity generation penalties account for parasitic losses associated with theuse of LP steam, electricity consumption imposing an auxiliary electricity load, and residual heat (RH) imposing no electricity generation penalty.N.B.: The scale of the y-axis is different in the two graphs.

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To simplify the revenue maximization process, we assume theretrofitted plant first allocates residual heat, then assigns steam orelectricity to environmental controls. We systematically explore thedecision space of our revenue model (eq 10) and alternative values ofSE, SW, and SC using the Matlab programming platform.52 As themodel is linear, we then identify the optimal values of SE, SW, and SC byinspection using the max function in Matlab. This assumption isreasonable as the case study plant maximizes its revenue by generatingelectricity (as shown in SI Section 4 where this assumption is relaxed),and there are no economically feasible technologies for convertingresidual heat to electricity.This analysis is performed only for hourly plant revenue, rather than

for profit, for three reasons. First, the costs of carbon capture andwater treatment technologies are highly uncertain and will dependlargely on the capacity factor of the plant. Second, variability in capitalcosts between different compliance technologies are likely to besmaller than the differences in operating costs between technologies.Finally, the energy-associated operational costs of these separationtechnologies are likely to exceed the capital costs.

■ RESULTS AND DISCUSSION

We calculate the trade-offs between electricity generation andcarbon capture and between electricity generation and watertreatment. For both carbon capture and water treatment, wegraphically present the trade-offs in allocating steam betweenelectricity generation and environmental controls. Finally, wecombine electricity generation, carbon capture, and watertreatment into one model and evaluate the revenueimplications of energy allocation decisions.Trade-Offs Between Steam for Electricity Generation

and MEA Carbon Capture Solvent Regeneration. Wehave calculated the electricity generation penalties for carboncapture at the 550MW PCC plant using a residual heat andsteam driven Cansolv process, a steam-only Cansolv process,and an electricity-driven membrane-based separation process(Figure 2A). Note that this analysis does not include any of thecosts or energy consumption associated with CO2 transport orunderground storage.6,45 The Cansolv process captures themost carbon per unit of steam, imposing a parasitic loss of 170kWh/tonne CO2 when steam is pulled from the LP turbine(Figure S9A). Compressing carbon captured using Cansolv to150 bar would require an additional 85 kWh/tonne.34 Thiswould reduce revenue $3.70/tonne or $450/h. Meeting the1400 lb/MWh standard for coal-fired generators via theCansolv process uses 301 GJ/h of LP steam and imposes anequivalent electricity penalty of 31.6 MW. The equivalentelectricity-driven membrane separation process consumes 31.9MW. The trade-off between electricity generation and carboncapture for all five carbon capture technologies can be found inFigure S1 of SI Section 1.3. Parasitic losses from the four

thermal technologies are shown in Figure S9 of SI Section 5.Alternatively, the plant may reduce this electricity penalty byallocating residual heat for carbon capture processes. There issufficient residual heat to capture 80% (98 tonne CO2/h) of theCO2 required for compliance with the Clean Power Plan (122tonne CO2/h) via the Cansolv process.For reference, Figure S1 also presents the thermodynamic

minimum for MEA solvent adsorption processes and theelectricity consumption of membrane-based carbon capturetechnologies. While the electricity-driven membrane separationprocesses are favorable alternatives to drawing steam from theHP and IP turbines, the thermally driven Cansolv process ismore efficient when allocating steam from the LP turbine. Thisconclusion is robust, even after accounting for variability in theestimates of energy intensity for amine and membrane-basedcarbon capture processes as shown in SI Section 1.4 and FigureS2. This conclusion stems from the fact that thermal processesrecover more of the enthalpy from LP steam than the turbine−generator system.

Trade-Offs between Steam for Electricity Generationand Water Treatment. We calculated the electricitygeneration potential for wastewater treatment using forwardosmosis, mechanical vapor recompression, and thermal vaporrecompression (Figure 2B). Thermal water deionizationsystems impose significant parasitic loads, ranging from 24kWh/m3 for TVC using steam from the LP turbine to 272kWh/m3 for MSF using steam from either the HP or IP turbine(Figure S3 of SI Section 2.3 and Figure S9B of SI Section 5) for65% water recovery at a feed temperature of 56 °C. Theauxiliary power for processes with significant vacuum orpumping requirements are reported in Table S2. In eachcase, the electricity-driven MVC process imposes a smallerenergy penalty than thermal deionization processes driven bysteam diverted from the turbines. Note that the energyconsumption of all five deionization water treatment processesexceeds that of chemical precipitation and biological treatment(CPBT) processes, the ELG’s minimum treatment standard forFGD wastewater. Also note the additional ZLD treatment trainenergy requirements for pretreatment of 0.02 kWh/m3 andcrystallization of 16 kWh/m3 reported in Table 1.48

For thermal processes using residual heat at 128 °C, the mostefficient water deionization process is forward osmosis (FO).Extending previous work,8 we estimate that treatment of 111.6m3 of FGD wastewater via FO processes driven by residual heatwill consume 29.7 GJ/h of thermal energy and 0.002 MW ofauxiliary electricity. A downside of membrane-driven FOprocesses is susceptibility to scaling and the potential formembrane damage from suspended gypsum in FGD waste-

Table 1. Minimum Estimated Energy Consumption Associated with Meeting Chemical Precipitation and Biological Treatment(CPBT) Standard or Zero Liquid Discharge (ZLD) Standard by Treating 111.6 m3/h of FGD Wastewater Using Steam from theLP Turbine, Residual Heat, or Electricity

Energy Requirements of Treating 111.6 m3/h of FGD Wastewater

Thermal Energy InputElectrical Energy

InputOther Electrical Processes in the

Treatment Train48

Energy Source and OptimalTechnology

Thermal[GJ]

Assoc. Parasitic Losses[MW]

Auxiliary Electricity[MW]

Pre-Treatment[MW]

Crystallization[MW]

Total[MW]

CPBT Electricity CPBT 0 n/a 0.079 n/a n/a 0.079

ZLD LP Steam TVC 23.5 2.6 0.19 0.022 1.2 4.0Exhaust Gas FO 29.7 0 0.003 0.022 1.2 1.2Electricity MVC 0 n/a 1.52 0.022 1.2 2.74

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Figure 3. Revenue per hour as a function of steam, residual heat, and electricity used for environmental compliance. The price of electricity for allplots is $43/MWh. In panels (A) and (B) CO2 is not captured. In panels (C)−(E) CO2 is captured and compressed. For panels (C) and (D) there isno price on CO2 while in panels (E) and (F) avoided CO2 emissions are valued at the social cost of carbon of $59.44/tonne. In panels (A), (C), and(E) FGD wastewater is treated to a CPBT standard and in panels (B), (D), and (F) FGD wastewater is treated to a ZLD standard.

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water.53 Additional research and piloting is critical toestablishing the viability of exhaust heat capture and utilizationin FO processes for FGD wastewater treatment.The energy optimal thermal technology for ZLD water

treatment at an energy penalty of 21 kWh/m3 is TVC. TVCwith an energy penalty of 24 kWh/m3 could be competitive inreal systems after accounting for operational inefficienciesincluding variable divalent cation concentration, scaling, andramping. Indeed, the observed energy consumption of MVCand TVC systems in other industrial wastewater treatmentapplications is often comparable.21,47,54

Revenue Trade-Offs in Steam Allocation. We combinethe trade-off curves shown in SI Figures S1 and S3 withretrofitted NETL plant limits on residual heat availability toidentify the revenue maximizing allocation of electricity, steam,and residual heat to meet carbon capture and water treatmentrequirements under either CPBT or ZLD standards. Note thatthese trade-off curves include the auxiliary electricity con-sumption of the separation processes. In the absence ofenvironmental control technologies, electricity generation fromthe LP turbine produces revenues of $11,245/h. The additionof environmental control technologies powered by electricity,steam, or residual heat can reduce this revenue by up to $1457/h. Capturing excess CO2 to bank carbon credits would furtherwiden this revenue window. Conducting this analysis on thebasis of hourly revenue reflects the fact that operating costs arethe majority of life-cycle costs for many of the technologies weexamine, and operating costs are likely to be more variable thancapital costs. The contours of that decision space as a functionof carbon price and the selected level of wastewater treatment(i.e., CPBT standard or ZLD standards set by EPA) arepresented in Figure 3. The optimal allocations of electricity, LPsteam, and residual heat for all five different energy strategies(feasible combinations of electricity, steam, and residual heat) isdetailed in SI Section 4 and Figures S4−S8.The revenue maximizing energy allocation strategy depends

on the decision to deploy CPBT or ZLD FGD wastewatertreatment trains at the retrofitted model NETL power plant,the date that carbon capture regulations come into effect, andthe value of avoided carbon emissions. Under the 2020regulatory scenario depicted in Figure 3A and B, carbon captureis not required for existing sources. It is more cost effective totreat wastewater using electricity-driven CPBT processes(Figure 3A) than residual heat powered FO processes, themost cost-effective ZLD option in this scenario.If the Clean Power Plan were to come into effect in 2030, the

retrofitted NETL model plant would maximize revenue byallocating all residual heat (243 GJ) and a small amount of LPsteam (59 GJ) to carbon capture processes using Cansolv(Figure 3C). Even if changes are made to the plant that reducethe amount of residual heat, the optimal allocation solutiondoes not change. In all cases, the optimal solution will first useany available residual heat and second will use LP steam tomake up the balance of energy needs. Complying with theCPBT standard is significantly more cost effective thancomplying with the ZLD one, as all residual heat has beenallocated to carbon capture processes. Instead, ZLD isperformed using electricity-driven MVC processes that directlyreduce plant revenue. These results are based on the plantoperating at full load. If the plant expects to operate below itsrated capacity, thermally driven technologies may be preferredas operating at partial loads reduces the efficiency of electricitygeneration.

In the final scenario, the retrofitted plant is given the optionof capturing carbon in excess of the mandatory minimumcapture rate and selling the resulting carbon credits at theInteragency Working Group’s social cost of carbon price of$59.44/tonne in 2030 (in 2015 dollars).51 A revenueswitchover analysis between delivering additional electricity tothe grid or capturing more carbon for sale on a carbon tradingmarket is provided in SI Section 6 and Figure S10. Consideringonly the carbon separation process and at an electricity price of$43/MWh, it is beneficial to capture excess CO2 at a priceabove $12.12/tonne and so the plant maximizes revenue bycapturing excess carbon to sell carbon credits. Whenconsidering the CO2 compression, transport, and undergroundstorage costs, this CO2 price will need to be significantly higher.Again, residual heat is fully allocated to carbon capture, so themost cost-effective technologies for meeting either the CPBTor the ZLD standard are electricity-driven processes.

Data Needs for Environmental Compliance DecisionMaking. With improved data availability, the decision-makingframework presented in this paper can be adapted to model theheat flows of specific power plants, the observed (rather thansimulated) efficiencies of installed air and water pollutioncontrol technologies, and the value of cost or efficiencyinnovations in control processes. In addition, plant-level dataon heat quality and availability under partial load conditionswould enable a more accurate assessment of revenuemaximizing decisions for low capacity factor plants. Finally,improved availability of plant-level capital and operating costswould move the model from a revenue-maximizing model to aprofit maximizing model.

■ IMPLICATIONSFully transitioning away from high air, water, and carbonemission intensity coal-fired electricity generation is expected totake several decades. In the meantime, regulatory action tominimize the human health and environmental impacts of coal-fired electricity generation will require extensive retrofit ofexisting CFPPs. The possible combinations of air and wateremissions control technologies that could be installed at plantsare vast, and design guidance on optimal retrofit approaches isseverely lacking.Using the NETL 550 MW CFPP as a case study, this work

evaluates the energy efficiency and revenue implications ofretrofitting a plant to comply with carbon capture andwastewater effluent standards. We evaluate several combina-tions of carbon capture and wastewater treatment technologies,as well as several different energy sources for driving theseseparations processes. In so doing, we provide the firstestimates of potential energy offsets associated with usingresidual heat captured at the power plant to drive carboncapture technologies. We also provide the first estimates ofparasitic losses associated with wastewater treatment under thepending deadlines for compliance with newly promulgatedELGs. Finally, this work is the first to evaluate carbon captureand water treatment retrofits simultaneously.This work demonstrates that plants undergoing retrofit will

maximize their revenue by generating as much electricity aspossible, while minimizing dispatch of steam and auxiliaryelectricity to environmental controls. As a result, each revenuemaximizing case fully utilizes residual heat resources for watertreatment or carbon capture, though the allocation of thisresidual heat between end uses depends upon regulatory andmarket forces. Minimizing the cost of plant compliance with

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environmental regulations will reduce rate increases experi-enced by rate payers in the transition to a lower human healthand environmental impact electricity system dominated byrenewable and natural gas generation.Evaluating multiple plant retrofits simultaneously is also

critical to capturing the effects of regulatory uncertainty inshaping plant decisions about technology adoption. Under ahigh uncertainty regulatory future, plants may choose tooptimize energy allocation according to near-term compliancerequirements. For CFPPs today, this would entail allocatingresidual heat to FO water treatment to comply with upcomingELG deadlines. In the long term, however, this capitalinvestment may represent a suboptimal allocation if carboncapture technologies are eventually mandated. Greaterregulatory certainty will improve the probability that plantsmake optimal technology selections and minimize the costs ofemission control.

■ ASSOCIATED CONTENT*S Supporting InformationThe Supporting Information is available free of charge on theACS Publications website at DOI: 10.1021/acssusche-meng.7b04316.

(1) Energy consumption of carbon capture and thetrade-offs of using different technologies, (2) energyconsumption of water treatment and the trade-offs ofusing different technologies, (3) regulatory scenarios andtechnology option combinations in this analysis, (4)maximum revenue strategies for the six differentregulatory scenarios included in the analysis, (5) parasiticlosses for carbon capture and water treatment, and (6)switchover analysis for carbon and electricity prices.(PDF)

■ AUTHOR INFORMATIONCorresponding Author*E-mail: mauter@cmu.edu. Telephone: (412) 268-5688.ORCIDMeagan S. Mauter: 0000-0001-6946-7213NotesThe authors declare no competing financial interest.

■ ACKNOWLEDGMENTSThis work was supported by the National Science Foundationunder award number SEES-1215845 and CBET-1554117. Thismaterial is based upon work supported by the Department ofEnergy under Award Number DE-FE0024008. D.B.G. alsoacknowledges support from The Pittsburgh Chapter of theARCS Foundation (Achievement Rewards for CollegeScientists), the Steinbrenner Graduate Fellowship, and thePhillips & Huang Family Foundation Fellowship.

■ SYMBOLSA = Hourly Auxiliary Electricity Demand [kWh/h]a = Electricity Demand per m3 of Water [kWh/m3]C = Carbon Captured per Hour [tonne CO2/h]c = Social Cost of Carbon [$/tonne CO2]E = Electricity Generation per Hour [kWh/h]e = Electricity Price [$/kWh]HC = Heat Duty in the MEA Regeneration Column [tonneCO2/kJ]

Hw = Heat Duty for Water Treatment [m3/kJ]h = Enthalpy of Steam [kJ/kg]η = Isentropic Efficiency of the Turbine-Generator [-]m = Mass Flow Rate of Steam [kg/h]P = Parasitic Loss [kWh/m3] and [kWh/tonne CO2]R = Hourly Revenue [$/h]S = Share of Mass [%]V = Volume of FGD Wastewater to be Treated [m3/h]W = Water Production per Hour [m3/h]w = Water Price [$/m3]ω = Specified Water Production [m3/h]χ = Specified Carbon Capture [tonne CO2/h]

Subscriptsc = Sent to Carbon CaptureE = Sent to Electricityi = Wastewater Treatment Technologyin = Steam into Turbine, Water Treatment, and MEARegeneration ColumnJ = Carbon Capture Technologyout = Steam out of Turbine, Water Treatment, and MEARegeneration Columnpress = Pressurizationrequired = Required Water Treatment or Carbon Capture forEnvironmental ComplianceW = Sent to Wastewater Treatment

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