Sourcing of Steam and Electricity for Carbon Capture Retrofits

Subscriber access provided by University of Virginia Libraries & VIVA (Virtual Library of Virginia)

Article

On the Sourcing of Steam and Electricity for Carbon Capture Retrofits Sarang D. Supekar, and Steven J. Skerlos Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.7b01973 • Publication Date (Web): 02 Oct 2017 Downloaded from http://pubs.acs.org on October 10, 2017

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a free service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are accessible to all readers and citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

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

Page 1 of 38

Environmental Science & Technology

On the Sourcing of Steam and Electricity for Carbon Capture Retrofits Sarang D. Supekar†, Steven J. Skerlos*,†,‡ †

Department of Mechanical Engineering, University of Michigan, Ann Arbor, MI 48109, United

States ‡

Department of Civil and Environmental Engineering, University of Michigan, Ann Arbor, MI

48109, United States

*

Corresponding author. Address: 3001F EECS, 1301 Beal Avenue, Ann Arbor, MI 48109-

2122, USA. Phone: (734) 615-5253. Fax: (734) 647-3170. Email: [email protected]

ACS Paragon Plus Environment

1


Page 2 of 38

1

ABSTRACT

2

This paper compares different steam and electricity sources for carbon capture and sequestration

3

(CCS) retrofits of pulverized coal (PC) and natural gas combined cycle (NGCC) power plants.

4

Analytical expressions for the thermal efficiency of these power plants are derived under 16

5

different CCS retrofit scenarios for the purpose of illustrating their environmental and economic

6

characteristics. The scenarios emerge from combinations of steam and electricity sources, fuel

7

used in each source, steam generation equipment and process details, and the extent of CO2

8

capture. Comparing these scenarios reveals distinct trade-offs between thermal efficiency, net

9

power output, levelized cost, profit, and net CO2 reduction. Despite causing the highest loss in

10

useful power output, bleeding steam and extracting electric power from the main power plant to

11

meet the CCS plant’s electricity and steam demand maximizes plant efficiency and profit while

12

minimizing emissions and levelized cost when wholesale electricity prices are below 4.5 and 5.2

13

US¢/kWh for PC-CCS and NGCC-CCS plants, respectively. At prices higher than these, higher

14

profits for operating CCS retrofits can be obtained by meeting a 100% of the CCS plant’s electric

15

power demand using an auxiliary natural gas turbine-based combined heat and power plant.


2

Page 3 of 38

16


INTRODUCTION

17

Thousands1 of fossil fuel-fired power plants with carbon capture and sequestration (CCS) may

18

be needed to supply 20 – 43%2–6 of the world’s electricity by 2050 to meet the 2 ºC climate

19

target.7 Reaching this goal would involve retrofitting more than a TW8 of the world’s existing

20

fossil power plant fleet in addition to constructing new advanced9–12 CCS power plants. This

21

study focuses on the environmental and economic characteristics of amine-based post-

22

combustion CCS retrofits to pulverized coal (PC) and natural gas combined cycle (NGCC) CCS

23

power plants. This scope is chosen since amine-based CCS is the most commercially mature

24

technology for retrofits9,13 with reliable process and cost data, and because PC and NGCC plants

25

make up most of today’s global fossil fuel plant capacity.

26

Low pressure (LP) steam for CO2 desorption and solvent regeneration is the largest

27

contributor9,14 to an amine-based CCS unit’s energy consumption, with estimates for CCS steam

28

flow rates ranging from 29 – 79%15–17 of the power plant boiler’s total steam flow rate (see

29

Supporting Information (SI) for explanation). The electricity consumption of CO2 compression

30

is the second largest contributor to the CCS unit’s energy consumption.9,14 Different choices for

31

sourcing CCS steam and electricity can thus significantly influence a retrofit power plant’s

32

thermal efficiency, as well as its CO2 emissions and cost of electricity (COE). For instance,

33

meeting the steam and electricity demand of the capture unit from within the main plant avoids

34

the added costs of building, maintaining, and operating a new auxiliary power plant to

35

supplement CCS heat and electricity demands. However, this approach causes a considerable

36

drop in useful electric power output from the main plant, referred to in the literature as

37

“derating”. Depending on the price of electricity, a likely drop in profits and potential loss of


3


Page 4 of 38

38

influence in competitive wholesale electricity markets could justify building a more thermally

39

efficient new auxiliary power plant for CCS energy demands.

40

Quantitative analyses of environmental and economic implications for various retrofit

41

scenarios stemming from different steam and electricity sourcing choices for CCS retrofits are

42

largely absent from the literature, with the exception of studies that have discussed cost-

43

minimizing optimal process conditions18–20 or optimal rates of CO2 capture21,22 within a single

44

CCS retrofit scenario. To address this gap in the literature, this work develops a set of analytical

45

expressions for the thermal efficiency of an amine-based post-combustion PC power plant under

46

eleven CCS retrofit scenarios, and an NGCC power plant under five CCS retrofit scenarios. In

47

future work these expressions could be extended to other solvents such as piperazine and KS-1,

48

as well as other CCS technologies including IGCC, oxyfuel, and membrane separation.

49

The analytical expressions for the different retrofit scenarios are used to comment on the

50

power plant’s thermal, economic, and environmental performance metrics, and to draw

51

conclusions regarding optimal retrofit strategies based on a careful evaluation of trade-offs

52

within and across retrofit scenarios. Thermal performance metrics evaluated are: efficiency

53

penalty (%-points); energy penalty on a plant heat input and electrical output basis (%); and

54

power plant derating (%). Environmental performance metrics evaluated are: non-renewable

55

energy use (PJ/year); overall reduction in CO2 emissions (%); and CO2 intensity of electricity

56

sold (kg CO2/kWh). Economic performance metrics evaluated are: levelized COE (US¢/kWh);

57

marginal COE (US¢/kWh); short-run profit (million US$); and abatement cost (US$/tonne CO2

58

avoided relative to identical plant without CCS). Metrics expressed in % values represent relative

59

change with respect to their value before the CCS retrofit.


4

Page 5 of 38


60

METHODS

61

Mass and energy feedbacks in CCS power plants

62

Adding CCS to a power plant creates what is commonly referred to in the literature as an

63

“energy penalty”. The energy penalty is defined as the relative drop in useful electric power

64

output for a given heat input, or the relative increase in heat input for a given power output

65

compared to a power plant without CCS. If any additional fuel were combusted to meet the CCS

66

unit’s energy demand and/or make up for lost useful electric power from the power plant, it

67

would generate more CO2, which needs to be captured. This in turn would require more capture

68

energy and would lead to the combustion of even more fuel, creating a recursive feedback loop

69

in the mass and energy balance of the power plant (see SI for a discussion on the convergence

70

condition for this recursive feedback). The energy penalty for such a CCS retrofit would thus be

71

a function of more than just the amount of CO2 generated in the power plant before CCS, the

72

CO2 capture efficiency, and the specific heat (

73

capture unit.23,24 As more CO2 is generated, the effective reduction in CO2 will necessarily be

74

lower than the CO2 capture efficiency. The inclusion of this mass-energy feedback is thus

75

central to the accurate estimation of a retrofit CCS power plant’s overall thermal efficiency and

76

its overall economic and environmental performance.

77

Retrofit scenarios

) and electricity (

) requirement of the

78

The process of CO2 capture from flue gases of both PC-CCS and NGCC-CCS power plants is

79

modeled assuming that amine separation and dehydration steps alone are sufficient to obtain the

80

necessary purity of CO2 (see Fig. S1 and Table S1 for process flows and conditions).23 The


5


Page 6 of 38

81

capture efficiency of the amine-based CCS process is assumed to be 90% as a representative

82

value. Literature on CCS retrofits20,25–31 discusses the sources of LP steam and electricity for

83

CCS, which are: (1) the main power plant itself (an approach referred to as an “integrated”

84

retrofit); (2) an auxiliary combined heat and power (CHP) plant; or (3) a combination of the two

85

approaches. Fig. S2 shows the general energy flows for these three retrofit approaches.

86

In an integrated retrofit, the energy demand of the CO2 capture unit is met from within the

87

main power plant, and no additional fuel is burnt for CCS. LP steam is obtained by bleeding the

88

crossover connection between the intermediate-pressure (IP) and LP stages of the main turbine,

89

and electricity for the capture plant is obtained from the main generator. Advanced stripper

90

configurations in the capture unit and other factors including the pre-capture efficiency and

91

residual life of the power plant can result in significant levels of heat integration through

92

elaborate networks of heat exchangers14,17,32–34 that can achieve the specific heat requirement of

93

3.09 and 3.235 MJth/kg CO2 considered here for PC-CCS and NGCC-CCS plants respectively.

94

Additional heat integration can be obtained from potential coupling of advanced flue gas

95

desulfurization (FGD) unit with the power plant steam cycle9,36 among other approaches. While

96

possible in theory, it should be noted that such added levels of heat integration, which is

97

considered here through a sensitivity analysis, may not always be feasible due to an existing

98

power plant’s design, space, or economic constraints.24,28,30,37

99

Retrofit scenarios other than integrated retrofits involve building a smaller boiler-based or gas

100

turbine-based auxiliary CHP plant. The auxiliary CHP plant could generate steam in either a

101

high-pressure (HP) boiler or by using a gas turbine that is followed by a heat recovery steam

102

generator (HRSG). In either approach, the HP steam generated would be expanded through a

103

non-condensing backpressure turbine (BPT) to obtain LP steam for the capture process. The


6

Page 7 of 38


104

auxiliary plant would also generate electric power from the BPT and/or the gas turbine for the

105

capture process.

106

The auxiliary CHP plant could be “heat-matched” or “power-matched” depending on whether

107

it meets 100% of the steam demand or 100% of the electricity demand of the capture unit. Any

108

unmet electricity and/or steam demand for CO2 capture is then met from the main plant. The fuel

109

of choice to power auxiliary CHP plants with gas turbines is usually natural gas. However, in

110

auxiliary CHP plants with a boiler, both coal and natural gas could be used as fuels, although it is

111

unlikely that boilers for NGCC-CCS retrofits would use coal.

112

In the case of PC-CCS retrofits with natural gas as the auxiliary CHP fuel, the lower CO2

113

concentration and partial pressure of the auxiliary plant would necessitate CO2 capture of the two

114

exhaust streams in separate capture units.

115

generated, capturing CO2 from the auxiliary gas-fired plant may or may not be practical. The

116

performance of PC-CCS retrofits is evaluated considering gas-based auxiliary CHP plants, both

117

with and without CO2 capture from the auxiliary plant to understand the conditions under which

118

the auxiliary CO2 capture approach may be a viable option. Recent work20,31,38 suggests that a

119

hot wind box that recirculates the gas turbine exhaust into the main boiler could help achieve a

120

CO2 concentration that can be handled by a capture unit designed for a coal boiler exhaust. This

121

approach is not considered here only due to a current lack of available data on its performance

122

and costs from pilot or commercial-scale plants.

Depending on the quantity of additional CO2

123

The analysis considers eleven retrofit scenarios for PC-CCS and five retrofit scenarios for

124

NGCC-CCS power plants from which power plant operators are currently likely to choose one.

125

Fig. 1 shows the combination of factors that lead to these retrofit scenarios. Embedded within

126

the sixteen retrofit scenarios are additional design parameters such as steam conditions,


7


Page 8 of 38

127

efficiencies of auxiliary plant components such as boiler, gas turbine, HRSG, steam turbine, and

128

extent of waste heat integration that are kept constant and do not vary across scenarios for clarity

129

of presentation. These factors are accounted for within the analytical expressions for the thermal

130

efficiency penalty derived in the next section and can be modified directly by manipulating the

131

equations.

132 133 134

Fig. 1 CCS retrofit scenarios for pulverized coal (PC) and natural gas combined cycle (NGCC) power plants considered in this study.

135

Mass and energy balance equations

136

Here, and throughout the rest of this paper, subscripts 1 and 2 denote an association with the

137

main and auxiliary plants, respectively. For instance, the total steam and electricity outputs from

138

the main and auxiliary plants are denoted by

139

and

and

and

, respectively.

and

represent the total steam and electricity consumption to capture CO2 at a rate of

140

with an efficiency of

141

where

. Eqs. (1) – (3) describe the relationship between these quantities,

is the CO2 content of the fuel on a mass basis,

is the mass flow rate of fuel,


8

Page 9 of 38


142

and

143

CO2 generated from the auxiliary CHP plant that is eventually captured.

are the heat and electricity demands per unit of CO2 captured, and

is the fraction of

144

(1)

145

(2)

146

(3)

147

and

represent the contribution of the auxiliary CHP plant in meeting the thermal and

148

electric power demand of the CO2 capture unit. Eqs. (4) and (5) reflect the fact that any unmet

149

capture electricity and/or steam demand would be met using electricity and steam from the main

150

plant (see Fig. S2A). When an auxiliary CHP plant is not used, Eqs. (1) – (3) still apply with

151

set to zero. In such cases,

and

are also zero. Further,

and

are

152

defined as the fractions of the total steam and electric power demand of the capture unit met by

153

the auxiliary CHP plant, as given by Eqs. (6) and (7). Thus, for a heat-matched retrofit,

154

would be 1, and for a power-matched retrofit,

155

approach, both steam and electricity are produced, which would reduce some amount of the

156

capture steam and/or electricity diverted from the main power plant.

would be 1. It should be noted that in either

157

(4)

158

(5)

159

(6)

160

(7)


9


161

The thermal efficiencies of a power plant without CCS (

Page 10 of 38

) and with CCS (

)

162

are given by Eqs. (8) and (9), where Eq. (10) represents the efficiency penalty in %-points. In

163

these equations,

164

power available for sale.

165

power output lost as a result of extracting a unit of thermal power in the form of steam from a

166

steam turbine. In cases where excess power is available for sale from the auxiliary plant, this

167

excess power can be calculated using Eq. (12), in which superscripts ST and GT refer to steam

168

and gas turbines.

is the lower heating value of the fuel and

represents the net electric

in Eq. (11) is the power equivalence factor, or the amount of electric

169

(8)

170

(9)

171

(10)

172

(11)

173

(12)

174

(13)

175

With mass-energy feedbacks in mind, a set of analytical expressions are developed for the fuel,

176

steam, and CO2 flow rates in the auxiliary and main plants based on the specific (per unit of CO2

177

captured) heat and electricity demand,

178

of feedbacks, and

,

,

. Note that

and

are independent

is assumed to remain unchanged post-retrofit since capital-intensive


10

Page 11 of 38


179

components such as turbines in the existing main plant are designed for safe operation for a

180

given value of

181

the final expressions for

182

determined as explained in the SI, are included here. Table 1 shows these expressions for the

183

retrofit scenarios selected for presentation in this study.

184 185

Table 1. Expressions for fuel flow rate in the auxiliary CHP plant incorporating mass-energy feedbacks in CCS power plants. CCS retrofit scenario

. Step-by-step derivations of these expressions are provided in the SI. Only , from which all other plant performance quantities can be

Fuel flow rate in auxiliary CHP plant

Integrated No auxiliary plant,

(14)

Heatmatched with auxiliary boiler CHP plant

(15)

with auxiliary gas turbine CHP plant

(16)

Powermatched with auxiliary boilerbased CHP plant

(17)


11


CCS retrofit scenario

Page 12 of 38

Fuel flow rate in auxiliary CHP plant

with auxiliary gas turbinebased CHP plant

(18)

186 187

For the expressions in Table 1:

188

, and

denotes the efficiency of the auxiliary boiler;

respectively denote the enthalpies of the HP steam, LP steam, and

189

condensate in the auxiliary plant;

190

steam turbine;

191

the exhaust gas after it has passed through the HRSG;

192 193 194

,

is the isentropic efficiency of the auxiliary back-pressure

is the enthalpy of the gas turbine exhaust;

is the enthalpy of

is the rated efficiency of the HRSG;

is the air to fuel mass flow rate ratio in the gas turbine combustion chamber; and

is the

efficiency of the gas turbine in converting heat input to useful electric power output. Once the values for

and

are determined based on the value of ) and electric (

and Eqs. (2) –

195

(7), the value for the balance steam (

) power met from the main plant

196

can be calculated using Eqs. (19) and (20). Although partial (< 90%) CO2 capture is also an

197

option21 that can be evaluated using the expressions derived here (by assigning an appropriate

198

value to

), the case of partial capture is not discussed below in the interest of brevity.

199

(19)


12

Page 13 of 38


200

201

(20)

Profit equations

202

Profitability plays an important role in the decision whether and how to retrofit a power plant

203

with CCS. Both the levelized COE13,17,39 and the marginal COE are considered in the context of

204

a given electricity price as a retrofit is implemented. Eq. (21) defines the short-run profit in US$

205

(

206

power producer receives in a competitive market,

207

) for a CCS power plant.

(US¢/kWh) is the average annual price of electricity that a is the average annual capacity factor,

(US¢/kWh) is the marginal COE of the power plant before the CCS retrofit,

208

(US¢/kWh) is the increase in marginal COE after the CCS retrofit,

(kW) is the

209

plant’s power output before the CCS retrofit,

210

CCS retrofit, the constant 8760 is the number of hours in a year, and the constant 100 converts

211

US¢ to US$. The marginal cost is comprised primarily of a plant’s variable operation and

212

maintenance (O&M), fuel, and CO2 emission taxes (if any).

(kW) is the plant’s derating after the

213

214

(21)

This analysis follows other assessments in the literature13,28,40 in assuming that

and

215

will be the same for large base load power plants (suitable candidates for retrofits) with or

216

without CCS. Our consideration for short-run profits over long-run profits, which include capital

217

recovery, is based on guidance provided by Stoft41 who contends that routine price spikes

218

observed in competitive wholesale electricity markets recover fixed costs including the risk-


13


Page 14 of 38

219

adjusted rate of return on capital in the long run.

220

technoeconomic assessment of power producing technologies in competitive electricity markets

221

is employed by other studies as well,42,43 including a CCS-focused study by Chalmers and

222

Gibbins.22

223

The use of short-run profits for the

It can be observed from Eq. (21) that increases in both marginal COE (

) and derating

224

(

) of the CCS-equipped plant affect the profit of the power plant. Eq. (21) thus

225

quantifies the “opportunity cost” of derating in a profit maximizing context similar to

226

MacDowell and Shah18, who discuss optimal capture rates in a levelized cost minimization

227

context. Below, the profitability of different CCS retrofit scenarios is evaluated under wholesale

228

electricity prices ranging from 3.5 – 7.5 US¢/kWh. As a reference, the average wholesale

229

electricity price received by power plants in the U.S. in 2015 was about 3.6 US¢/kWh.44

230

Key data sources and assumptions

231

Input data for the thermal, emissions, and economic performance evaluation of PC-CCS and

232

NGCC-CCS retrofit scenarios in this work are listed in Table S2 along with their sources. Pre-

233

capture efficiency of the PC and NGCC power plants is chosen as 34.7% and 46.3%,

234

respectively, based on the capacity-weighted average efficiency of U.S. plants that would likely

235

be candidates for CCS retrofits (≤ 20 years of age and ≥ 200 MW in size). Data on capture

236

process parameters such as capture heat and electricity demand per unit of CO2, also listed in

237

Table S2, are based on studies ranging from 2011 to 2015. The majority of cost data for

238

economic performance metrics are obtained from a CCS retrofit-focused International Energy

239

Agency report prepared by Gibbins et al.28 Performance metrics for different retrofit scenarios

240

are estimated using Eqs. (1) – (21). A sensitivity analysis is performed on these performance


14

Page 15 of 38


241

metrics and the conclusions based on them using a range of values for important parameters such

242

as pre-capture efficiency, capture plant costs, specific capture energy requirements, and fuel

243

prices.

244

Levelized COE calculations are based on guidelines provided by Rubin et al.45 The analyses in

245

this work apply only to plants for which retrofitting has already been deemed to be the more

246

viable option than closure. Any capital liability of the existing plant is thus excluded from

247

levelized COE calculations, and levelized COE includes only the cost of the retrofit. CO2

248

abatement costs are calculated as the ratio of the levelized cost of the CCS retrofit and the net

249

reduction in CO2 relative to the plant’s pre-CCS emissions. Transportation and storage (T&S)

250

costs for the captured CO2 are excluded. Values for CO2 reduction are based on use phase

251

emissions only. Other environmental considerations such as criteria pollutant emissions and

252

water use are not considered here but they can be calculated based on other work in the

253

literature23,46 using the thermal and environmental performance metrics provided below.

254

RESULTS AND DISCUSSION

255

Fig. 2A – C show power plant derating, net reduction in CO2 emissions, and increase in

256

levelized COE as a function of the plant’s efficiency penalty in %-points. Fig. 2D shows the

257

total fossil energy use, Fig. 2E shows the CO2 abatement cost, and Fig. 2F shows the drop in the

258

short-run profit after the CCS retrofit (relative to before the retrofit) assuming no explicit price

259

on CO2. Interested readers can find guidance on how to follow the legend and interpret the

260

results in this figure in the SI. Table S4 lists the values of the different thermal, economic, and

261

environmental performance metrics including those shown in Fig. 2. All values shown in Fig. 2

262

(and subsequent figures and tables) were calculated using the analytical expressions developed in

263

this work.


15


Page 16 of 38

264

It should be noted that heat-matched retrofits using an auxiliary gas turbine CHP plant for both

265

PC-CCS and NGCC-CCS plants necessitate auxiliary plant capacities that are likely to be

266

impractical considering that they are significantly larger than the main plant as shown in Table

267

S4. As a result, this retrofit scenario has been excluded in Fig. 2A – C. The amount of CO2

268

generated in a power-matched gas turbine-based auxiliary CHP plant in a PC-CCS retrofit is less

269

than 5% of the total CO2 generation in the plant. Therefore, addition of a separate capture unit

270

for the auxiliary CO2 from natural gas combustion is unlikely, and thus results for this scenario

271

in Fig. 2 and Table S4 are provided assuming no CO2 capture from the auxiliary CHP plant.

272 273 274 275 276 277

Fig. 2 Performance of different CCS retrofit scenarios for PC and NGCC power plants. Each bubble represents a unique retrofit scenario described according to the legend, and the size of the bubble represents the CO2 intensity of the electric output of the respective power plant after the retrofit. Efficiency penalty (%-points), derating, CO2 reduction, COE, and abatement costs are all expressed relative to the corresponding power plant without CCS. Drop in annual short-run


16

Page 17 of 38


278 279

profit is expressed as a relative change over its pre-CCS profit as a function of wholesale electricity price.

280

To bleed or not to bleed the main turbine

281

It is observed that the thermal efficiency penalty follows the general trend of integrated
power-matched > heat-matched. This trend is in direct

284

proportion to the amount of steam bled from the main turbine to meet the heat requirements of

285

the CO2 capture plant, which follows the same order as derating. There is thus a clear trade-off

286

between a CCS plant’s thermal efficiency and net power output, as has been noted in other

287

studies,18,47,48 whereby reducing plant derating will come an the expense of plant efficiency.

288

Fig. 2B shows that high plant efficiency (low efficiency penalty) goes hand-in-hand with low

289

CO2 emissions (high CO2 reduction). By extension, this means that lower CO2 emissions would

290

also come at the expense of higher derating with respect to the discrete CCS retrofit scenarios

291

discussed here.

292

PC-CCS plants with auxiliary boiler-based CHP plants can use natural gas boilers instead of

293

coal boilers as a way to reduce CO2 emissions, maintain the power output, and improve plant

294

efficiency as shown in Fig. 2A – B. Use of a gas turbine CHP with a backpressure steam turbine

295

instead of a natural gas boiler can further increase plant efficiency and CO2 reduction. In fact,

296

Fig. 2A and Fig. 2C show that for the subcritical PC plant specifications and economic data used

297

in this study, a power-matched CCS retrofit using an auxiliary gas turbine-based CHP plant can

298

provide an efficiency gain of 1.5 %-points and an additional power output of about 51 MW over

299

an integrated retrofit at about 10% lower levelized COE, and 23% lower CO2 abatement cost. It

300

would, however, cause a 7% increase in marginal COE, 6% increase in fossil energy use and

301

have a 25% higher CO2 intensity. Using natural gas to supplement any form for capture energy


17


Page 18 of 38

302

in a PC-CCS plant may also expose the power plant to potentially higher fuel price volatility

303

compared to the relatively stable markets for both coal and electricity.

304

From a levelized COE, efficiency, and CO2 reduction standpoint, using a power-matched gas

305

turbine-based auxiliary CHP retrofit would be the preferred scenario for PC-CCS plants.

306

However, a plant’s post-CCS profit is an important metric in choosing a retrofit scenario. Fig.

307

2F shows that despite having a higher levelized COE and lower efficiency than a gas turbine-

308

based auxiliary CHP retrofit, an integrated retrofit in a PC-CCS plant would still lead to higher

309

profits (lower drop in profit in Fig. 2F) at electricity prices below 4.5 US¢/kWh (

310

because the economic value of lost power is not significant enough at those prices to compensate

311

for the relatively higher marginal COE faced by the gas turbine-based power-matched retrofit

312

(see Eq. (21)). Therefore, at current average wholesale prices of about 3.6 US¢/kWh in the U.S.,

313

an integrated retrofit would be the more profitable option for PC-CCS plants.

314

conclusion also holds true for NGCC-CCS plants, although the value of

315

5.2 US¢/kWh. For both PC-CCS and NGCC-CCS plants, a power-matched gas turbine-based

316

auxiliary CHP can thus provide comparable CO2 reduction to integrated retrofits at a lower

317

levelized COE and abatement cost, and a higher profit in a future where electricity prices

318

increase by about 0.9 – 1.6 US¢/kWh.

). This is

The same

is higher at about

319

From Fig. 2A, it is observed that heat-matched CCS retrofits are generally an inefficient

320

approach to CCS retrofits. However, they provide surplus power generation that causes a net

321

increase in the rated capacity of the power plant. This capacity increase comes as the expense of

322

higher levelized COE due to a larger auxiliary and capture plant size, and higher marginal COE

323

due to the higher fuel consumption relative to other retrofit scenarios as seen in Table S4. This

324

increased power output can only be valuable if (a) the price of electricity is high enough to


18

Page 19 of 38


325

justify the higher capital costs and marginal COE, (b) there is sufficient land and resources such

326

as water available to build and operate the significantly larger auxiliary CHP plant and CCS unit,

327

and (c) there is sufficient transmission capacity available to dispatch surplus electricity as

328

discussed by Gibbins et al.28

329

If the conditions surrounding availability of land and other resources, transmission capacity,

330

and capital are met, Fig. 2F shows that for PC-CCS plants, a heat-matched retrofit using an

331

auxiliary CHP with a coal-fired boiler stands to be the most profitable option at wholesale

332

electricity prices higher than about 5.1 US¢/kWh. The trade-off is that heat-matched retrofits

333

lead to lower net CO2 reduction and significantly higher fossil energy use than any other retrofit

334

scenario. In NGCC-CCS plants, a weaker feedback effect due to a higher pre-CCS efficiency

335

and lower fuel CO2 content relative to PC plants leads to lower surplus electricity production

336

relative to a heat-matched PC-CCS plant. A heat-matched boiler-based auxiliary CHP retrofit

337

scenario offers no advantage in profitability over an integrated retrofit in NGCC-CCS plants

338

even at high electricity prices.

339

Although highly efficient at producing electricity, a gas turbine-based CHP plant is generally

340

less efficient at producing LP steam than a boiler-based CHP plant (using the same fuel),49

341

particularly at high steam generation pressures50 such as those typically considered in CCS

342

retrofit studies. Thus, in generating the same amount of LP steam output as a heat-matched

343

natural gas boiler-based CHP plant, a heat-matched gas turbine-based CHP plant has to burn

344

more fuel. This amplifies the mass and energy feedback effect discussed earlier (additional fuel

345

creates additional CO2 to be captured, which requires more fuel), and ultimately leads to higher

346

fuel consumption than all other CCS retrofit scenarios.


19


Page 20 of 38

347

As a result, heat-matched gas turbine-based auxiliary CHP retrofits produce more surplus

348

power than the rated capacity power of the PC or NGCC plant before the retrofit. Table S4

349

shows that in the case of PC-CCS and NGCC-CCS plants, this surplus power is respectively 2.6

350

and 1.8 times higher, which would mean the addition of several additional power generation

351

units at the power plant. This also leads to CO2 abatement costs shown in Fig. 2E that are an

352

order of magnitude higher than integrated or power-matched scenarios. Building an advanced

353

and more efficient integrated PC-CCS or NGCC-CCS plant would likely be a more cost effective

354

approach (see Table S6), making heat-matched CCS retrofits with a gas turbine-based auxiliary

355

CHP impractical.

356

Sensitivity analysis

357

To test the robustness of the performance metrics of different retrofit scenarios, the nominal

358

values (shown in Table S2) of key input parameters were varied. CCS plant capital cost was

359

varied by ±20%, fixed O&M cost was varied by ±1%-point of the capital cost, variable O&M

360

cost was varied by ±10%, fuel prices were varied by ±10%, specific capture heat and electricity

361

requirements were varied by ±10%, pre-capture plant efficiency was varied by ±5%-points, and

362

the capital charge rate was varied by ±1.5%-points. While these variations affect the absolute

363

values of metrics such as efficiency penalty, levelized and marginal COE, CO2 reduction, and

364

profit for all retrofit scenarios, they do not alter the relative order of the different retrofit

365

scenarios for the performance metrics compared in Fig. 2.

366

It is observed as expected that integrated retrofits would still be the most profitable until a

367

certain threshold price

beyond which power-matched auxiliary gas turbine based retrofits

368

are the most profitable retrofit scenario. However, it is found as well that all other factors


20

Page 21 of 38


369

remaining unchanged, plants with lower pre-capture plant efficiency face a slightly higher value

370

of

371

efficiency plants would prefer integrated retrofits and high efficiency plants would prefer power-

372

matched gas turbine-based retrofits when all other factors are held constant. This is because

373

lower efficiency corresponds to higher CO2 generation and higher derating in an integrated CCS

374

plant, and therefore the value of that lost power must be higher to justify conserving that power

375

output. In the most optimistic case of low costs, high plant efficiency, and low specific capture

376

energy requirements, the threshold prices

377

are 3.7 and 3.6 US¢/kWh, indicating that a gas turbine-based auxiliary CHP for power matching

378

would be preferred. In the least optimistic case with high costs, specific energy requirements

379

and low plant efficiency,

380

CCS plants respectively, indicating that integrated retrofits would likely be the most favorable

381

scenario.

382

scenarios under the best and worst case assumptions.

383

To capture or not to capture CO2 from auxiliary plant

and plants with a higher pre-capture efficiency face a lower value of

. That is, low

for PC-CCS and NGCC-CCS plants respectively

increases to about 6.1 and 9.1 US¢/kWh for PC-CCS and NGCC-

Fig. S5 shows this comparison between performance metrics for different CCS

384

The effects of mass and energy feedbacks in CCS systems can be avoided by avoiding the

385

capture of the additional CO2 generated in the auxiliary CHP plant. As discussed in the methods

386

section, this is a significant consideration in PC-CCS plants using natural gas-based auxiliary

387

CHP plants. To ascertain the advantage and drawbacks of capturing the CO2 from the auxiliary

388

gas-based CHP plant vis-à-vis releasing it, the parameter

389

performance metrics listed in Table S4 are recalculated using formulas from Table 1 and data


in Eq. (1) is set to 0, and the

21


390

from Table S5. Since

391

turbine CHP, we analyze this scenario by setting the value of

Page 22 of 38

is already set to 0 for power-matched PC-CCS with auxiliary gas to 1.

392

It is found that heat-matched and power-matched retrofits with a gas boiler show a marked

393

reduction in levelized COE (35% and 40%, respectively) and a reasonable improvement in

394

efficiency (1.7 and 1.0%-points, respectively) when releasing CO2 from the auxiliary plant

395

without capture, although the power output is held constant in the comparison. However, without

396

CO2 capture from the auxiliary CHP plant, boiler-based retrofit scenarios have double the CO2

397

emissions and emissions intensity relative to the corresponding scenario where auxiliary CO2 is

398

captured. It is notable that the net reduction in CO2 of 68% for the heat-matched scenario and

399

75% for the power-matched scenario is significantly less than the 90% target typically discussed

400

in the context of CCS plants.

401

However, the corresponding CO2 intensity values of 271 and 231 kg CO2/MWh for these

402

scenarios would fall well within the mandated limit of 592 kg CO2/MWh in the U.S. EPA’s

403

Clean Power Plan (CPP).51 Relative to capturing the auxiliary CO2 in existing PC-CCS plants

404

retrofitted with an auxiliary natural gas boiler-based CHP plant, not capturing the auxiliary CO2

405

could thus provide a lower-cost and higher efficiency option for regulatory compliance with

406

CPP. On the other hand, capturing the small amount of CO2 generated in a power-matched gas

407

turbine-based PC-CCS retrofit would only modestly increase CO2 reduction from 86% to 90%

408

and provide little efficiency gain.

409

Effects of a carbon price

410

To understand the effect of a carbon price on the different CCS scenarios, a carbon tax in

411

US$/tCO2 emitted is applied to power plants with and without CCS based on the plant’s post-

412

CCS emissions rate. The profit and the relative change in profit are still defined by Eq. (21).


22

Page 23 of 38


413

However, depending on the CO2 intensity of the power plant, there would be a carbon cost per

414

kWh in addition to the other operating costs. This approach shows that at prices around 25

415

US$/tCO2 that have been previously observed in European carbon markets, both PC and NGCC

416

would require CCS to stay profitable unless wholesale electricity prices increase. At carbon

417

prices closer to the social cost of carbon, which is estimated to be greater than 50 US$/tCO2 by

418

various integrated assessment models,52–54 a CCS retrofit would lead to a net increase in profit.

419

Fig. 3B and C show the annual short-run profit under a carbon price of 50 US$/tCO2 for each

420

CCS retrofit scenario as a function of wholesale electricity price. The relative order of the

421

retrofit scenarios in terms of efficiency, levelized COE, and profits of the retrofit scenarios

422

however remains similar to the scenario without a carbon price as seen in Fig. 3A – C and Fig.

423

2C and Fig. 2F, although heat-matched retrofits fare slightly better relative to integrated retrofits

424

in the presence of a carbon price.

425 426 427 428 429 430 431

Fig. 3 (A) Increase in levelized COE for various CCS retrofit scenarios under a carbon price of 50 US$/tCO2. Faded bubbles indicate values for the scenario without a carbon price that is shown in Fig. 2A. Annual short-run profit for (B) PC-CCS and (C) NGCC-CCS power with various retrofit scenarios under a carbon price of 50 US$/tCO2. Legend identical to Fig. 2. The value of the price threshold

under a carbon price of 50 US$/tCO2 is found to increase

to 6.5 US¢/kWh for PC-CCS and 5.5 US¢/kWh for NGCC-CCS plants. At even higher carbon


23


Page 24 of 38

432

prices, the value of

433

CCS plants. The difference between the profitability of the most profitable scenario and the

434

other scenarios becomes practically indiscernible, thus showing a diminishing effect of carbon

435

price on the price sensitivity of the most profitable retrofit scenario. Finally, if power plants are

436

to absorb CO2 transmission and storage (T&S) costs of about 18.5 US$/tCO255 (adjusted to

437

2015$ from data source), which effectively influence costs and profits in ways identical to

438

carbon price, PC-CCS plants would require electricity prices of about 4.5 US¢/kWh to remain

439

profitable. As with carbon price, T&S costs do not change the relative merit of the different

440

CCS scenarios discussed in the context of their performance. Naturally for CCS to gain a strong

441

footing in global energy supply, profitability considerations would need to be coupled with

442

measures to help overcome other technological, political, and social hurdles associated with CCS

443

from the capture to storage, as discussed extensively elsewhere in the literature.56–58

444

Model validation

increases for PC-CCS plants and remains more or less stable for NGCC-

445

Values for the thermal efficiency of the retrofit scenarios shown in Fig. 2A – C were calculated

446

using analytical expressions developed in this work. Here they are compared with corresponding

447

values reported by Gibbins et al.,28 which they obtain using process simulation models. Fig. S6

448

compares thermal efficiency values obtained using the analytical expressions developed in this

449

work (Eqs. (1) – (21) with Gibbins et al.28 process simulation results for eight common scenarios

450

using identical input parameters and process conditions.

451

values in this work are found to be within ± 5% (not %-points) of their simulations for all

452

integrated, heat-matched, and power-matched scenarios compared. The only exception is the coal

453

boiler-based power-matched PC-CCS retrofit scenario, for which the post-capture efficiency

The computed thermal efficiency


24

Page 25 of 38


454

value predicted by the analytical expressions is 11% lower at 28.2% compared to the process

455

simulation-based value of 31.7%. Exclusion of the auxiliary electricity loads and steam demand

456

for processes such as desiccant bed regeneration59 in the capture unit could account for some of

457

these differences. Overall, a good level of agreement can be claimed between the analytical

458

expressions developed in this study and corresponding process simulation models for calculating

459

efficiency penalty and associated performance metrics examined in this study.

460

The relative agreement of the analytical expressions presented here with previous simulation

461

results underpins the conclusion that integrated retrofits are most practical both for PC-CCS and

462

NGCC-CCS plants, particularly plants with low pre-capture efficiency. At electricity prices

463

higher than 4.5 and 5.2 US¢/kWh respectively, power-matched gas turbine-based auxiliary CHP

464

plants would provide higher profitability at comparable CO2 reduction and higher plant

465

efficiency for PC-CCS and NGCC-CCS plants. Heat-matching would generally lead to

466

considerably higher levelized COE and CO2 abatement cost, and lower efficiency, short-run

467

profit and overall CO2 reduction relative to integrated retrofits.

468

ACKNOWLEDGEMENTS

469

This material is based upon work supported by the U.S. National Science Foundation under

470

Grant No. CBET 1235688 and the University of Michigan Energy Institute BCN Seed Grant No.

471

U052191.

472

SUPPORTING INFORMATION

473

Derivations of analytical equations for CCS scenarios, including analytical expressions for

474

post-CCS retrofit thermal efficiency, net CO2 reduction, and CO2 intensity of electricity

475

normalized by power output; input data, assumptions, and sources; values of thermal, economic,


25


Page 26 of 38

476

and environmental metrics in Fig. 2; sensitivity analysis results; details of validation of analytical

477

equations against process simulation models.

478

REFERENCES

479

(1)

Peters, G. P.; Andrew, R. M.; Canadell, J. G.; Fuss, S.; Jackson, R. B.; Korsbakken, J. I.;

480

Le Quéré, C.; Nakicenovic, N. Key indicators to track current progress and future

481

ambition of the Paris Agreement. Nat. Clim. Chang. 2017, 7 (2), 118–122; DOI

482

10.1038/nclimate3202.

483

(2)

Pacala, S.; Socolow, R. Stabilization wedges: solving the climate problem for the next 50

484

years

485

10.1126/science.1100103.

486

(3)

with

current

technologies. Science

2004,

305

(5686),

968–972;

DOI

Praetorius, B.; Schumacher, K. Greenhouse gas mitigation in a carbon constrained world:

487

The role of carbon capture and storage. Energy Policy 2009, 37 (12), 5081–5093; DOI

488

10.1016/j.enpol.2009.07.018.

489

(4)

Williams, J. H.; DeBenedictis, A.; Ghanadan, R.; Mahone, A.; Moore, J.; Morrow, W. R.;

490

Price, S.; Torn, M. S. The technology path to deep greenhouse gas emissions cuts by

491

2050: the pivotal role of electricity. Science 2012, 335 (6064), 53–59; DOI

492

10.1126/science.1208365.

493

(5)

Riahi, K.; Grübler, A.; Nakicenovic, N. Scenarios of long-term socio-economic and

494

environmental development under climate stabilization. Technol. Forecast. Soc. Change

495

2007, 74 (7), 887–935; DOI 10.1016/j.techfore.2006.05.026.

496

(6)

Reducing U.S. Greenhouse Gas Emissions : How Much at What Cost?; McKinsey &


26

Page 27 of 38


497 498

Company.; 2007. (7)

499 500

Meyer, L., Eds.; IPCC: Geneva, Switzerland, 2014. (8)

501 502

IPCC. Climate Change 2014: Synthesis Report; Core Writing Team; Pachauri, R. K.;

CCS Retrofit - Analysis of the Globally Installed Coal-Fired Power Plant Fleet; Finkenrath, M.; Smith, J.; Volk, D.; Paris, France, 2012.

(9)

Boot-Handford, M. E.; Abanades, J. C.; Anthony, E. J.; Blunt, M. J.; Brandani, S.; Mac

503

Dowell, N.; Fernández, J. R.; Ferrari, M.-C.; Gross, R.; Hallett, J. P.; et al. Carbon capture

504

and

505

10.1039/C3EE42350F.

506

(10)

storage

update.

Energy

Environ.

Sci.

2014,

7

(1),

130–189;

DOI

Leung, D. Y. C.; Caramanna, G.; Maroto-Valer, M. M. An overview of current status of

507

carbon dioxide capture and storage technologies. Renew. Sustain. Energy Rev. 2014, 39,

508

426–443; DOI 10.1016/j.rser.2014.07.093.

509

(11)

Sreenivasulu, B.; Gayatri, D. V; Sreedhar, I.; Raghavan, K. V. A journey into the process

510

and engineering aspects of carbon capture technologies. Renew. Sustain. Energy Rev.

511

2015, 41, 1324–1350; DOI 10.1016/j.rser.2014.09.029.

512

(12)

Joos, L.; Lejaeghere, K.; Huck, J. M.; Van Speybroeck, V.; Smit, B. Carbon capture

513

turned upside down: high-temperature adsorption & low-temperature desorption

514

(HALD). Energy Environ. Sci. 2015, 8 (8), 2480–2491; DOI 10.1039/C5EE01690H.

515

(13)

Zhai, H.; Ou, Y.; Rubin, E. S. Opportunities for Decarbonizing Existing U.S. Coal-Fired

516

Power Plants via CO 2 Capture, Utilization and Storage. Environ. Sci. Technol. 2015, 49

517

(13), 7571–7579; DOI 10.1021/acs.est.5b01120.


27


518

(14)

Page 28 of 38

Goto, K.; Yogo, K.; Higashii, T. A review of efficiency penalty in a coal-fired power plant

519

with post-combustion CO2 capture. Appl. Energy 2013, 111, 710–720; DOI

520

10.1016/j.apenergy.2013.05.020.

521

(15)

Booras, G. S.; Smelser, S. C. An engineering and economic evaluation of CO2 removal

522

from fossil-fuel-fired power plants. Energy 1991, 16 (11–12), 1295–1305; DOI

523

10.1016/0360-5442(91)90003-5.

524

(16)

Alie, C.; Backham, L.; Croiset, E.; Douglas, P. L. Simulation of CO2 capture using MEA

525

scrubbing: A flowsheet decomposition method. Energy Convers. Manag. 2005, 46 (3),

526

475–487; DOI 10.1016/j.enconman.2004.03.003.

527

(17)

Duan, L.; Zhao, M.; Yang, Y. Integration and optimization study on the coal-fired power

528

plant with CO2 capture using MEA. Energy 2012, 45 (1), 107–116; DOI

529

10.1016/j.energy.2011.12.014.

530

(18)

Mac Dowell, N.; Shah, N. Identification of the cost-optimal degree of CO2 capture: An

531

optimisation study using dynamic process models. Int. J. Greenh. Gas Control 2013, 13,

532

44–58; DOI 10.1016/j.ijggc.2012.11.029.

533

(19)

Kang, C. A.; Brandt, A. R.; Durlofsky, L. J. Optimizing heat integration in a flexible coal–

534

natural gas power station with CO2 capture. Int. J. Greenh. Gas Control 2014, 31, 138–

535

152; DOI 10.1016/j.ijggc.2014.09.019.

536

(20)

Carapellucci, R.; Giordano, L.; Vaccarelli, M. Studying heat integration options for steam-

537

gas power plants retrofitted with CO2 post-combustion capture. Energy 2015, 85, 594–

538

608; DOI 10.1016/j.energy.2015.03.071.


28

Page 29 of 38

539


(21)

Craig, M. T.; Jaramillo, P.; Zhai, H.; Klima, K. The Economic Merits of Flexible Carbon

540

Capture and Sequestration as a Compliance Strategy with the Clean Power Plan. Environ.

541

Sci. Technol. 2017, 51 (3), 1102–1109; DOI 10.1021/acs.est.6b03652.

542

(22)

Chalmers, H.; Gibbins, J. Initial evaluation of the impact of post-combustion capture of

543

carbon dioxide on supercritical pulverised coal power plant part load performance. Fuel

544

2007, 86 (14), 2109–2123; DOI 10.1016/j.fuel.2007.01.028.

545

(23)

Supekar, S. D.; Skerlos, S. J. Reassessing the Efficiency Penalty from Carbon Capture in

546

Coal-Fired Power Plants. Environ. Sci. Technol. 2015, 49 (20), 12576–12584; DOI

547

10.1021/acs.est.5b03052.

548

(24)

House, K. Z.; Harvey, C. F.; Aziz, M. J.; Schrag, D. P. The energy penalty of post-

549

combustion CO2 capture & storage and its implications for retrofitting the U.S. installed

550

base. Energy Environ. Sci. 2009, 2 (2), 193; DOI 10.1039/b811608c.

551

(25)

Lucquiaud, M.; Gibbins, J. Retrofitting CO2 capture ready fossil plants with post-

552

combustion capture. Part 1: requirements for supercritical pulverized coal plants using

553

solvent-based flue gas scrubbing. Proc. Inst. Mech. Eng. Part A J. Power Energy 2009,

554

223 (3), 213–226; DOI 10.1243/09576509JPE661.

555

(26)

Lucquiaud, M.; Patel, P.; Chalmers, H.; Gibbins, J. Retrofitting CO2 capture ready fossil

556

plants with post-combustion capture. Part 2: requirements for natural gas combined cycle

557

plants using solvent-based flue gas scrubbing. Proc. Inst. Mech. Eng. Part A J. Power

558

Energy 2009, 223 (3), 227–238; DOI 10.1243/09576509JPE629.

559

(27)

Bashadi, S. O.; Herzog, H. J. Using auxiliary gas power for CCS energy needs in


29


560

retrofitted

561

10.1016/j.egypro.2011.02.060.

562

(28)

coal

power

plants.

Energy

Procedia

Page 30 of 38

4,

2011,

M.;

564

http://www.ieaghg.org/docs/General_Docs/Reports/2011-02.pdf. (29)

DOI

Retrofitting CO2 Capture to Existing Power Plants; Gibbins, J.; Chalmers, H.; Lucquiaud,

563

565

1828–1834;

McGlashan,

N.;

Li,

J.;

Liang,

X.;

Cheltenham,

UK,

2011;

Korkmaz, Ö.; Oeljeklaus, G.; Görner, K. Analysis of retrofitting coal-fired power plants

566

with carbon dioxide capture. Energy Procedia 2009, 1 (1), 1289–1295; DOI

567

10.1016/j.egypro.2009.01.169.

568

(30)

Gerbelová, H.; Versteeg, P.; Ioakimidis, C. S.; Ferrão, P. The effect of retrofitting

569

Portuguese fossil fuel power plants with CCS. Appl. Energy 2013, 101, 280–287; DOI

570

10.1016/j.apenergy.2012.04.014.

571

(31)

Rio, M. S. del; Lucquiaud, M.; Gibbins, J. Maintaining the Power Output of An Existing

572

Coal Plant with the Addition of CO2 Capture: Retrofits Options With Gas Turbine

573

Combined

574

10.1016/j.egypro.2014.11.275.

575

(32)

Cycle

Plants.

Energy

Procedia

2014,

63,

2530–2541;

DOI

Hanak, D. P.; Biliyok, C.; Yeung, H.; Białecki, R. Heat integration and exergy analysis for

576

a supercritical high-ash coal-fired power plant integrated with a post-combustion carbon

577

capture process. Fuel 2014, 134, 126–139; DOI 10.1016/j.fuel.2014.05.036.

578

(33)

Khalilpour, R.; Abbas, A. HEN optimization for efficient retrofitting of coal-fired power

579

plants with post-combustion carbon capture. Int. J. Greenh. Gas Control 2011, 5 (2), 189–

580

199; DOI 10.1016/j.ijggc.2010.10.006.


30

Page 31 of 38

581


(34)

Alabdulkarem, A.; Hwang, Y.; Radermacher, R. Multi-functional heat pumps integration

582

in power plants for CO2 capture and sequestration. Appl. Energy 2015, 147, 258–268;

583

DOI 10.1016/j.apenergy.2015.03.003.

584

(35)

Carapellucci, R.; Giordano, L.; Vaccarelli, M. Studying heat integration options for steam-

585

gas power plants retrofitted with CO2 post-combustion capture. Energy 2015,

586

85, 594–608; DOI 10.1016/j.energy.2015.03.071.

587

(36)

588 589

Shaw, D. Cansolv CO2 capture: The value of integration. Energy Procedia 2009, 1 (1), 237–246; DOI 10.1016/j.egypro.2009.01.034.

(37)

Cost and Performance Baseline for Fossil Energy Plants Volume 1a: Bituminous Coal

590

(PC) and Natural Gas to Electricity; National Energy Technology Laboratory.; 2015;

591

https://www.netl.doe.gov/File

592

Analysis/Publications/Rev3Vol1aPC_NGCC_final.pdf.

593

(38)

Library/Research/Energy

Sanchez del Rio, M.; Gibbins, J.; Lucquiaud, M. On the retrofitting and repowering of

594

coal power plants with post-combustion carbon capture: An advanced integration option

595

with a gas turbine windbox. Int. J. Greenh. Gas Control 2016, In Press DOI

596

10.1016/j.ijggc.2016.09.015.

597

(39)

Zhao, M.; Minett, A. I.; Harris, A. T. A review of techno-economic models for the

598

retrofitting of conventional pulverised-coal power plants for post-combustion capture

599

(PCC) of CO 2. Energy Environ. Sci. 2013, 6 (1), 25–40; DOI 10.1039/C2EE22890D.

600 601

(40)

Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants; U.S. Energy

Information

Administration.;

Washington,


DC,

2013;

31


602

Page 32 of 38

http://www.eia.gov/forecasts/capitalcost/pdf/updated_capcost.pdf.

603

(41)

Stoft, S. Power System Economics; IEEE Press: Piscataway, NJ, 2002.

604

(42)

Carraretto, C. Power plant operation and management in a deregulated market. Energy

605 606

2006, 31 (6–7), 1000–1016; DOI 10.1016/j.energy.2005.02.009. (43)

Lazzaretto, A.; Carraretto, C. Optimum production plans for thermal power plants in the

607

deregulated

608

10.1016/j.energy.2005.05.007.

609

(44)

610 611

EIA

electricity

market.

Wholesale

Energy

2006,

31

Electricity

(10–11),

Prices

1567–1585;

DOI

2015;

http://www.eia.gov/electricity/wholesale/xls/ice_electric-2015final.xls. (45)

Rubin, E. S.; Short, C.; Booras, G.; Davison, J.; Ekstrom, C.; Matuszewski, M.; McCoy,

612

S. A proposed methodology for CO2 capture and storage cost estimates. Int. J. Greenh.

613

Gas Control 2013, 17, 488–503; DOI 10.1016/j.ijggc.2013.06.004.

614

(46)

Ou, Y.; Zhai, H.; Rubin, E. S. Life cycle water use of coal- and natural-gas-fired power

615

plants with and without carbon capture and storage. Int. J. Greenh. Gas Control 2016, 44,

616

249–261; DOI 10.1016/j.ijggc.2015.11.029.

617

(47)

Harkin, T.; Hoadley, A.; Hooper, B. Optimisation of power stations with carbon capture

618

plants – the trade-off between costs and net power. J. Clean. Prod. 2012, 34, 98–109; DOI

619

10.1016/j.jclepro.2011.12.032.

620

(48)

Harkin, T.; Hoadley, A.; Hooper, B. Using multi-objective optimisation in the design of

621

CO2 capture systems for retrofit to coal power stations. Energy 2012, 41 (1), 228–235;

622

DOI 10.1016/j.energy.2011.06.031.


32

Page 33 of 38

623


(49)

624 625

Manag. 2009, 50 (1), 76–81; DOI 10.1016/j.enconman.2008.08.029. (50)

626 627

Habib, M. A. Thermodynamic analysis of the performance of cogeneration plants. Energy 1992, 17 (5), 485–491; DOI 10.1016/0360-5442(92)90084-D.

(51)

628 629

Kanoglu, M.; Dincer, I. Performance assessment of cogeneration plants. Energy Convers.

Regulatory Impact Analysis for the Clean Power Plan Final Rule; U.S. Environmental Protection Agency.; Washington, DC, 2015.

(52)

The Social Cost of Carbon; United States Government.; Washington, DC, 2013;

630

http://www.whitehouse.gov/sites/default/files/omb/assets/inforeg/technical-update-social-

631

cost-of-carbon-for-regulator-impact-analysis.pdf.

632

(53)

633 634

51 (3), 860–872; DOI 10.1257/jel.51.3.860. (54)

635 636

Pindyck, R. S. Climate Change Policy: What Do the Models Tell Us? J. Econ. Lit. 2013,

Foley, D. K.; Rezai, A.; Taylor, L. The social cost of carbon emissions: Seven propositions. Econ. Lett. 2013, 121 (1), 90–97; DOI 10.1016/j.econlet.2013.07.006.

(55)

Carbon Dioxide Transport and Storage Costs in NETL Studies Quality Guidelines for

637

Energy

638

https://www.netl.doe.gov/File

639

Analysis/Publications/QGESS_CO2T-S_Rev3_20140514.pdf.

640

(56)

System

Studies;

Grant,

T.;

Morgan,

D.;

Gerdes,

K.;

2014;

Library/Research/Energy

L‫׳‬Orange Seigo, S.; Dohle, S.; Siegrist, M. Public perception of carbon capture and

641

storage (CCS): A review. Renew. Sustain. Energy Rev. 2014, 38, 848–863; DOI

642

10.1016/j.rser.2014.07.017.

643

(57)

Scott, V.; Gilfillan, S.; Markusson, N.; Chalmers, H.; Haszeldine, R. S. Last chance for


33


Page 34 of 38

644

carbon capture and storage. Nat. Clim. Chang. 2013, 3 (2), 105–111; DOI

645

10.1038/nclimate1695.

646

(58)

647 648 649

Anderson, K.; Peters, G. The trouble with negative emissions. Science (80-. ). 2016, 354 (6309), 182–183; DOI 10.1126/science.aah4567.

(59)

Supekar, S. D.; Skerlos, S. J. Market-Driven Emissions from Recovery of Carbon Dioxide Gas. Environ. Sci. Technol. 2014, 48 (24), 14615–14623; DOI 10.1021/es503485z.

650


34

Page 35 of 38


Abstract/TOC Art 70x43mm (300 x 300 DPI)



CCS retrofit scenarios for pulverized coal (PC) and natural gas combined cycle (NGCC) power plants considered in this study. 89x60mm (300 x 300 DPI)


Page 36 of 38

Page 37 of 38


Performance of different CCS retrofit scenarios for PC and NGCC power plants. Each bubble represents a unique retrofit scenario described according to the legend, and the size of the bubble represents the CO2 intensity of the electric output of the respective power plant after the retrofit. Efficiency penalty (%-points), derating, CO2 reduction, COE, and abatement costs are all expressed relative to the corresponding power plant without CCS. Drop in annual short-run profit is expressed as a relative change over its pre-CCS profit as a function of wholesale electricity price. 175x133mm (300 x 300 DPI)



Fig. 3 (A) Increase in levelized COE for various CCS retrofit scenarios under a carbon price of 50 US$/tCO2. Faded bubbles indicate values for the scenario without a carbon price that is shown in Fig. 2A. Annual shortrun profit for (B) PC-CCS and (C) NGCC-CCS power with various retrofit scenarios under a carbon price of 50 US$/tCO2. Legend identical to Fig. 2. 174x60mm (300 x 300 DPI)


Page 38 of 38

Sourcing of Steam and Electricity for Carbon Capture Retrofits

Recommend Documents