EUROPEAN COMMISSION DG ENERGY - Projets IFPENprojet.ifpen.fr/Projet/upload/docs/application/pdf/... · and Cesar1 as solvent systems. A multi-heating stripper and the DMX TM process

EUROPEAN COMMISSION DG ENERGY

SEVENTH FRAMEWORK PROGRAMME

THEME ENERGY.2011.5&6.2-1 Optimising the integration of CO2 capture into power plants

Collaborative Project– GA No. 295645

Deliverable N° D13.2

Report on methodology for benchmarking of large scale capture plants

Dissemination level Public

Written By Hanne Kvamsdal (SINTEF), Sören Ehlers (TUHH), Purvil Khakharia (TNO), Michiel Nienoord (TNO), Patrick Briot (IFPEN), Paul Broutin (IFPEN), Philip L. Fosbøl (DTU), and Adam Al-Azki (E.ON)

16.07.2015

Checked by SP1 Leader Hanne Kvamsdal (SINTEF) 16.07.2015

Approved by the coordinator Paul Broutin (IFPEN) 16.07.2015

Main conclusions The methodology for the reference capture processes in OCTAVIUS is updated based on D13.1 and other experiences in the project. It will also serve as a basis for the processes to be benchmarked. Other criteria than energy and cost for the benchmarking are also included.

Issue date 16.07.2015

Document No. Issue date Dissemination Level

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This document contains proprietary information of OCTAVIUS project. All rights reserved.

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Executive summary

In order to show the performance of the demonstrated technologies and aspects in the OCTAVIUS project, benchmarking will also be performed. The work will be based on the European Benchmarking Task Force – EBTF within the CESAR, CAESAR, and DECARBit projects. However, while the main focus was on energy efficiency and costs in those projects, the focus on degradation, emission, operability and flexibility in OCTAVIUS require that additional criteria are used for the comparison and a proper reference capture process is established. The criteria will be both qualitative as well as quantitative type. In this report the final version on methodology for benchmarking is outlined. This methodology is the basis for the actual benchmarking work and in particular the basis for the integrated reference power- and capture plants is emphasized. The reference cases are based on optimization work in Task 13.2. In this task 4 new reference cases are established considering one coal and one natural gas based power plant and both MEA and Cesar1 as solvent systems. A multi-heating stripper and the DMX

TM process will be

benchmarked against the established reference cases. The computational assumptions and modelling parameters for the simulation to be done as a basis for determining the energy requirement and the associated costs of CO2 capture are given here in the present report with mainly the reference cases in mind. More specifically, this implies that the power plant cases are described together with the conventional absorber/stripper process for the reference capture plants, specifications on major equipment as e.g. heat exchanger outlet temperature, CO2 compression description and specifications, tools to be used for the OCTAVIUS benchmarking and finally how to determine the energy requirement and total plant efficiency for the integrated plants. Though the guideline for the energy and cost calculations are given specifically for the reference capture plants it is emphasized that it shall also be used at least as a basis for the other processes to be evaluated and benchmarked in OCTAVIUS in order to secure a fair comparison as possible. All the assumptions and modelling parameters have been evaluated in a thorough manner with input from additional partners other than the authors. The design parameters for each of the process units (absorber, stripper, blower, heat exchangers, pumps etc.) are specified for calculating the capital costs of the units. Furthermore, the other costing parameters are extensively described and guidelines for the use of more qualitative criteria for benchmarking to be used in OCTAVIUS are given. This is related to degradation and emission, operational flexibility and process complexity.


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Content

1 INTRODUCTION .................................................................................................................... 5

1.1 THE OCTAVIUS PROJECT AND OBJECTIVE OF TASK 13.1 ..................................................................... 5 1.2 REPORT LAYOUT .................................................................................................................................. 6

2 THE BASIS FOR THE MASS- AND ENERGY BALANCE CALCULATIONS ......................... 7

2.1 INTRODUCTION ..................................................................................................................................... 7 2.2 DESCRIPTION OF THE BASE CASES ........................................................................................................ 7

2.2.1 The bituminous coal case .......................................................................................................... 7 2.2.2 The NGCC case......................................................................................................................... 7

2.3 GENERAL TECHNICAL FRAMEWORK ....................................................................................................... 7 2.4 COMPUTATIONAL ASSUMPTIONS FOR THE CAPTURE PLANT ..................................................................... 9

2.4.1 Overall specifications ................................................................................................................. 9 2.4.2 Flue gas conditions .................................................................................................................. 10 2.4.3 Basic flowsheet description ...................................................................................................... 11 2.4.4 Specifications of the unit operations ........................................................................................ 12 2.4.5 CO2 compression and specifications ....................................................................................... 14

2.5 MODELS AND TOOLS TO BE USED IN OCTAVIUS ................................................................................. 17 2.6 ENERGY EFFICIENCY CALCULATIONS ................................................................................................... 18

2.6.1 Energy requirement in the capture plant .................................................................................. 18 2.6.2 Energy output from the power plant ......................................................................................... 19 2.6.3 Definition of energy efficiency for the total plant ...................................................................... 19

3 DESIGN OF LARGE SCALE CAPTURE PLANTS ............................................................... 20

3.1 INTRODUCTION ................................................................................................................................... 20 3.2 ABSORBER INCLUDING WATER-WASH .................................................................................................. 20 3.3 STRIPPER INCLUDING CONDENSER AND WATER-WASH ......................................................................... 23 3.4 REBOILER .......................................................................................................................................... 23 3.5 SO2 REMOVAL AND PRE-COOLER ........................................................................................................ 23 3.6 BLOWER ............................................................................................................................................ 24 3.7 CROSS HX ........................................................................................................................................ 24 3.8 PUMPS .............................................................................................................................................. 24 3.9 LVC COMPRESSOR AND FLASH TANK .................................................................................................. 24 3.10 BUFFER TANK, AMINE STORAGE TANKS, AND OTHER TANKS .................................................................. 24 3.11 CO2 COMPRESSOR ............................................................................................................................ 25 3.12 OTHER HX ........................................................................................................................................ 25

3.12.1 Lean cooler .............................................................................................................................. 25 3.12.2 Water-wash cooler ................................................................................................................... 25 3.12.3 CO2 compression intercoolers and after-cooler ....................................................................... 25

3.13 WATER DEHYDRATION ........................................................................................................................ 25 3.14 OVERALL HEAT TRANSFER COEFFICIENT FOR HEAT EXCHANGER DESIGN ............................................... 25 3.15 RECLAIMING ...................................................................................................................................... 26 3.16 ADDITIONAL COOLING WATER PLANT ................................................................................................... 26 3.17 SPARE UNITS ..................................................................................................................................... 26


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4 BASIS FOR COST-CALCULATIONS ................................................................................... 27

4.1 INTRODUCTION ................................................................................................................................... 27 4.2 FINANCIAL PARAMETER ASSUMPTIONS ................................................................................................ 27 4.3 POWER PLANT COSTS ........................................................................................................................ 29 4.4 COST OF ELECTRICITY WITHOUT CO2 CAPTURE .................................................................................. 29 4.5 CO2 CAPTURE PLANT COSTS .............................................................................................................. 29

4.5.1 Capital cost/CAPEX of the CO2 capture plant ......................................................................... 29 4.5.2 Operational cost/OPEX of the CO2 capture plant .................................................................... 31

4.6 COST OF ELECTRICITY WITH CO2 CAPTURE ......................................................................................... 33 4.7 COST OF CO2 AVOIDED ...................................................................................................................... 33

5 GENERAL OPERABILITY .................................................................................................... 34

5.1 EMISSION TO AIR AND WATER RELATED TO SOLVENT MANAGEMENT ...................................................... 34 5.1.1 Emission to Air ......................................................................................................................... 34 5.1.2 Emission to water ..................................................................................................................... 35 5.1.3 Use of the emission criterion for benchmarking in OCTAVIUS ............................................... 35

5.2 FLEXIBILITY ........................................................................................................................................ 35 5.2.1 General about flexibility ............................................................................................................ 35 5.2.2 How to use the flexibility criterion for the benchmarking in OCTAVIUS................................... 36

5.3 DYNAMICS AND CONTROL ................................................................................................................... 37


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1 Introduction

1.1 The OCTAVIUS project and objective of Task 13.1

OCTAVIUS aims to demonstrate integrated concepts for zero emission power plants covering all components needed for power generation as well as CO2 capture and compression. Operability and flexibility of first generation post combustion processes are demonstrated by TNO, EnBW and ENEL pilot plants in order to prepare full scale demo projects. OCTAVIUS will establish detailed guidelines with relevant data on emissions, HSE, and other operability, flexibility and cost aspects. Related to this, there will also be an activity on review of proposed process concepts for 1

st generation solvent systems published in open literature and patents (Task 25.3).

Additionally, OCTAVIUS includes a comprehensive study of the second generation process DMX

TM. Applications to coal power stations but also NGCC are considered.

In order to show the performance of the demonstrated technologies and aspects, benchmarking will also be performed in the OCTAVIUS project (within Task 13.4). The work will be based on the European Benchmarking Task Force – EBTF within the CESAR, CAESAR, and DECARBit projects. However, while the main focus was on energy efficiency and costs in those projects, the focus on degradation, emission, operability and flexibility in OCTAVIUS require that additional criteria are used for the comparison. Four different reference cases have been established for the benchmarking. These cases are described in D13.3. Based on a screening of the reviewed process concepts in Task 25.3, six of them are modelled and further analysed. Then the best one (multi-heating stripper) is further optimized prior to final benchmarking in Task 13.4. Also the DMX

TM process will be benchmarked against the established

reference cases. In OCTAVIUS there are different partners who have and will develop and use models for process simulations for determining energy requirement as well as cost estimation models to be used as part of the benchmarking activities. Since these partners also will have different preferences when it comes to the tool to be used for the modelling as identified in deliverable D11.1, an internal "benchmarking" of these models have been performed. The results of the comparison of process models to be used for energy requirement estimation were presented at the GHGT-12 conference in Austin, Texas, in October 2014. The corresponding published paper is attached in Appendix A of the present report. The main conclusion is that there is a general good resemblance between modelling results and thus we are confident that by using different models we are still able to perform the benchmarking on a fair basis. Four new reference capture processes for the benchmarking is developed in Task 13.2 of OCTAVIUS based on the results from the Cesar project. Both MEA and CESAR 1 (AMP+piperazine) are considered as solvent systems and one coal- and one NG based power plant are used as basis for each of these solvent systems. During the work with this optimization it was discovered that also cost estimations performed by three of the partners were quite different so that the costs parameters described in D13.1 have been thoroughly studied and a more comprehensive list and assumptions made are given in this present report.


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1.2 Report layout

The present report is the final report on benchmarking methodology within Task 13.1. It starts in Chapter 2 with the basis for the mass- and energy balance calculations used for the reference capture process (Task 13.2). It is emphasized, that not all the given data and specifications can be used for the cases to be part of the benchmarking (Task 13.4), but they are meant to be guidelines. The same concern the guidelines for large-scale design important for the cost-calculations, which are given in Chapter 3. In Chapter 4 the basis for the updated cost-analysis is given while other criteria for comparison are dealt with in Chapter 5.


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2 The basis for the mass- and energy balance calculations

2.1 Introduction

As mentioned in Chapter 1, most of the benchmarking work in OCTAVIUS will be based on the previous EBTF work (as e.g. presented in D2.4.3 European Best Practice Guidelines for Assessment of CO2 Capture Technologies of the Cesar project). The base cases in OCTAVIUS are limited to the 800 MWe Bituminous Coal and the 430 MWe Natural Gas Combined Cycle (NGCC) cases, and we also have considered only new build plant (i.e. no retrofit).

2.2 Description of the base cases

Both power plant base cases are re-simulated in OCTAVIUS (see D13.3), a summary of the results are given here.

2.2.1 The bituminous coal case

The 800 MWe Bituminous Coal case is based on an advanced super critical boiler and a steam turbine. This plant has been simulated in Ebsilon®Professional 10.03 and the gross power output is 804.8 MWe. Subtracting the auxiliary power resulted in net power plant output of 743.5 MWe. Thus the determined net cycle efficiency was 45.4% while the specific CO2 emission was 761.5 g/kWhnet without post-combustion CO2 capture.

2.2.2 The NGCC case

The 430 MWe NGCC case is based on a gas turbine and a bottoming cycle consisting of one steam turbine and a heat recovery steam generator (HRSG). The HRSG is a three pressure level type with reheat and feeds the steam turbine. This plant has also been simulated in Ebsilon®Professional 10.03 and the gross power output from the gas turbine is 281.7 MWe and 148.6 MWe from the steam turbine. The determined net cycle efficiency was 57.8% while the specific CO2 emission was 364.2 g/kWhnet without post-combustion CO2 capture.

2.3 General technical framework

In this section some basic definitions are made. In all reports and presentations, SI unit system is to be used. For ambient conditions, the ISO standard conditions were used in the EBTF work and are also applicable in OCTAVIUS:

Air pressure: 0.101325 MPa

Air temperature: 15°C

Relative humidity: 60%

Gas constant: 288.16 J/kgK

Molecular mass: 28.854 kg/kmol

Cooling water temperature: 18.2°C


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The air composition is given in Table 2-1.

Table 2-1: Air composition

Component Volume fraction dry in % Volume fraction at 60% relative humidity in %

N2 78.09 77.30

O2 20.95 20.74

H2O 1.01

Ar 0.932 0.923

CO2 0.03 0.03

For the 800 MWe base case Bituminous Douglas Premium coal is used. The calorific values and CO2 emissions are given below:

HHV: 26.230 MJ/kg

LHV: 25.170 MJ/kg

Specific CO2 emission: 349 g/kWh LHV The composition of the coal is given in Table 2-2.

Table 2-2: Bituminous coal composition

Proximate analysis Ultimate analysis

Component Mass fraction in % Component Mass fraction in %

Fixed Carbon 54.90 Carbon 66.52

Volatiles 22.90 Ash 14.15

Ash 14.15 Moisture 8.00

Moisture 8.00 Oxygen 5.46

Total sulphur 0.52 Hydrogen 3.78

Nitrogen 1.56

Total sulphur 0.52

Chlorine 0.009

For the 430 MWe NGCC case natural gas is used. It is supplied at 10°C and 7 MPa. The calorific values and CO2 emissions are given below:

HHV: 51.473 MJ/kg

LHV: 46.502 MJ/kg

Specific CO2 emission: 208 g/kWh LHV


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The composition of the natural gas is given in Table 2-3.

Table 2-3: Natural gas composition

Component Volume fraction in %

CH4 - Methane 89.00

C2H6 - Ethane 7.00

C3H8 - Propane 1.00

C4-i – I-Butane 0.05

C4-n – N-Butane 0.05

C5-i – I-Pentane 0.005

C5-n – N-Pentane 0.004

CO2 2.00

N2 0.89

S < 5 ppm

2.4 Computational assumptions for the capture plant

2.4.1 Overall specifications

There are many degrees of freedom when designing a large-scale capture plant. Therefore certain pre-defined specifications and assumptions are required in order to reduce the number of feasibilities. Specifications for some of the main parameters, which influence on the capital costs (CAPEX) and operating costs (OPEX) are listed in Table 2.4.


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Table 2-4: Some pre-fixed specifications for the OCTAVIUS large-scale CO2 capture plants, which

influence capital cost (CAPEX) and operating cost (OPEX)

Parameter Fixed values Comments

Flue gas CO2 content See Section 2.4.2 Two different values 1) coal case and 2) NG case

Flue gas flowrate See Section 2.4.2 Two different values 1) coal case and 2) NG case

Flue gas temperature after direct contact cooler (DCC)

40C Reference case spec (Chapter 6), optimization parameter

H2O in flue gas See Section 2.4.2 Two different values 1) coal case and 2) NG case

Capture rate 90 % of inlet content Shall be obtained in all cases

Solvent 30 wt% MEA + CESAR1 (AMP+Piperazine)

Packing material (included water-wash sections)

Sulzer Mellapak 2X DMX will use alternative packing

Water content in CO2 stream for transport

50 ppmv See Section 2.4.5

Amine/Ammonia content in flue gas leaving the absorber*

<4.3 ppmv/6.9ppmv See Chapter 5 for further details

* Based on the limit in the ROAD Feed report (for MEA this limit is 11 mg/Nm3 or approx.4.3 ppmv and for

NH3 this number is 5 mg/Nm3 or appr. 6.9 ppmv) when entire FG stream is treated according to GCCSI

reference ROAD Feed report (pg. 29)1).

2.4.2 Flue gas conditions

The flue gas conditions for both the coal and the NG cases are summarized in Table 2-5. They result from the power plant simulations in Task 13.2 and are reported in D13.3 as well.

1 http://www.globalccsinstitute.com/publications/road-ccs-project-non-confidential-feed-study-report


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Table 2-5: The flue gas conditions determined for the Advance Supercritical pulverized bituminous

Coal (ASC) case and the Natural Gas Combined Cycle (NGCC) case (same as reported in D13.3)

Parameter Unit ASC NGCC

Flow rate kg/s 786.5 671.3

Temperature C 50.3 85.76

Pressure kPa 101.6 101.6

Composition:

O2 mol% 3.65 11.89

CO2 mol% 13.25 4.11

H2O mol% 12.11 8.89

Inert (Ar+N2)* mol% 70.99 75.11

*SOx and NOx are omitted here

2.4.3 Basic flowsheet description

This section describes the basic flow sheet for the capture plant associated with the base cases: 800 MW Bituminous Coal and the 430 MW NGCC power plants. The capture plant flow-sheet for both the cases is as shown in Figure 2-1.

Rich solvent

pump

Lean solvent

pump

Cooler

Absorber

Lean-rich heat

exchanger

Condenser

Condenser

pump

Reboiler

CO2 to

compression

Stripper

To stack

Wash

section

Cooler

Condensate

drum

Make-up

Blow-down

DCC

Flue gas Blower

DCC Pump

Wash liquid

Pump

Figure 2-1: Standard flowsheet for Post Combustion capture


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It is important to note that the flowsheet is based on a standard representation of a post-combustion carbon capture plant and not necessarily accurate in its details of equipment. The CO2 capture process is based on a conventional absorber-stripper system. The flue gas is first cooled to a specified temperature in a direct contact cooler (DCC). Then the flue gas passes through a blower to overcome the pressure drop in the DCC and the absorber column. In the absorber section, the flue gas comes in contact with the solvent, which chemically binds the CO2. The treated flue gas, before being emitted to the atmosphere, passes through a water wash system to balance the water in the system and to avoid solvent carryover (here shown as one single washing-section). The solvent, which is “rich” in CO2, is pumped to top of the stripper via a cross heat exchanger. The solvent is regenerated in the stripper at elevated pressure and temperature. The stripper is heated by means of a steam reboiler to maintain regeneration conditions. This low pressure (LP) steam is withdrawn from the power plant, which in turn reduces the thermal energy efficiency of the power plant. The heat in the stripper is necessary to heat the solvent, generate stripping vapour and desorbing the chemically bound CO2 from the solvent. The stripping steam associated with the CO2 product leaving the stripper is recovered by means of a condenser and fed back to the stripper. The CO2 product thus leaving the condenser is relatively pure (>99%), with water vapour being the only other major component. There is also a water-wash section in the top of the stripper to avoid slipping of solvent to the CO2 stream. The lean solvent with residual amounts of CO2 from the stripper is pumped back to the absorber via the cross heat exchanger and a cooler to lower the temperature of the lean solvent stream entering the absorber.

2.4.4 Specifications of the unit operations

The specifications for the process unit operations given here are those which are necessary for simulation of the capture- and the CO2 compression processes in both CO2SIM and Aspen Plus and for calculation of total energy requirement. In Chapter 3 further specifications are given for design and cost-calculation purposes. Some preliminary specifications for all process unit operations are summarized in the following tables. It should be noted that the output pressure of the blower depends on the pressure drop in the absorber column, which again depends on the height of packing. The steam needed for the amine regeneration would be withdrawn for the power plant steam cycle. The location of the withdrawal is depending on the steam specification and on the minimization of the power loss. This is further described in deliverable D13.3. The required specification of the steam is presented in Table 2-6. The water used for the DCC unit as well as the absorber and stripper water-wash section shall be demineralised process water. This water is cooled by cooling water from the cooling-towers of the power-plant in separate coolers as shown in Figure 2-1 for the DCC and absorber units. The specification for the cooled process water is given in Table 2-7, while the specification for the inlet and outlet temperature for the cooling water is given in Table 2-6.


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Table 2-6: Specifications for utilities

Utility Temperature inlet Temperature outlet

Water Cooling* 18.2 °C 29.2 °C

Steam** TProcess + 10°C (at dew point)

*** TProcess + 10°C (at boiling point)

* It is assumed that the cooling water is provided from cooling towers (adopted from EBTF)

**Assuming Tmin = 10 °C for the reboiler

*** p_steam = (p_sat(T_process + 10 K)+p_loss)

Table 2-7: Specifications for all heat-exchangers (process side)*

General coolers/condensers Lean cooler

Parameter Value/spec Parameter Value/spec

Temperature outlet

process side (C)

30 Temperature outlet

(C)

40

Pressure drop (gas) 3% of inlet stream pressure

Pre-cooler Cross-heat exchanger


Temperature outlet

(C)

40 Temperature

approach (C) (i.e. cold in – hot out)

5

Water-content outlet stream

Saturated

Pressure drop **

Reboiler CO2 compressor Intercoolers

Operating

temperature (C)

120 Parameter Value/spec

Temperature outlet

(C)

40

* A sensitivity analysis will be carried out in the optimization work (D13.3) for some of the parameters listed here as there is a clear trade-off between the effect on CAPEX and OPEX. **The pre-cooler pressure drop needs to be calculated meaning 6 mbar for the column head + 3 mbar for the demister + 3 mbar for the liquid distributor + 50 mbar for the gas distributor and 1.5 mbar per packing height meter.

For specification of type of heat-exchanger see Sections 3.7 and 3.12.


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Table 2-8: Specifications for absorber/stripper***

Absorber + Water-wash Stripper


Operating velocity 70% flooding Operating velocity 70%

Maximum diameter (m)

18* Temperature outlet

(C)

30

Pressure drop (mbar/m packing)

** Pressure drop (mbar/m packing)

**

Capture level (% of incoming CO2 content)

90 Water-wash temperature inlet

resirc. stream (C)***

30

Water-wash temperature inlet

resirc. stream (C)**

30

* Adapted from Reddy et al.2

** Same as for the pre-cooler (so 6 mbar for the column head + 3 mbar per demister + 3 mbar per liquid collector + 50 mbar for the gas distributor + 1.5 mbar per packing height meter ***Temperatures for water wash sections in absorber and stripper are defined by cooling specifications (Table 2-6 and 2-7)

Table 2-9: Specifications for centrifugal pumps, LVC compressor, and blower

Pumps Blower


Hydraulic efficiency (%)

80* Isentropic efficiency

(%) 75

Driver efficiency (%) 95 Driver efficiency (%) 95

LVC Compressor

Isentropic efficiency LVC (%)

80**

Driver efficiency (%) 95 *Based on performance curves for centrifugal pumps, hydraulic efficiency reach 80 % when the volumetric flow rate Qv > 1000 m

3/h. For this project efficiencies are assumed to be the same at flow rates beneath

1000 m3/h.

**Assuming a turbo compressor for LVC.

It is assumed that all pumps are located at ground level.

2.4.5 CO2 compression and specifications

Specifications The specification for the CO2 stream after compression is:

Pressure: 110 bar

Temperature: ≤30°C

2 Reddy, S., Johnson, D., and Gilmartin, J., (2008), Fluor’s Econamine FG PlusSM Technology For CO2 Capture

at Coal-fired Power Plants, presented at the Power Plant Air Pollutant Control Mega Symposium, Baltimore, August 25-28


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The water content should be according to Table 2.4, i.e. ≤ 50 ppmv. This value means additional drying as the final water content after compression (with inter-cooling to 40°C) is around 1400-1500 ppm.

Compression The electric energy duty of the CO2 compression has a large influence on the efficiency penalty of the integrated overall process. Nevertheless, the best compressor configuration can only be determined by taking into account both waste heat integration analyses and economics. The potential of waste heat integration depends on the number of stages, number of intercoolers, positions of intercoolers and heat sinks available in the power plant process. Hence, the compression train described here for benchmarking is based on a state-of-the-art turbo compressor without taking into account optimisation measures. The gas in the CO2 inlet stream (Figure 2-2) is a wet CO2 stream. Dehydration is required due to the risk of pipeline corrosion and hydrates formation during transportation of the pressurized CO2 stream. However, removing water by simple cooling in order to reach the design specification is practically unfeasible. For example with inter-cooling to 30°C final water content after compression is around 1400-1500 ppm. Further drying can be achieved by adding an absorption (glycols) or adsorption (molecular sieves) step after the compression train. Inclusion of adsorption in the CO2 compression process is shown in Figure 2-2 as an example. For CO2 compression an integrally geared (radial) compressor with six stages, three inter-coolers and one after-cooler is considered. This is the same configuration as mentioned in EBTF except that the Compressor 1, 2, and 3 in the EBTF report consist actually of two stages each. For the simulation, a calculation method for real gas behaviour should be applied to take into consideration the non-ideal behaviour of the CO2 during compression and cooling. Calculation with ideal gas behaviour leads to a lack in accuracy of approximately 10% related to the energy requirements. Table 2-10 shows the boundary conditions for the CO2 compressor model. The pressure drop for the application of adsorption beds in the drying unit is assumed to be 0.5 bar. Furthermore, the pressure ratio of each stage is decreased by 2 % per stage caused by the rotor dynamics of integrally geared compressors. The intercooling temperature is 40 °C3 . Due to the smaller impeller sizes the polytropic efficiency decreases with increased stage number.

MCompressor

stage with

adjustable inlet

guide vanes

drain valve

Adsorptive

drying unit aftercooler

transmission

engine drive

Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6

ic 3

ic 1 ic 2

CO2 inlet

Figure 2-2: Flowsheet of integrally geared CO2 compressor

3 Recommended by MAN and Siemens


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Table 2-10: Boundary conditions for the compressor model

Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 Engine drive

Pol. (/el.)

efficiency 85% 84% 83% 82% 81% 80% 97%

Pressure loss in

inter-

coolers/after-

cooler

- 40 mbar - 80 mbar 100 mbar 120 mbar -

By using the software tool Ebsilon®Professional the compression part was simulated and reported in Liebenthal et al.(2011)4. For an inlet pressure of 2.0 bar the specific power duty of the engine drive was estimated to be 329.9 kJ/kg CO2. The specific cooling duty was 468.5 kJ/kg CO2. The results agree with data from other literature and information from manufacturers. The influence of different compressor configurations on the energy requirements are summarized in Liebenthal and Kather5. Furthermore the same compressor configuration serves as reference case in the 7

th framework EU project iCap – Innovative CO2 capture.

Drying to 50 ppmv There are mainly two different types of technologies for meeting the target of less than 50ppm H2O in the final CO2 stream.

1) Separation of components by adsorption (shown in Figure 2-2) is based on differences in the components affinity to accumulate (bound physically or chemically) on the surface of an adsorbent. By using zeolite molecular sieves as adsorbent, the water content may be as low as 0.1 ppm. However, the regeneration by either Temperature Swing (TSA) or Pressure Swing (PSA) will imply energy requirement. Another drawback is the relatively high pressure drop in such systems.

2) An alternative process is based on absorption by means of glycols like Tri-ethylene-glycol (TEG) or glycerol. Figure 2-3 shows a typical glycol dehydration plant configuration. Glycols have a relative high affinity for CO2 at elevated pressure; therefore, the liquid rate to the contactor should be kept at a minimum to prevent excessive absorption of CO2. Glycol circulation rate ranges from 17 to 42 l/kg H2O (GPSA)6.

4 U. Liebenthal, S. Linnenberg, J. Oexmann, and A. Kather. Derivation of correlations to evaluate the impact of

retrofitted post-combustion co2 capture processes on steam power plant performance. International Journal of Greenhouse Gas Control, 5:1232–1239, 2011

5 U. Liebenthal and A. Kather. Design and off-design behaviour of a co2 compressor for a post-combustion co2 capture process. In the proceedings of the 5th International Conference on Clean Coal Technologies, Saragozza, Spain, May 2011

6 GPSA, 1980: GPSA (Gas Processors Suppliers Assoc.), SI Engineering Data Book. ninth Edition, Gas Processors Suppliers

Association, Tulsa, Oklahoma, USA (1980)


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Figure 2-3: Typical glycol dehydration plant configuration

The regenerator reboiler temperature should not exceed 204°C due to thermal degradation of TEG. Maximum TEG fraction is around 99.1 wt% with 204°C. This limits the stripping capabilities and the degree of dehydration, since it is the water removal in the regenerator that decides the net removal of water. However if a bleed stream, from the dry gas leaving the contactor is used as stripping gas in the regenerator section, a higher degree of dehydration can be achieved. Stripping gas is supplied to a column below the reboiler section of the primary regenerator, and the exiting wet stripping gas from this column is fed to the reboiler of the primary regenerator. This column is often referred as a “Stahl column”. The bleed stream is often very small compared to the main stream (<1%) and it is often used in gas dehydration with the stringent water requirements. Compared to the adsorption alternative, this technology has lower pressure drop.

As indicated for both methods there are clear advantages and disadvantages. However, in Octavius it has been decided to use the latter method.

2.5 Models and tools to be used in OCTAVIUS

Most of the simulation tools to be used in the OCTAVIUS project were identified in Deliverable D11.1. For the benchmarking, steady state simulators are needed for the energy efficiency calculation described in Section 2.6. As stated in Deliverable D11.1 process models is developed in both the in-house tool CO2SIM provided by SINTEF and NTNU and the commercial software tool Aspen Plus (with the RateSep column model or in-house modules) for simulation of the capture process. For the power plant simulations, the commercial software tool EBSILON®Professional 9.00 has been used. Later, it was decided to use the commercial software Pro II, with proprietary thermodynamic and reactions models included in an User Added Subroutine (UAS), for simulation of the CO2 capture process with DMX

TM and the corresponding power plant process.


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2.6 Energy efficiency calculations

2.6.1 Energy requirement in the capture plant

Reboiler The energy requirement shall be calculated in terms of electric power (MWe). This means that the steam requirement in the reboiler must be transformed to equivalent work (here, loss in gross output of the power plant). As part of the optimization of the reference capture plants in task 13.2 a simplified approach was used (see below) while for the final benchmarking the complete simulation of both the NGCC and the coal power-plant is done in EBSILON (see D 13.3). For the coal base case the simplified approach (for determining the optimal reference capture plant) is based on work by Liebenthal and Kather (2011). By simulation using the commercial software tool EBSILON®Professional 9.00 they have established a general correlation describing the power loss in the upstream power-plant when extracting steam for the reboiler. This correlation is a function of steam quantity and quality by means of the reboiler temperature. For the NGCC base case the simplified approach is based on work reported by Bolland and Undrum (2002), who used simulations of a NGCC cycle to determine the corresponding loss of electric power when withdrawing steam (different steam pressure levels were considered) for the reboiler. In the paper there is a graph showing the ratio between incremental power reduction to incremental heat output as function of saturation temperature and pressure. For example with a steam pressure of 4 bar this ratio is approximately 0.23. Then by assuming a mechanical efficiency of 95% the loss in electric power can be determined.

Blower and LVC compressor The required electric power is determined using the process unit efficiency numbers as given in Table 2-9.

CO2 compressors The required electric power is determined using the process unit efficiency numbers given in Table 2-10.

Liquid recirculation pumps For the real necessary work of the pumps, the total pressure head must be determined. By assuming all pumps to be located on the ground, the static pressure head for the rich and lean pumps is determined roughly based on the height to the top of the upper absorber/stripper sections. For the water-recirculation pump of the DCC and the water-wash pumps for the absorber and stripper columns only estimates are given to account for the pressure drop.

Table 2-11: Assumed pressure head for the major liquid pumps in the capture plant*

Rich solvent pump

Lean solvent pump

DCC water circulation pump

Absorber water-wash pump

Stripper water-wash pump

Pressure head (m)

K*height to top of stripper

section*

K*height to top of

absorber section*

4 4 3

* K is a safety margin=1.5


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Electric power consumption is determined using the efficiency numbers given in Table 2-9

Cooling water pumps The cooling water pumps power consumption shall be calculated considering a total pressure drop of 1 bar (including pipes from cooling area to the amine plant, exchangers pressure drop, control valves etc.). Electric power consumption shall be determined using the efficiency numbers given in Table 2-9.

2.6.2 Energy output from the power plant

Both the Bituminous Coal case and the NGCC case have been simulated in OCTAVIUS and net power output is determined. More details are reported in deliverable D13.3, but a summary is given in the following: A gross electrical power output of 804.8 MWe was determined for the 800 MWe Bituminous Coal case. The sum of the auxiliary consumers adds up to 61.3 MWe, leading to a net power output of 743.5 MWe. The auxiliary consumers are listed in Table 2-12.

Table 2-12: Auxiliary power consumers determined for the 800 MWe base case

Consumer Electrical power consumption in MWe

Feed water pump 32.32

Condenser extraction pump 0.74

Auxiliaries for heat rejection 4.74

Forced fans 2.06

Induced fan 7.77

Flue gas cleaning 7.58

Additional consumers 7.11

The 430 MWe NGCC case has a gross electrical power output of 430.3 MWe. The gas turbine contributes two thirds of the power output, while the steam turbine delivers one third.

2.6.3 Definition of energy efficiency for the total plant

The net efficiency of the power plant shall be calculated using Equation 2-1.

netnet

f

P

m LHV (2-1)

where netP is the net electric power supplied to the grid, fm is the fuel mass flow, and LHV is the

lower heating value. The net electric power is computed by subtracting the power used by the different consumers from the power provided by the generator.


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3 Design of large scale capture plants

3.1 Introduction

There are many different units in a capture plant. Here, the design parameters and information for the main units, which are considered most important for the for the capital cost calculation, are given. The list of units considered is shown in Table 3-1. The number of required units is first of all given from the capacity of the absorber and thus the number of major process trains for the capture plant. The number of heat exchangers (HX) units per process train is dependent on the maximum allowed area of the unit. The number of strippers per process train is dependent on the maximum number of reboiler units per stripper unit. The number of pumps and compressors is dependent on the maximum power required per unit. The number of tanks in the process follows the number of process trains while it is assumed that only one unit is enough for the various storage tanks. Even though it might be enough with only one joint compressor train, it is for reasons of flexibility considered to use one compressor train per stripper unit. Spare units are considered only for pumps and this mean one spare unit for each type of pump (e.g. rich solvent pump, lean solvent pump, etc.). Further details about major design considerations and number of units are given in the subsequent sections.

Table 3-1: Major equipment considered for cost calculations

Type of equipment Equipment name

Columns flue gas direct contact cooler (DCC), absorber, stripper

Compressors blower, LVC compressor, CO2 compressor (including inter-cooler, knockout drum and water drying unit)

Heat exchangers cross HX (lean-rich heat exchanger), lean cooler, reboiler, condenser cooler, DCC process water cooler, absorber water-wash cooler, stripper water-wash cooler

Flash tanks condenser, LVC flash

Pumps rich solvent pump, lean solvent pump, DCC water circulation pump, absorber water-wash pump, stripper water-wash pump, stripper condenser pump, various cooling-water pumps

Tanks condensate reflux drum, amine storage tank, process water make-up tank, solvent buffer tank

As a basis it will be considered Stainless Steel (SS) 316 as material in all equipment and piping at least for the reference plants. However, there might be considered other type of materials as well in the optimization and benchmarking work.

3.2 Absorber including water-wash

The amount of gas to be treated in large scale absorbers is huge and may imply that actually more than one absorber column is needed. This further may imply separate trains as already mentioned in Section 3-1.


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The number of column(s) depends on several factors like type of column, packing material, flooding velocity, and practical construction limitations. In OCTAVIUS only cylinder type of columns is considered because none of the partners involved with cost estimation in OCTAVIUS can determine adequate cost estimates for concrete rectangular columns (though used and considered in many larger applications previously as e.g. Boundary Dam, Test Center Mongstad and Kingsnorth). The column diameter shall be determined by a specification of operating below 70% of the flooding velocity (as given in Table 2-8). The practical maximum diameter of a column to be used in OCTAVIUS is 18 m according to Table 2-8. Thus the number of trains needed must be determined based on this maximum diameter and the amount of gas to be treated. The actual height of the column depends mainly of the required packing height for 90 % removal and the height of the washing section, but also other internals as the liquid sump, the inlet gas duct, the gas- and liquid distribution plates and any redistribution plates will contribute to the overall height. The number of necessary packed sections depends further on the type of packing and recommendation from the packing supplier. In OCTAVIUS it is decided to use a maximum bed height of 7m (Kohl and Nielsen 1997)7. According to Sulzer it is good practise to have a liquid collector at the bottom of each packed section. The required means for amine emission mitigation will depend on several factors and the specific emission permit. For the reference cases a one-stage water wash solution with fresh water make-up and a demister unit is adopted in OCTAVIUS. The actual height of the absorber will be determined based on the sketch given in Figure 3-1and supported by information given in Kvamsdal et al. 20108. Thus the typical height for all internals except for the packed sections, which are determined by simulation and optimization, is as shown in Table 3-2.

Table 3-2: Pre-defined dimensions absorber column. The numbers are based on Figure 3-1

and Kvamsdal et al. 20107 with some modifications.

Height mist collector + gas outlet section m 2.5

Height between absorber and water-wash sections and between packed sections m 2.5

Height required for flue gas inlet and distributor (between sump and first packed section) m 2+0.5D

Sump m

Must be determined assuming 6 minutes of

residence time*

*Based on requirement for the rich solvent pump

7 A. L. Kohl, R.B. Nielsen, “Gas Purification”, 5th Edition, p 31, Gulf Publishing Company 1997

8 Kvamsdal, H.M., Hetland, J., Haugen, G., Svendsen, H.F., Major, F., Kårstad, V., and Tjellander, G. (2010),

Maintaining a neutral water balance in a 450 MWe NGCC-CCS power systems with post-combustion carbon

dioxide capture aimed at offshore operation, International Journal of Greenhouse Gas Control, 4(4), pp. 613-622


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Figure 3-1: Sketch of absorber column with indications of dimensions

Information about the water-wash pumps and the water-wash cooler is given in Sections 3.8 and 3.12, respectively.


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3.3 Stripper including condenser and water-wash

As for the absorber the diameter of the stripper column is determined by the vapour flow and the specification of 70 % of flooding velocity. According to Table 2-4 the structured packing Mellapak 2X will be considered at least for the reference cases. As in the absorber, the packing internals such as the gas and liquid distributor, redistribution plates, etc. will influence the height of the column (see Table 3-1). The liquid sump height depends on the type of reboiler and the design of it. In the stripper tower, one wash section is present above the stripping column to avoid solvent carryover. The wash section design is similar to the absorber wash section design as mentioned in Section 3.1. As indicated in Section 3.1 the number of stripper columns is more limited of the number of reboilers than the numbers of absorbers (see Section 3.4). The condenser cooler is a plate and frame type of heat exchanger with cooling water as the cooling medium. The overall heat transfer coefficient is given in Table 3.2.

3.4 Reboiler

The reboiler maintains the solvent temperature at the specified temperature (Table 2-7). The reboiler must be steam operated using the saturated steam from the power plant. It is decided to use the same type as used by Cansolv at the Boundary Dam facility. This is a Compabloc heat exchanger, which is the largest available and the supplier is Alfa Laval. At Boundary Dam9 there are 4 reboilers each of approximately 24 MW attached to one stripper10. For the Octavius we adopt this number (4) as the maximum number of reboiler units per stripper. Dependent on the total duty in the various Octavius cases this will determine the number of required stripper units per capture process train. A recent inquiry towards the Alfa Laval Company shows that the highest heat exchanger area for the Compabloc technology is 845 m

2. The overall heat transfer coefficient is given in Table 3-3

and from determined heat duty per reboiler unit the LMTD for this design can be calculated.

3.5 SO2 removal and pre-cooler

In the Kingsnorth FEED-study SO2 removal and WET ESP units were supposed to be combined with the direct contact cooler (DCC) used as the flue gas pre-cooler. In their cost-estimate this combined unit contributes considerably to the total CAPEX and thus the capture cost. In OCTAVIUS we assume that SO2 and fly ash are removed prior to the DCC and not part of the units necessary for CO2 capture only. For the direct contact cooler (DCC) an arrangement as shown in Figure 2-1 can be used with counter-current flow of water (process water) in direct contact with the flue-gas. Out of the DCC unit the flue-gas shall be saturated with water and the tank shall be dimensioned accordingly. The internal should be a packed section (Mellapak 2X) with distribution plates similar to an absorber

9 Cansolv Technologies inc., (2013), SaskPower Boundary Dam 3 – Project update and some lessons learned, 10 P. Micone, Capture Carbon Journal Conference, London, March 26th 2013


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wash section as described in Section 3.1. At the Enel pilot plant the packing is random (IMPT50) and the height of packing is 3.6 m. However, here it is decided to use structured packing as in both the absorber and stripper. At the Tiller plant, at which the packing type is Mellapak 2X, the height of packing is 1.5 m. This is enough for cooling the flue-gas to the desired saturation temperature also lower than 40°C. This height of packing is adopted for the OCTAVIUS project. Since the amount of flue gas is almost the same as the amount entering the absorber, the diameter must be the same as the absorber and the height up to the packed section will be similar. For Octavius, it is assumed that the total column height is 7.5 m.

3.6 Blower

In order to compensate the pressure drop of the flue gas in the capture plant (DCC+absorber), an additional blower is needed in the flue gas stream as indicated in Figure 2-1. The pressure drop in these units is indicated in Table 2-7 (DCC) and 2-8 (absorber). Since the required increase in pressure is relatively small, an axial blower is used similar to the induced draught.

3.7 Cross HX

The cross heat exchanger (lean-rich heat exchanger) shall be designed in such a way that the heat from the hot lean solvent is efficiently transferred to the rich solvent. The type of heat exchanger to be used is a plate and frame heat exchanger, thus the temperature approach (i.e. cold in – hot out) can be 5°C (according to Table 2-7). The overall heat transfer coefficient is given in Table 3.3 together with maximum area. Thus the number of units can be determined.

3.8 Pumps

Pumps are needed in different places in the capture plant. Centrifugal pumps are used for pumping the rich and the lean solvent, the process water in the absorber and stripper water-wash sections as well as the cooling water for the various coolers. The required pressure differences are quite small compared to the pressure differences of other pumps in a power plant, e.g. the feed pump. The sizes of the pumps differ a lot, the delivery rates differ between a few ten thousand and a few hundred m

3/h. The efficiency number to be used is given in Table 2-9.

3.9 LVC Compressor and flash tank

An LVC compressor will be used for recirculating of lean vapour back to the stripper after pressure relief, but upstream the cross-over HX. This lean recycling stream will consist mainly of water vapour, but also some solvent and CO2. The size of this unit and thus the CAPEX will highly depend on the flow-rate and pressure inlet conditions. The design of the flash tank needed for separation depends mainly on the lean flow rate and hold-up. The pressure is low (below stripper pressure).

3.10 Buffer tank, amine storage tanks, and other tanks

The required size and thus associated CAPEX will be scaled from other cost-estimate studies. For instance at Boundary Dam, the amine tank is 1758 m

3 in volume (18.5 m height and diameter

11m). The capture plant serves a 150 MW power station and thus the required size should be up-scaled to the relevant power-plant cases in Octavius.


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3.11 CO2 compressor

As stated in Section 2.4.5, an integrally geared (radial) compressor with six stages is considered for the benchmarking in OCTAVIUS (at least for the reference capture case). For the DMX

TM

process the stripper pressure is higher, so the number of stages might be changed. As mentioned in Section 3.1 the number of compression trains should be the same as the number of strippers making the operation more flexible.

3.12 Other HX

3.12.1 Lean cooler

The lean solvent stream must be cooled before it enters the absorber column to enhance CO2 absorption. This lean cooler, also known as trim cooler, further cools the lean solvent from the cross heat exchanger. A plate heat exchanger will be considered. The overall heat transfer coefficient is mentioned in Table 3-3 together with the maximum allowed area per unit. The LMTD is determined by simulation and cooling-water requirement as given in Table 2-6. Thus the number of required units can be determined.

3.12.2 Water-wash cooler

The water wash section maintains the water balance in the system and prevents solvent carry-over. Thus, the flow of the water wash liquid is kept constant while the temperature is controlled by means of the water-wash cooler. A plate heat exchanger will be considered here. The overall heat transfer coefficient is mentioned in Table 3-3 together with the maximum allowed area per unit. The LMTD is determined by simulation and cooling-water requirement as given in Table 2-6. Thus the number of required units can be determined.

3.12.3 CO2 compression intercoolers and after-cooler

The inter-coolers and after-cooler are considered to be plate type of heat exchangers. The overall heat transfer coefficient is given in Table 3-3 together with the maximum allowed area per unit. The LMTD is determined by simulation and cooling-water requirement as given in Table 2-6. It should be noted that care should be taken in case of that the cost-estimate for the CO2 compressor include these units.

3.13 Water dehydration

As stated in Section 2.4.5 we will consider a TEG plant for reducing water content in the CO2 stream to 50 ppm. It is assumed that CAPEX associated with this drier plant corresponds to 1% of total CAPEX for the capture and compression plant. However, it is believed that the energy requirement is negligible compared to other contributors 11.

3.14 Overall heat transfer coefficient for heat exchanger design

The overall heat transfer coefficient to be used for determining the size and thus the cost of the various heat exchangers required in the capture plant are listed in Table 3-3. Additionally, the max heat exchanger area is given in order to determine the number of units needed.

11 In line with the conclusions by Kemper et el. 2014, " Evaluation and analysis of the performance of dehydration

units for CO2 capture", Energy Procedia, 63 ( 2014 ) pp. 7568 – 7584


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Table 3-3: Overall heat transfer coefficient and maximum area for heat exchangers design

Heat exchanger U (W/m2K) Maximum HX area (m

2)

Reboiler: Compabloc HX from Alpha Laval 3200 845

Cross HX (plate HX*) 3000 1280**

Lean cooler (plate HX*) 3000 1280**

Plate HX Condenser 2000*** 1280**

Water-wash cooler (plate HX) 2000**** 1280**

Plate HX inter cooler for CO2 compression 400 1280**

Plate HX after cooler for CO2 compression 2000 1280**

* Gasket and brazed plate heat exchangers. ** Based on TL35 Model from Alfa Laval *** In the condenser basically three phenomena will take place (i.e., cooling of the steam, condensing of steam and cooling of water). This means that the overall heat transfer coefficient will change throughout the heat exchanger and for simplicity here, an average value is used considering a plate heat exchanger. **** This number is based on pure liquid-liquid heat exchanger

3.15 Reclaiming

To avoid accumulation of solvent contaminants, a reclaimer must be applied to separate degradation products and other contaminants from usable amines in the process. Optimization of the reclaimer process is important in order to minimize the amine consumption, but also because of regulations for handling of the reclaimer bottom products. There are several types of reclaimers. Some are operated in batch and others more in a continuous manner (slip-stream). Since we do not have any information of the required operational regime and nor the capital and operational cost of reclaimers we will not include it in the cost-calculations for use in the benchmarking in OCTAVIUS. However, the cost of amine make-up is indeed included in the OPEX calculation.

3.16 Additional cooling water plant

If the cooling-water requirement for the capture plant exceeds the existing capacity of the power plant, we need to include CAPEX associated with an additional cooling plant. In OCTAVIUS we assume the capacity of the cooling water-system for the power-plant is sufficient for serving the capture plant as well. However, the cost of the cooling water requirement for the capture plant is included in the utility cost (operating cost).

3.17 Spare units

Since it is common to have spare pump units it will be considered in OCTAVIUS one extra pump per equal type of pump (on extra pump per service) as indicated in Section 3-1.


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4 Basis for cost-calculations

4.1 Introduction

The methodology to be used for cost estimation related to the benchmarking in OCTAVIUS is outlined in this chapter. The cost estimation work in OCTAVIUS will be based on the EBTF work, but as previously stated some updates have been done. For the benchmarking in OCTAVIUS, the economic performance of the base case systems with and without CO2 capture (reference capture plants) shall be analysed, and then the OCTAVIUS capture processes (MEA and CESAR1) shall be compared to the capture reference plants using the same upstream base cases for the power plants (coal and NGCC). The economic viability of the selected processes is to be primarily determined through the CO2 avoidance costs and the breakeven electricity selling prices. It is important to make certain financial parameter assumptions, which are mentioned in section 4.2. The methodology for the capital and operational cost of the power plant is then explained in section 4.3. The cost of electricity based on this, is mentioned in section 4.4. Next, the capital and operational cost of the CO2 Capture plant is described in section 4.5. The resulting cost of electricity with CO2 capture and the corresponding cost of CO2 avoided are presented in section 4.6 and 4.7.

The list of abbreviations is given in Table 4-2.

Table 4-1: List of abbreviations used

CAPEX Capital Expenditure/Capital Costs

OPEX Operating Expenditure/Operational Costs

WACC Weight Average Capital Costs

NPV Net Present Value

COE Cost of Electricity

TEC Total Equipment Cost

TDPC Total Direct Plant Cost

DCC Direct Construction Costs

ICC Indirect Construction Costs

TIPC Total Indirect Plant Costs

LHV Lower Heating Value

FCI Fixed Capital Investment

TCI Total Capital Investment

4.2 Financial parameter assumptions

As mentioned the methodology is according to the same lines as described in the CESAR-EBTF work. The basis for costs in Octavius is the year 2012 (while it was 2009 in EBTF) and the corresponding CEPC Index over the years is as shown in Figure 4-1. The number used for 2012 is 595% (see also Section 4.5).


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Figure 4-1: Chemical Engineering Plant Cost Index (monthly 2004-2012)

Table 4-2 presents the main input data for the economic model. These include the lifetime of the power plant and capture plant and the amount of operational hours. Table 4-3 shows the annual budget allocation for the plant construction period (including commissioning phase) assumed for both the power plants.

Table 4-2: General input for economic model.

Parameter Value Units

Lifetime Capture Plant 25/40* yr

Lifetime Coal-fired Power Plant 40 yr

Lifetime Natural Gas-fired Power Plant

25 yr

Operating hours per year 8000 hr/yr *Dependent on type of up-stream plant (25 years for NGCC and 40 years for coal)

Table 4-3: Annual allocation of finances for plant construction.

Year Allocation 3 years

(natural gas cycles)

Allocation 4 years (coal fed systems)

1 40% 20%

2 30% 30%

3 30% 30%

4 0 20%

A compounding factor is calculated with a Weight Average Cost of Capital (WACC) of 8%. The annual cash flow is the annual income minus the annual costs before tax. The annual income is the number of operating hours times the selling price of electricity in € per MWh. The annual discounted cash flow is calculated by multiplying the yearly cash flow and the compounding factor.


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The Net Present Value (NPV) is the cumulative annual discounted cash flow over the construction period and the lifetime of the project.

4.3 Power plant costs

The power plant costs consists of the Capital cost/CAPEX and the operational cost/OPEX. Data for the CAPEX of a power plant is supplied by the power companies in the consortium. The operational costs are divided into variable costs and fixed costs. The operational variable costs are mainly fuel costs. The fixed operational costs are based on experience from power companies. The CAPEX and the fixed cost part of the OPEX for the power plants are calculated from the information in Table 4-4. The variable part of the OPEX in the case without CO2 capture is calculated from the net electricity produced, the efficiency of the power plant, the LHV of the fuel and the fuel price. The fuel price for coal was assumed to be 3.0 €/GJ while, the remaining assumptions are as mentioned in sections 2.2 and 2.3.

Table 4-4: CAPEX and OPEX for power plants

Power plant Type

CAPEX [€/kWe gross]

Fixed OPEX [€/kWe gross]

Fuel costs [€/GJ]

Coal fired 1440 44 3.0*

NGCC 847 44 6.5

* Estimated average value based on 2015 value

4.4 Cost of electricity without CO2 Capture

The cost of electricity is calculated from the CAPEX and OPEX for a power plant. The cost of electricity is calculated for a power plant by varying the selling price of electricity in order to find a NPV of zero from the cumulative cash flows over the construction and lifetime period of the plant. The selling price for which the NPV is zero, is called the breakeven Cost Of Electricity for the reference case (COEreference). It should be noted that both the fuel costs (Table 4-4) and the electricity price have values, dictated by market circumstances. Historical values and scenarios for the future could be used to calculate the COE. However, this is out of scope in the current methodology as the objective of this exercise is a relative comparison between the different cases and not absolute values.

4.5 CO2 capture plant costs

The method to calculate the Capital costs/CAPEX and Operational costs/OPEX of a CO2 capture plant is explained in this section.

4.5.1 Capital cost/CAPEX of the CO2 capture plant

4.5.1.1 Total Equipment cost (TEC) The main equipment for the CO2 capture process is sized from the mass and energy balance. As mentioned in Section 2.5 the mass and energy balance for the capture process are solved using the in-house software tool CO2SIM, while the CO2 compression part of the capture process is modeled and simulated with the software tool EBSILON®Professional 9.00. The equipment units


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considered for the capture plant are described in Chapter 3. Table 3-1 gives a list of the major equipment, which forms the basis for the Total Equipment Costs. As mentioned in Chapter 3 one spare pump shall to be considered per service. Furthermore and also indicated in Chapter 3, the number of reboilers per stripper is limited to maximum 4 reboilers per stripper. The total reboiler duty needed and the maximal duty per reboiler determine the number of reboilers and thus the number of strippers. The necessary utilities, like steam, electricity and cooling water, for the capture plant are supplied by the power plant and no additional equipment such as a cooling tower is included. Costs need to be made to connect the power plant with the capture plant. These costs will depend on the situation. For instance, a newly build power and capture plant are easier to connect than an existing power plant to a new capture plant. No costs for connecting the power plant to capture plant are budgeted in this study. The costs of the main equipment are determined from public data, proprietary owned information and vender supplied information. The equipment costs for a certain capacity may be scaled from power-law cost correlations to the proper capacity. If the costs are known from a period before beginning of 2012, the Chemical Engineering Plant Cost Index (CEPCI) is used to correct the costs to the beginning of year 2012. The CEPCI value of beginning 2012 is 595%. The value of CEPCI as function of time is given in Figure 4-1. The detailed correlation for costs of each equipment unit is out of the scope of this chapter. The sum of all the equipment costs is called the

Total Equipment Costs (TEC).

4.5.1.2 Total Direct Plant Cost (TDPC) The Total Equipment Costs are used to estimate the costs of construction of the whole capture plant. Direct and indirect costs are distinguished for the construction costs. Fixed percentages of the TEC are taken for the cost of the Direct Construction Costs (DCC), as given in Table 4-5.

Table 4-5: Direct Construction Cost (DCC)

Direct Construction Costs titles

Instrumentation and Controls 9 % of TEC

Piping 20 % of TEC

Electrical Equipment and Materials 12 % of TEC

Civil works 11 % of TEC

Erection, Steel structures and painting 49 % of TEC

The sum of the Total Equipment Costs and the Direct Construction Costs are the Total Direct

Plant Costs (TDPC), i.e. TDPC = TEC + DCC=2.01 * TEC.

4.5.1.3 Total Indirect Plant cost (TIPC) The Indirect Construction Costs (ICC) is taken as fixed percentages of the TDPC, and is as given in Table 4-6. The Indirect Construction Costs are summed in order to give the Total Indirect Plant Costs (TIPC).


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Table 4-6: Indirect Construction Cost (ICC)

Indirect Construction Costs

Yard Improvements 1,5 % of TDPC

Service Facilities 2,0 % of TDPC

Engineering, Supervision and construction 6,5 % of TDPC

Buildings (Including Services) 4,0 % of TDPC

The sum of the Total Indirect Plant Costs and the Total Direct Plant Costs are the Fixed Capital

investment (FCI) i.e. FCI = TIPC + TDPC=1.14*TDPC.

4.5.1.4 Total Capital Investment (TCI)/CAPEX Finally, there are additional costs that contribute to the Total Capital investment (TCI) or CAPEX. The values taken for additional costs are given in Table 4-7.

Table 4-7: Additional costs

Startup costs (solvent) 1 inventory

Contingency 15 % TCI

Capital fee 2 % TCI

Working capital 3 % TCI

The TCI/CAPEX of the capture process is then Fixed Capital Investment (FCI) and additional

costs, i.e. TCI=FCI + Additional costs=FCI/0.8

4.5.2 Operational cost/OPEX of the CO2 capture plant

The operational costs/OPEX is the sum of Direct Production Costs and Fixed Charges and is calculated as follows.

4.5.2.1 Direct Production Cost The Direct Production Cost is the sum of variable and fixed production costs. The variable costs are related to usage of raw materials and utilities. The fixed costs are related to the maintenance and labour. An overview of the direct production costs are given in Table 4-8.

Table 4-8: Direct Production costs

Description

Variable costs Raw Materials

Utilities

Fixed Costs

Maintenance and Repairs

Operating Labor

Operating Supervision

Operating Supplies

Laboratory Charges


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Raw material costs are for the replacement of degraded MEA and activated carbon for MEA cleaning. Utilities are costs for cooling water and process water as obtained from the power plant. Steam and electricity are supplied by the power plant. The costs of the main consumables are listed in Table 4-9.

Table 4-9: Cost of consumables

Consumable Cost

Process water* 0.45 €/m

3 (1)

Process water make-up rate

Depending on mass balance capture process

Cooling water** 0.30 €/m

3 (1)

Cooling water make-up rate 1 m3/GJ cooling duty

MEA make-up 1.5 kg/ton CO2 separated

MEA 1500 €/t (2)

Activated carbon make-up 0.075 kg/ton CO2

Cost of activated carbon 3038 €/t *Include clarification and chlorination process,

**Include clarification and chlorination process, corrosion inhibitors, biological inhibitors.

Contribution to CAPEX for cooling water system is included in these costs (1)

SRI PEP Report n°136A, 1995, update by IHS-CERA DCCI cost index 2010 2)

Based on MEA supply cost on ENEL pilot, Brindisi, Italy

Operation labor is calculated from the number of people per shift, the number of shifts per year and the hourly wage; see Table 4-10.

Table 4-10: General Input for operational labor costs capture plant

Parameter Value Units

Working hours per

man

1752 hr/man/yr

Number of shifts 5 #

People per shift 2 #

Labour 17520 hr/yr

Wage tariff 45 €/hr

The other fixed production costs are calculated with the percentages given in Table 4-11.

Table 4-11: Percentages for calculating fixed production costs

Fixed production costs

Supervision 30 % of operating labor costs

Maintenance 2.5 % of FCI

Operating supplies 15 % of Maintenance

Laboratory charges 10 % of total labor costs

Plant overhead costs 60

% of maintenance, operating labor and supervision


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4.5.2.2 Fixed Charges The Fixed charges and general expenses are calculated with the percentages in Table 4-12. No expenses are taken into account for distribution, marketing, research and development and financing.

Table 4-12: Fixed charges for production costs

Fixed charges production costs

Taxes 2 % of FCI

Insurance 1.5 % of FCI

Administrative Expenses 20 % of operating labor costs

4.6 Cost of electricity with CO2 capture

The cost of electricity for the power plant combined with a capture plant is calculated in the same way as the COE for the power plant alone as mentioned in section 4.4, however now with a lower electricity output. The cost of electricity is calculated for a power plant together with the capture plant by varying the selling price of electricity in order to find a NPV of zero from the cumulative cash flows over the construction and lifetime period of the power and capture plant. The selling price, for which the NPV is zero, is now called the breakeven Cost Of Electricity for the capture case (COEcapture).

4.7 Cost of CO2 avoided

The breakeven Cost Of Electricity (COE) of the power plant with capture plant (COEcapture) and power plant without capture plant (COEreference) is used to calculate the cost of CO2 avoided. The cost of CO2 avoided is expressed as cost per tonne CO2 pollutant avoided. In all cases, the cost of CO2 avoided is given relative to a reference plant without capture:

capturereference

referencecapture

EmissionCOEmissionCO

COECOEtonAvoidedCOofCost

)/€(

22

2

4-1

where COE is defined as cost of electricity for the capture case and the reference case in €/MWh. CO2 Emissionreference is CO2 emitted per MWh of electricity produced for the reference case, while the CO2 Emissioncapture is CO2 emitted with capture per MWh of electricity produced with the capture unit attached to the power plant.


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5 General operability

5.1 Emission to air and water related to solvent management

5.1.1 Emission to Air

The scope of emissions to air is related to components present in the sweet gas stream from the absorber which is released to the atmosphere. There could also be components present in the pure CO2 stream from the stripper, which could affect the subsequent compression stage, but that will not be considered within OCTAVIUS. The emission to air can be classified into the following categories based on the mode of emission:

Gas/Vapour emissions The emissions of components in the form of gas/vapour are due to its volatility at the specific temperature.

Aerosol emissions Emissions in the form of aerosols arising from sulphuric acid nuclei, fine dust, etc. have been observed in absorbers of capture units, especially from coal-fired power plants.

Emissions can also be classified based on the components involved as follows:

Amines Amines typically used in carbon capture plants can have a significant partial pressure at the operating conditions and thus, can be emitted in the vent gas stream from the absorber.

Ammonia Ammonia is a typical degradation product of amines and is extremely volatile. Thus, emissions of ammonia can be expected in the absorber vent gas stream.

Nitrosamines/Nitramines Nitrosamines can be formed by reaction of amines with NO+NO2 (present in the flue gas) or nitrites (degradation products of amines) and nitramines are obtained by nitration of amines with NO2. These nitrosamines and nitramines may be carcinogenic and thus, their emission into the atmosphere must be considered as of importance.

Miscellaneous Amines can be degraded during operation. This can lead to a wide variety of different degradation products. Some of these degradation products can be volatile (e.g. aldehyde) and can be subsequently emitted.

Limits The limit assumed for the total Amine in OCTAVIUS is given in Table 2-4. If some of the benchmarked processes in OCTAVIUS will exceed this limit and thus require other means than the standard washing section to meet the target this may be reflected in the cost calculations. However, it will not be determined specifically for the benchmarking in OCTAVIUS and thus other means for utilizing the emission to air criterion is considered as given in Section 5.1.3.


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5.1.2 Emission to water

The emission directly to water relates to the liquid waste generated on site of the capture plant. As all the aforementioned components are present in the liquid along with the degradation products of the solvent components, liquid waste must be handled carefully. If certain type of counter-measures is applied, then the liquid waste generated must be treated appropriately. Liquid waste arising out of solvent leak must be sent for special chemicals disposal while liquid waste due to dilute aqueous streams must be sent to the waste water treatment plant. If possible this should be reflected through the cost of treatment. But as for the air-emission it is not possible to calculate the cost associated with this extra treatment in OCTAVIUS so it will be considered more qualitatively as part of benchmarking as indicated in the next section..

5.1.3 Use of the emission criterion for benchmarking in OCTAVIUS

As indicated in the two previous sections detailed calculation of emission will not be done for the benchmarking. However, as the solvent systems to be considered are MEA, CESAR1 and the DMX solvent, they can be ranked according to their volatility, degradation rate, and possible formation of harmful nitrosamines/nitramines based on experiences obtained in other tasks in OCTAVIUS. Also requirement of additional counter-measures in addition to the standard washing section for the emission to air and standard process water treatment for the emission to water shall be indicated. This criterion will thus be of more qualitative nature and should be used as a support to the power plant efficiency and cost criteria in the benchmarking work.

5.2 Flexibility

5.2.1 General about flexibility

High flexibility is essential for efficient operation of a power plant under current operation with increasing amounts of renewable energies that forces conventional power plants to be operated in part-load more often. Thus, flexibility too becomes integral part of the benchmarking. In order to benchmark the specific configurations the plant has to be simulated at different operating points. The operating points are defined on the basis of the power output of the power plant. The operating points could be fixed e.g. at 40 and 70 % of net power output. The capture plant is affected by the power reduction in different ways:

The flue gas mass flow is reduced. The exact value cannot be obtained by multiplying the mass flow at full-load with 0.7 respectively 0.4, it has to be obtained through a thorough simulation of the power plant instead. This is due to the fact that the efficiency differs between full-load and part-load for each component and the whole plant itself. In addition, the air ratio is higher under partial load.

The flue gas composition is different too, due to the higher air/fuel ratio. This can also be obtained from the simulation.

The changes in the live steam parameters and the isentropic efficiency of the turbines alter the temperature and pressure of the steam which is required for the reboiler.

Some of the effects part-load has on the capture plant components are:

Pumps and blowers have different efficiencies at full-load and at part-load.


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The heat exchangers are more efficient when the mass flow is reduced. The heat flow is lower due to the reduced mass flow, so that the mean logarithmic temperature difference needed is reduced as well.

The absorber and the stripper are more efficient when the mass flow is reduced. The mass transfer is enhanced because the velocities in the columns are reduced and the retention time thus increases.

One of the most important parameters determining the performance of the capture plant under partial load is the number of trains the plant consists of. This should be kept in mind when fixing the part-load operating points. It might be reasonable, for example, to choose operating points where some of the lines are completely disabled while the rest operate at full-load.

5.2.2 How to use the flexibility criterion for the benchmarking in OCTAVIUS

Within task T24.2 of OCTAVIUS the main purpose was to study various operational strategies for the operation of the capture plant in order to cope with the "capacity on demand" way of operating the upstream power plant. Both some experimental tests in the Brindisi pilot plant were conducted12 as well as process simulations of the same pilot plant13. The solvent system was 30 wt% MEA in both cases. Both on/off operation and intermittent stripping in which solvent was stored and regenerated at a later stage were tested in the pilot plant. The pilot plant is equipped with two storage tanks both located on the "lean side" of the cross heat exchanger. The modes of operation assuming a given operation scheme (load) of the upstream power plant simulated with the K-spice model (of the Brindisi pilot plant) developed in SP1 were: 1. Load-following. To check the response in the capture plant with an assumed reduction of

flue-gas rate to 60%. 2. Exhaust gas venting. A fraction of the flue-gas (of the nominal flow to the capture plant)

bypasses the capture plant meaning that a momentary capture rate is below 90%. 3. Varying degree of solvent regeneration. The steam rate used for solvent regeneration is

decreased during peak electricity price periods meaning that CO2 accumulates in the solvent. When the electricity price is normalized the regeneration is increased so the average capture rate is kept at 90 % over the 24 simulation period.

4. Solvent storage or intermittent stripping. This is the same as tested at the Brindisi pilot, but in the simulations it is assumed that one of the storage tanks is placed on the "rich" side so that rich solvent can be fed directly to the stripper. During the same peak price periods a fraction of the solvent is stored in the storage tank so the steam required for regeneration is reduced. It is assumed that some lean solvent is fed to the absorber from the other storage tank in order to keep the same solvent flow-rate.

Simulations of load following operation shows that the process reacts fast to load changes and the process is able to stabilize at both part and full load operation. Solvent storage gives

12 Mangiaracina, A., Zangrilli, L., Robinson, L., Kvamsdal, H., van Os, P., (2014), OCTAVIUS: Evaluation of flexibility and

operability of amine based post-combustion CO2 capture at the Brindisi Pilot Plant, poster presentation at 12th International

Conference on Greenhouse Gas Control Technologies conference (GHGT-12), Austin, Texas, 5th-9th October, Energy Procedia,

63, pp. 1617-1636 13 Enaasen Flø, N., Kvamsdal, H.M., and Hillestad, M., (2015), Dynamic Simulation of Post-combustion CO2 Capture for Flexible

Operation of the Brindisi Pilot Plant, submitted for publication in a special issue of International Journal of Greenhouse Gas

Control


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satisfactory results when it comes to average capture rate and energy performance in a varying electricity market. However, considerable investments are required for solvent storage tanks and additional operating solvent. The mode of exhaust gas venting and varying solvent regeneration is able to operate without any process modifications. Exhaust gas venting seems to give favorable average capture rate and energy performance indicators compared to the latter. It is beyond scope and budget to do similar simulations for the large scale reference cases and the cases to be benchmarked. However, though the simulations were done for a capacity of a pilot plant, it is assume that the results will be similar for a large scale plant given the same computational assumptions and cases. Thus the results are indicative at least for coal power station and the MEA as solvent system in the capture plant (no LVC though). By considering the four types of modes of operation the other processes to be benchmarked should be assessed in a qualitative manner.

5.3 Dynamics and control

Though we have tested some dynamics and controllability in OCTAVIUS there is still no (at least not reported) experience with large scale operation. However, there are some aspects in the processes to be benchmarked which may imply operational challenges (see Kvamsdal et al., 200614 for further details). These aspects will have cost effects related e.g. to availability and maintenance, but are difficult to estimate. For OCTAVIUS it is easier to quantify:

The number of incidences of heat- and process integration with the power-plant/CO2 compression train

Number of recycle loops

Duty of the main heat exchangers For the DMX

TM process, which relies on phase changes the effect on the operability shall

additionally be assessed in a qualitative manner.

14 Kvamsdal, H.M., Jordal, K., Maurstad, O. and Bolland, O., (2006), A Qualitatively Based Comparison of Gas Turbine Cycles

with CO2 Capture, in proceedings of The Eight International Conference on Greenhouse Gas Control Technologies – GHGT-8,

Trondheim, Norway, June 19 - 22

Documents

EUROPEAN COMMISSION DG ENERGY - Projets IFPENprojet.ifpen.fr/Projet/upload/docs/application/pdf/... · and Cesar1 as solvent systems. A multi-heating stripper and the DMX TM process