co2 capture within refining: case studies - rosa maria domenichini, foster wheeler

© Foster Wheeler 2013. All rights reserved

CO2 Capture within Refining: Case Studies

3rd CCS Cost Workshop Paris, 6-7 November 2013

Rosa Maria Domenichini Director, Power Division Foster Wheeler


•  Contribution of refining to world CO2 emissions

•  Refining processes

•  Major refinery CO2 emission sources

•  Applying carbon capture to the refinery: case studies

•  Conclusions

1

Agenda

CO2 capture within refining processes


Introduction

2

Contribution of refining to CO2 emissions

Source: NETL DOE website (2013) http://netldev.netl.doe.gov/research/coal/carbon-storage/carbon-storage-natcarb/co2-stationary-sources

Source: concawe report 07/11 https://www.concawe.eu/DocShareNoFrame/docs/4/AKPHIDGDCMEBKOOKOOLLCGBDVEVCWY939YBYW3B6AYW3/CEnet/docs/DLS/Rpt_11-7-2011-03321-01-E.pdf

Ø  Refining contribution: 6%

Ø  Annual CO2 emissions up to 4-5 million tons/year for the largest refineries (400,000 BPSD equivalent to approx 20,000,000 tons/year of crude oil)


Ø  Most carbon entering the refinery leaves again with the hydrocarbon products; CO2 emissions related to the chemistry and mostly to the energy demand of the refinery processes

Ø  Typically 5-10% of thermal power entering is lost, increasing trend due to more stringent product specs, heavier crude oils, need to reduce/eliminate heavy products

Ø  Multiple dispersed sources over large areas

Reduction of refining carbon footprint Ø  Efficiency improvements/flaring reduction Ø  Feedstocks/fuels substitution Ø  Modifications to refinery configuration Ø  Carbon capture and storage

3

Contribution of refining to CO2 emissions



Modern refinery simplified scheme

4

Topping

Vacuum

Delayed Coker

HDT (naphtha)

HDCK

FCC

GPL

gasoline

HDS (Kerosene)

kerosene

GasificaBon

HDS (Gasoil)

gasoil

CCR

products

H2

H2

H2

H2

H2



5

CO2 sources

Chemicals producBon via boGom of the barrel

gasificaBon •  heavy liquid residue •  petcoke

Refinery Hydrogen via steam reformer

Process heaters & al Topping/Vacuum, CCR,

HDS, HCK, TGT incinerator, FCC regenerator, etc)

Refining

Power plant

Hydrogen

Methanol

SNG

Others (GTL, ferLlizers…)

Flare (no capture)

© Foster Wheeler 2013. All rights reserved 6

Example of rough split of major CO2 emitters


Process heaters / FCC regenerator

55%

Power/steam generation

20%

H2 production 25%


CO2 capture from process heaters flue gas

7

More emitters, same area/different sizes, to the same stack

Process unit

Fuel gas absorber

Heat recovery

H2S to SRU

Flue gas to atm

Compressed CO2

CO2 capture plant

Fuel oil Fuel gas NG

NEW UNIT

Main process heaters joint:

crude disBllaBon unit, catalyBc reforming,

HDS



8

CCU utility requirements: two scenarios…

CO2 capture plant

CO2 compression

Utilities available from refinery Utilities NOT available from refinery (fit for purpose) Compressed CO2

Flue gas

EE LP steam

Boiler

Power to CO2 compressor

Power to AGR

Deaerator

Condensate Make-‐up



9

Bases for the analysis

LocaLon -‐ Central Europe

Total capital requirement -‐ TIC + 20%

IRR % 10

Plant life years 25

Financial leverage % debt 100

InflaLon rate % No inflacLon

Electricity price €/MWh 70

Steam price €/t Equivalent to loss of power producLon

NG cost $/MMBtu 12

CO2 condiLons @ BL -‐ 110 bar, liquefied

CO2 transport and storage cost €/t 10



10

Case study: refinery heaters Case UBliBes from refinery Dedicated power plant

Refinery size 300,000 bpd

Origin of emission Common stack on furnaces in crude disLllaLon unit, catalyLc reforming, HDS

CO2 balance

CO2 produced (process) t/h 100 100

CO2 captured (process) t/h 91 91

CO2 emiced (uLlity plant) t/h -‐ 19

CO2 abated (total) t/h

(ktpa) 91

(700) 72

(555)

UBlity requirement

Natural gas MWth -‐ 98

Electrical consumpLons MWe 12.1 (1)

LP Steam consumpLon (4 barg, sat) t/h 120 (1)

Economic data

Total capital requirement M€ 153 181 (1) Generated internally



11

Case study: refinery heaters

Case UBliBes from refinery Dedicated power plant


CO2 avoidance cost

Central Europe (NG cost: 12 $/MMBtu EE cost: 70 €/MWh)

€/t 72 103

USA (NG cost: 4 $/MMBtu EE cost: 50 $/MWh)

€/t 60 80


CO2 capture within H2 production process

12

Different alternatives available

Steam reforming

Feed ShiX

Fuel

PSA H2

CO2 capture OpLon #3



Flue gas

PSA tail gas

Achievable CO2 capture 90%





13

Case study: option 1

Steam reforming

Feed ShiX

Fuel

PSA H2 CO2 capture

OpLon #1

PSA tail gas

CO2 capture 99.5%

Flue gas

MDEA absorber

CO2 stripper

CO2 drying/ compression


Hydrogen from steam reformer

Hydrogen producLon Nm3/h 150,000

AGR CO2 balance

CO2 captured kmol/h (ktpa)

1,702 (623)

CO2 capture rate % 99.5

AGR + compression unit consumpBon

Electrical consumpLons MWe 10.1

LP Steam consumpLon t/h 20.2

Hydrogen losses Nm3/h 175

Economic data

Total capital requirement M€ 92

CO2 capture cost (OpLon #1) €/t 47

CO2 capture cost (OpLon #3) €/t 65


14

Case study: option 1


Joint CO2 capture from different refinery processes

15

CO2 capture from process heaters flue gas and within H2 production process

CO2 capture plant

CO2 compression

Compressed CO2

Flue gas

Boiler

Power to CO2 compressor

Power to AGRUs

Deaerator

Make-‐up

CO2 capture plant

Reformed gas

To PSA


Joint CO2 capture from different processes

CO2 capture from process heaters flue gas and within H2 production process


Hydrogen from steam reformer Nm3/h 150,000

Origin of emission Common stack on furnaces in CDU, reforming, HDS, steam reformer

CO2 balance

CO2 produced t/h 224.8

CO2 captured t/h 165.9

CO2 emiced t/h 24.1

CO2 abated t/h

(ktpa) 141.8 (1093)

UBlity requirement

Natural gas MWth 122

Electrical consumpLons MWe 22.2

LP steam consumpLon t/h 140

Economic data

Investment cost M€ 284

CO2 avoidance cost €/t 78


CO2 capture within an XTP plant

17

Hydrogen case

CO2 to atm

ASU

CO Shil

Heavy residue 70 t/h

Raw Syngas

Oxygen

SRU & TGT

Sour gas

ULliLes and Offsites

ShiXed syngas PSA Clean

syngas GasificaLon AGR

Hydrogen 150,000 Nm3/h

CO2 compression

CO2

CO2 TO STORAGE

CAPTURE RATE 87%

NEW UNIT



18

Hydrogen case

Hydrogen from asphalt

Liquid heavy residue flowrate t/h 70

Raw syngas flowrate kmol/h 22,000

Hydrogen producLon Nm3/h 150,000

CO2 balance

CO2 captured kmol/h (ktpa)

4,370 (1,430)


Compression unit

Compression consumpLons (up to 110 bar) MWe 13.3


CO2 capture cost €/t 19



19

Methanol case

CO2 to atm

ASU

CO Shil

Heavy residue 148 t/h

Raw Syngas

Oxygen

SRU & TGT

Sour gas

ULliLes and Offsites

ShiXed syngas

Methanol plant

Clean syngas GasificaLon AGR

MeOH 4000 TPD

CO2 compression

CO2

CO2 TO STORAGE

CAPTURE RATE 43%

NEW UNIT



Methanol case (*)

Methanol from asphalt

Liquid heavy residue flowrate t/h 148

Raw syngas flowrate kmol/h 46,000

MeOH producLon (*) tpd 4,000

CO2 balance

Captured CO2 kmol/h (ktpa)

4,490 (1,470)


Compression unit

Compression consumpLons (up to 110 bar) MWe 13.6


CO2 capture cost €/t 19

(*) or GTL process (LPG production 745 bpd, naphtha production 3,300 bpd, Diesel production 6,600 bpd)


•  Refineries are not larger CO2 emitters, but CO2 capture needs to be considered

•  Number of options available for applying carbon capture to most of the CO2 sources in a refinery

•  Post combustion CO2 capture in refining process still expensive

•  Both pre and post combustion CO2 capture applicable to Hydrogen process; pre-combustion capture fostered by the process itself (limiting capture rate)

•  CO2 capture in chemical production strongly convenient CO2 being already available at plant BL (limiting capture rate): only compression needed

•  Transportation economically attractive requires scale economy

•  Application of oxy-combustion to refining processes under R&D (FCC regenerator)


Summary findings


•  The most suitable options for each source to be determined by site-specific study (set the target, perform C balance, select optimal technologies, develop reliable site-specific cost estimate)

•  Impacts on an existing refinery:

Ø  Incremental steam generation / power consumption of CO2 capture may require a dedicated boiler

Ø  Increased consumption of fuel gas/ reduced CO2 abatement

Ø  Increase in service and cooling water withdrawal

Ø  Impact on plot plan (ducting, CO2 capture and compression units)

•  To make carbon capture economically attractive, the CO2 needs to have a value significantly higher than actual EU ETS, unless EOR is applicable.

Summary findings



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co2 capture within refining: case studies - rosa maria domenichini, foster wheeler

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annual co2 emissions

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