Hydrogen Management Console (HyNDTTM)

ERTC 09-11 November 2009

M. PaganoM. Pagano

Why Managing H2

Deep conversion refineries with and high level of bottom-of-the-barrel conversion can have an H2 demand up to 2.7%wt of total crude input

2

Hydrogen plays a capital role both for the environment and for an effective usage of energy

The hydrogen sources have to be studied in their synergies with hydrogen users to determine the most effective way of satisfying refinery needsThe approach will be different for new refineries or for

revamps

Why Managing H2

3

H2

ROG

Grass Root Refineries

The optimum configuration for a new complex has to satisfy both the present and the future hydrogen demand

Possible developments of fuels specifications have to be examined

The following goals have to be pursued: High level of H2 Availability Adequate Flexibility Lowest CAPEX Lowest Operating costs

4

5Revamping of Existing Refineries

The issue is to deal with increasing demand of hydrogen while: Upgrading of the existing Hydrogen Generation Unit (HGU) Adding a new on purpose HGU Performing an Integrated utilization of the Refinery Off-Gas (ROG) Studying and assessing the possible H2 recovery solutions from ROG streams Assessing the impact on performances of hydro-processing units caused by H2

make-up with lower purity

In this respect the approach is twofold: Internal optimization of the HGU External optimization of the H2 network

Why Managing CO2

6

A modern high conversion refinery produces: 0.330.4 ton CO2 per ton of crude (without residue gasification) 0.7 ton CO2 per ton of crude (with residue gasification)

However, the major sources of CO2 in a refinery are scattered on the plot plan

Coupling H2 and utilities production in the HGU or IGCC can be a way of having a single source for CO2 captureThe impact of carbon emissions trading scheme on a refinery

is very complex Use of LP model can help to asses the impact of changing emissions costs

on the refinery operation and configuration

How to Manage CO2

Typically there are 6 options to reduce GHG emissions

Energy efficiency

Switch fuel

Renewable energies

Aforestation/reforestation (not relevant)

Reduce emissions of other gases than CO2

Carbon Capture and Storage

7

8 Whatever is the fuel used to substitute the equivalent energetic content of 1 ton/h of recovered H2, there is an effect on the overall CO2 emissions, which shall be carefully evaluated in a CO2 emissions trading scheme (i.e. ETS scenarios)

CO2 Produced by fuel substitution of 1 Ton/h of Hydrogen:

LHV (kcal/kg) CO2 (ton/h)

Hydrogen 28661 -

Methane 11947 6.60

Ethane 11342 7.41

Propane 11071 7.77

Fuel Oil 9680 9.50

H2 & CO2 Management(Example of Fuel Substitution)

H2 & CO2 Management(Example of Fuel Substitution)

9

CO2 emissions per T/h of Hydrogen produced through SR

CO2 INDIRECT FROM UTILITIES

CO2 from Utilities Production/Generation (x1 Ton/h of Hydrogen)Hp. (CH 4 is used in a CC power plant and for Steam boilers)

Natural Gas feedstock Light Naphtha feedstockGcal/h/Ton of hydrogen Gcal/h/Ton of hydrogen

steam -9.7 -6.52 -6.12power 246376.8 0.42 0.46

TOT. -6.09 -5.67

Related CO2 produced Related CO2 produced -1.40 Ton/h -1.30 Ton/h

SR OVERALL CO2 BALANCE

CO2 from Production of 1 Ton/h of pure Hydrogen (99.9 %vol.)

Natural Gas feedstock Light Naphtha feedstock9.17 ton/h of CO2 10.99 ton/h of CO22.79 ton/h of CO2 3.30 ton/h of CO2

-1.40 ton/h of CO2 -1.30 ton/h of CO2Tot = 10.56 ton/h 13.00 ton/h

CO2 exit CO Shift ReactorsCO2 from FG firing CO2 from Indirect Utilities Prod./Gen.

10

CO2 Recovery in the H2 plant(Example of Carbon Capture)

GasifierSyngasAmineWash COShift

CO2 for sequestration/Enanched Oil Recovery/Urea production

O2

Coal/TAR

IGCC

Refinery

GTL/CTL

Ammonia/Urea

MeOH

PSA

11

Technips Tool for H2 & CO2 Management

Technip can help refiners to find out the optimum solution using its group transversal competences and advanced methodologies: Knowledge of the available options for hydrogen production, supply and

recovery

Suite of tools based on advanced LP modeling, for planning of the all refinery operations

Expertise on equipment costs estimate with a scaling accuracy

These competences are now concentrated in TechnipsHydrogen Network Design Tool

12

HyNDT Hydrogen Network Design Tool

Interfaces between process simulators and LP are made easy by the use of HyNDT

LP can help in retrieving the optimum configuration with the following cautions: The optimization of H2 usage shall be able to identify the trade-off between H2

purity, pressure and recovery level from ROG

Before any H2 model optimization, an off-line screening to fix the reasonablehydrogen recovery solutions is preferable

13

HyNDT versus Hydrogen Pinch Analysis (HPA)

The HPA, traditionally used, is not sufficient to model the complexity of the network design It only considers flow rates and purities of streams containing hydrogen while

neglecting: Pressure of hydrogen rich stream

Spare capacity on existing compressors

Safety

Piping routing

Operability/Availability

CAPEX/OPEX

The result is a mere hydrogen balance closure

14

HyNDT Work-Flow

H2 SystemCO2 recovery

(LP model)

Refinery

Modelling

HGU Preliminary

Design

H2

Network

Process & Utilities units modelling

H2 headers identification

H2/CO2 Balance validation

Off-gas & purge streams

Optimization

Routine

Options Screening

LP Modelling

and/or

Off-line analysis

Cost Estimate &

Cost factors

Configuration

Selection

Max Refinery Operating Margin

Min pay out time

Iteration

Infos gathering(Environment definition)

15

HyNDT has successfully been used to optimize the hydrogen network of a complex grass root refinery in Tatarstan for which Technip has performed a detailed feasibility study

The Complex will be designed to process 7 million tons per year of Carbonic Crude (23.4 API, Sulfur = 3.8 wt %) and it will have the following features : Maximization of Diesel and Jet Kero fuels @ EURO V specifications Minimization of residue (i.e. Deep Conversion Scheme/Zero fuel oil Refinery) Production of Benzene and Paraxylene

Case Study: Grassroot Refinery in Tatarstan

Refinery Block Flow Diagram

16

The selected process configuration is shown below:

CRUDECRUDEDISTILL.DISTILL.

UNITUNIT

VACUUMVACUUMDISTILL.DISTILL.

UNITUNIT

NAPHTHANAPHTHAHDTHDT

KEROKEROHDTHDT

DIESELDIESELHDTHDT

HYDROHYDROCRACKERCRACKER

SOLVENTSOLVENTDEASPHALTINGDEASPHALTING

HYDROGENHYDROGENUNITUNIT

SULFUR & AMINESULFUR & AMINEUNITUNIT

KERO/JETKERO/JET

DIESELDIESEL

SULFURSULFUR

SATURATEDSATURATEDGAS PLANTGAS PLANT

FG+LPGFG+LPG

SOUR WATERSOUR WATERSTRIPPERSTRIPPER

FUEL OILFUEL OIL

7 millions t/y7 millions t/y

GASIFICATIONGASIFICATION

SYNGASSYNGASCLEANINGCLEANING

COMBINED CYCLECOMBINED CYCLEPLANTPLANT

DAODAO

POWERPOWERSTEAMSTEAM

AIR AIR SEPARATIONSEPARATION

VACUUM VACUUM RESIDUERESIDUE

O2O2

Products SlateProducts Slate

Ni, V AshNi, V Ash

ASPHALTENESASPHALTENES

Main Ancillary Main Ancillary UnitsUnits

HCK ResidueHCK Residue

C3C3ii--C4 & nC4 & n--C4C4

Fuel Gas

COCO SHIFTSHIFT HYDROGENHYDROGEN

LT LT NAPHTHANAPHTHA

CCRCCR

AROMATICSAROMATICSCOMPLEXCOMPLEXReformateReformate

HV HV NAPHTHANAPHTHA

BENZENEBENZENEPARAXYLENEPARAXYLENE

PETROCHEM. PETROCHEM. NAPHTHANAPHTHARaffinateRaffinate

PROPANEPROPANE

BUTANESBUTANES

Heavy AromaticsHeavy Aromatics

H2 ProducersH2 Producers

H2 UsersH2 Users

17

Hydrogen Purification Options

The appropriate hydrogen separation technology is crucial

The three main hydrogen purification technologies available are: PSA pressure swing absorption

Small pressure drop across the PSA avoiding excessive recompression duty

Membrane selective permeation Operate under high pressure drop to deliver moderately pure hydrogen

Cryogenic separation (cold box) The refrigeration required for the process is obtained by Joule-Thomson effect

Base Configuration (Recovery Level = 0%)

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

6.4 t/d 2.3 t/d H2 Network

H2 Network257,264 Nm3/h

551 t/d

17.1 t/d 508.2 t/d

HGUHGUHGUHGUPSA CCRCCRCCRCCR AROMATICS AROMATICS COMPLEXCOMPLEX

AROMATICS AROMATICS COMPLEXCOMPLEX

ISOMAR TATORAY

157.1 t/d

PSACO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

CO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

H2 High Purity Network, 99.9% vol

PSA

242.0 t/d

FG Network

151.9 t/d 3.9 t/d 13.1 t/d

RFG Network

RFG Network

FG Network

11.3 t/d

58.7%vol.

33.1 t/d

53.3%vol.

3.1 t/d

67.8%vol.

0.2 t/d

16.1%vol.1.0 t/d

33.9%vol.

8.0 t/d

81.5%vol.H2

108.2 t/d

45.2 t/d

90.6%vol.Fractionator

Cold Sep.

(H2)70,937 Nm3/h

(H2)73,352 Nm3/h

18

Case 1: Direct use of HCK Cold Separator Off Gas(Recovery Level=23.8 %)

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

6.4 t/d 2.3 t/d H2 Network

H2 Network245,212 Nm3/h

525 t/d

17.1 t/d 508.2 t/d

HGUHGUHGUHGUPSA CCRCCRCCRCCR AROMATICS AROMATICS COMPLEXCOMPLEX

AROMATICS AROMATICS COMPLEXCOMPLEX

ISOMAR TATORAY

131.3 t/d

PSACO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

CO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

H2 High Purity Network, 99.9% vol

PSA

242.0 t/d

FG Network

151.9 t/d 3.9 t/d 13.1 t/d

RFG Network

RFG Network

FG Network

11.3 t/d

58.7%vol.

33.1 t/d

53.3%vol.

3.1 t/d

67.8%vol.

0.2 t/d

16.1%vol.1.0 t/d

33.9%vol.

8.0 t/d

81.5%vol.H2

82.4 t/d

19.4 t/d

90.6%vol.Fractionator

Cold Sep.

H2 Network

H2 Network

12,046 Nm3/h

26 t/dH2 Low Purity Network , 90.6% vol

25.8 t/d

90.6%vol.

(H2)70,937 Nm3/h

(H2)61,311 Nm3/h

19

20

Case 2: PSA Option(Recovery Level = 41.7%)

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

6.4 t/d 2.3 t/d H2 Network

H2 Network257,264 Nm3/h

551 t/d

17.1 t/d 508.2 t/d

HGUHGU

(H2)

55,204 Nm3/h

HGUHGU

(H2)

55,204 Nm3/h

PSA CCRCCRCCRCCR AROMATICS AROMATICS COMPLEXCOMPLEX

AROMATICS AROMATICS COMPLEXCOMPLEX

ISOMAR TATORAY

118.2 t/d

PSACO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

CO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

H2 High Purity Network, 99.9% vol

PSA

242.0 t/d

FG Network

151.9 t/d 3.9 t/d 13.1 t/d

RFG Network

RFG Network

FG Network

11.3 t/d

58.7%vol.

33.1 t/d

53.3%vol.

3.1 t/d

67.8%vol.

0.2 t/d

16.1%vol.1.0 t/d

33.9%vol.

8.0 t/d

81.5%vol.H2

63.0 t/d

6.3 t/d

57.6%vol.Fractionator

Cold Sep.

PSA

38.9 t/d

(H2)70,937 Nm3/h

21

Case 3: PSA combined with Membranes(Recovery Level = 65.8 %)

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

NAPHTHA NAPHTHA HDTHDT

HP Separator

24.1 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

KEROSENE KEROSENE HDTHDT

HP Separator

24.3 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

DIESEL DIESEL HDTHDT

HP Separator

58 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

HYDROCRACKERHYDROCRACKER

HP Separator

155 Barg

6.4 t/d 2.3 t/dH2

NetworkH2

Network245,212 Nm3/h

525 t/d

17.1 t/d 508.2 t/d

HGUHGU

(H2)

43,143 Nm3/h

HGUHGU

(H2)

43,143 Nm3/h

PSA CCRCCRCCRCCR AROMATICS AROMATICS COMPLEXCOMPLEX

AROMATICS AROMATICS COMPLEXCOMPLEX

ISOMAR TATORAY

92.4 t/d

PSACO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

CO SHIFTCO SHIFT

HT Reac.HT Reac.

(H2)

112,977 Nm3/h

H2 High Purity Network, 99.9% vol

PSA

242.0 t/d

FG Network

151.9 t/d 3.9 t/d 13.1 t/d

RFG Network

RFG Network

FG Network

11.3 t/d

58.7%vol.

3.1 t/d

67.8%vol.

0.2 t/d

16.1%vol.1.0 t/d

33.9%vol.

8.0 t/d

81.5%vol.H2

37 t/d

6.3 t/d

57.6%vol.Fractionator

Cold Sep.

H2 Network

H2 Network

12,046 Nm3/h

26 t/dH2 Low Purity Network , 90 % vol

PSA

25.8 t/d 38.9 t/d

(H2)70,937 Nm3/h

7.3 t/d

33.1 t/d

53.3%vol.

22

Impact of Lower Purity Hydrogen

As preliminary results, the licensor has confirmed that make-up H2 at lower purity (i.e. 90 % vol.) can be used to feed both Kero and Diesel HDT Units

On Diesel Unit the impacts are: At same pressure profile in the Reaction Loop, the catalyst volume shall be

increase of 10%.

At same catalyst volume, the reactor outlet pressure shall be increased of 7-8 bar.

On Kerosene Unit the impacts are quite minimal as the unit is smaller: At same pressure profile in the Reaction Loop, the catalyst volume shall be

increased of 4-5%

At same catalyst volume, the reactor outlet pressure shall be increased of 2-3 bar

Summary Overview

23

Hydrogen Economic Analysis(Cost factors)

H2 Production Factor =CAPEX HGU (Capacity)

Plant Life (years) * H2 recovered

H2 Recovery Factor =

H2 Factors [=] /(Nm3/h *year)

CAPEX HDTs (Pressure)Plant Life (years) * H2 recovered

+

+CAPEX H2 Recovery TechnologyPlant Life (years) * H2 recovered

+ H2 Compression Costs

+ OPEX HGU

CO2 Credits+

CO2 Credits+

The H2 network configurations are deeply analysed from the economical point of view by use of tailored cost factors :

24

+

+

25

HyNDT Economics ResultsThe Analysis, conducted for this specific client, has shown a

break even point, around 56% of overall H2 recovery

Beyond this recovery level the costs associated with the CAPEX and OPEX for the H2 recovery & purification technologies exceed the generation costs CAPEX ESCALATION

2.755.50

19.46

0

5

10

15

20

25

CASE 1 CASE 2 CASE 3

M

M

E

u

r

o

CAPEX

PAY OUT TIME

1.92.5

5.3

0.0

1.0

2.0

3.0

4.0

5.0

6.0

CASE 1 CASE 2 CASE 3

Y

E

A

R

S

POT

H2 RECOVERY TRENDS

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

0 20 40 60 80

% of H2 Recovery

E

u

r

o

/

Y

e

a

r

H2 Production CostsH2 Recovery Costs

Recovery of H2 favourable Production of H2 favourable

26

Conclusions

The methodological approach to the Hydrogen analysis is strongly depended by the project typology & environment constraints

It is necessary for each project & client environment to re-evaluate the H2 economics factors in light of any specific constraints

The Technips HyNDT is a flexible tool to optimize new or existing H2 network with practical solutions allowing to define a roadmap for the refinery investments