07-0-ra-4804-0001 - corrosion control manual - to goa · shell canada energy, chevron canada...

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Heavy Oil

Controlled Document

Quest CCS Project

Corrosion Control Manual (Preliminary)

Project Quest CCS Project

Document Title Corrosion Control Manual (Preliminary)

Document Number 07-0-RA-4804-0001

Document Revision 00

Document Status Preliminary (For GoA)

Document Type RA4804-Corrosion Manual

Control ID

Owner / Author

Issue Date 2013-01-22

Expiry Date None

ECCN EAR 99

Security Classification

Disclosure None

Revision History shown on next page

SURE document number - 2 - Security classification listed here

2

Quest Carbon Capture and Sequestering (CCS) Project

Corrosion Control Manual

Preliminary


3

TABLE OF CONTENTS

Page 1 SUMMARY ............................................................................................................................................ 4

2 INTRODUCTION .................................................................................................................................. 4

3 MATERIALS SELECTION BASIS ........................................................................................................... 4

3.1. PROCESS CONDITIONS ............................................................................................................. 5

3.2. APPLICABLE DOCUMENTS AND STANDARDS ........................................................................ 5

3.3. MATERIALS OF CONSTRUCTION .............................................................................................. 6

3.4. PIPING .......................................................................................................................................... 6

3.5. PUMPS .......................................................................................................................................... 6

4 CORROSION DEGRADATION LOOPS ........................................................................................... 7

4.1 CORROSION DEGRADATION LOOP # 1 (CC-01 – SYNGAS ABSORPTION) ..................... 8

4.2 CORROSION DEGRADATION CIRCUIT CC#02- WATER WASH ........................................ 13

4.3 CORROSION DEGRADATION CIRCUIT CC#02A – WASH WATER MAKE-UP ............. 17

4.4 CORROSION DEGRADATION CIRCUIT CC#03 - RICH AMINE SECTION ....................... 20

4.5 CORROSION DEGRADATION CIRCUIT CC#04 - HOT RICH AMINE SECTION .............. 24

4.6 CORROSION DEGRADATION CIRCUIT CC#05 – HOT LEAN AMINE SECTION ............ 28

4.7 CORROSION DEGRADATION CIRCUIT CC#06 – WARM AMINE SECTION ................ 31

4.8 CORROSION DEGRADATION CIRCUIT CC#07 - FILTERING SECTION .............................. 35

4.9 CORROSION DEGRADATION CIRCUIT CC # 08 - AMINE REFLUX SECTION ................... 39


4

1 SUMMARY This document describes the corrosion mechanisms prevailing in the process path of Quest CCS plant. 2 INTRODUCTION The purpose of the Quest CCS Project is to capture, compress and store about 1.08 million tones of CO2 per year from the Shell Canada Scotford Upgrader. The Amine Unit for AOSP CO2 capture project is designed to remove 80% CO2 from three HMU (Hydrogen Manufacturing Unit) syngas streams. The amine absorption section is designed to treat three separate gas streams from the three Hydrogen Manufacturing Units in three separate amine absorbers (C-1, C-2 and C-3). The feed gases to the three absorbers are first treated with lean amine in their respective amine absorbers for CO2 removal. This design is based on ADIP-X solvent composition of 40 wt% MDEA, 5 wt% DEDA and 55 wt% water. The ADIP-X process used in this Amine Unit is a regenerative amine based process where CO2 is removed from the gas stream at relatively high pressure and low temperature with a mixture of water and amine(s). The ADIP-X process is an accelerated MDEA process using piperazine (DEDA) to enhance the CO2 absorption over that achievable with non-accelerated MDEA. The absorbed acid gases are removed from the amine solution in the Amine Stripper of the amine regeneration section at low pressure and high temperature. 3 MATERIALS SELECTION BASIS Materials and corrosion allowances for this project are selected on the basis of anticipated corrosion rates under the maximum operating parameters. The stream conditions are described in the Materials Selection Diagrams:

· MSD 241.0051.000.059.005 Rev. 0A

· MSD 242.0051.000.059.006 Rev. 0A

· MSD 246.0051.000.059.001 Rev. 0A

· MSD 246.0051.000.059.002 Rev. 0A

· MSD 246.0051.000.059.003 Rev. 0A

· MSD 246.0051.000.059.004 Rev. 0A

· MSD 441.0051.000.059.005 Rev. 0A

absorbers are first treated with lean amine in their respective amine absorbers for COoval. This design is based on ADIP-X solvent composition of 40 wt% MDEA, 5 wt% DEDA removal. This design is based on ADIP-X solvent composition of 40 wt% MDEA, 5 wt% DEDA

and 55 wt% water.


5

Detailed water analysis is not available. In most cases, carbon steel is not the appropriate materials as the corrosion is very severe:

- Predicted corrosion rates for carbon steels in areas not wetted with amine from deWaard CO2 corrosion model is 18 mm/y (contribution by CO to corrosion in the amine treating unit temperature range, below 120°C, has not been reported in the literature, hence not considered in this manual for simplicity).

- High pH amines might reduce CS corrosion to a much lower level, about 0.5 to 1 mm/y

- Stainless steels reduce corrosion rate to an acceptable level in the presence or absence of amine

Table 3.1: Summary of Field Conditions

Type of Service Hydrogen Syngas Gas

H2S Content 0 ppm

CO2 Content 16.5 to 17.1%

CO content 2.4% to 2.9%

Cl- Content 0 ppm

3.1. PROCESS CONDITIONS Syngas streams from HMU 1, HMU 2 and HMU3, respectively, are sent to corresponding Amine Absorbers to remove up to 80% of the CO2 content. 3.2. APPLICABLE DOCUMENTS AND STANDARDS Process Flow Diagrams SR.11.10343 MSD diagrams: - SR.11.10343, Quest CO2 Capture

Project-Amine Unit, Basic Design Package

- OP.99.20651, Materials Selection for Amine Units

Material Requirement for Piping: - SR.11.10343, Quest CO2 Capture Project-Amine Unit, Basic Design Package

- OP.99.20651, Materials Selection for Amine Units


6

3.3. MATERIALS OF CONSTRUCTION

Predicted CO2 corrosion for carbon steels would have been so severe that all (or most) vessels are to be fabricated from stainless steels or clad with stainless steels. Please refer to Appendices A to H for Materials Selection Diagrams. 3.4. PIPING

For above ground piping, stainless steel piping is recommended for most locations because of the severity of corrosion. Carbon steel piping is recommended for some less corrosive locations. All piping is externally bare. 3.5. PUMPS

Stainless steel is recommended for all pump casings and impellers.


7

4 CORROSION DEGRADATION LOOPS Corrosion loops for the Quest Carbon Capture and Sequestering (CCS) Project – Amine Plant is illustrated as block diagram in Figure 1.


8

4.1 CORROSION DEGRADATION LOOP # 1 (CC-01 – SYNGAS ABSORPTION) 4.1.1 PROCESS DESCRIPTION Feed hydrogen gas (containing up to 16.5%, 16.5%, and 17.1% CO2) from HMU 1, 2 and 3, respectively, enters the absorbers C1, C2, and C3 at trays 1 and flow upward countercurrent to lean amine downward flow. The lean amine absorbs the acid gas, CO2 mainly, and leaves the absorber hotter. From a safety viewpoint, this circuit (and circuit CC- 02A below) is very critical. Any failure (pinhole leak or rupture) might present a hydrogen-laden atmosphere with a potential explosion of extreme consequences. Table 4.1.1: Circuit Process Conditions Parameter Typical Range Drawings 241.0051.000.059.005 Rev.0A

242.0051.000.059.006 Rev.0A 441.0051.000.059.005 Rev.0A

Line/Equipment Absorbers C1, C2 or C3 H2S Content 0

CO2 Content 16.5% to 17.1 mole %

CO content 2.4% to 2.9 mole %

Cl- Content 0

Organic Acids N/A

Water 0.18%

Condensate (>C5+) None

Raw Gas Hydrogen syngas from HMU 1 to 3

Temperature 35°C feed gas, 30°C lean amine, 64°C rich amine outlet, >64°C temperature bulge at tray #7

Pressure 3057 to 3097 kPa

Designed acid gas loading 0.5 mol/mol

Actual acid gas loading Not to exceed 0.6 mol/mol

NOTES:

0.5

eed 0.6

feed gas, 30°C lean amine, 64°Camine outlet, >64°C


9

Increased actual acid gas loading (apparent gas loading affected by heat stable amine salt level, amine strength, etc.) and 2-phase flow (gas breakout in liquid lines) can increase corrosion rate even for stainless steels

4.1.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No.

Description Materials Comments

C-1 (V-24118)

Amine Absorber # 1

Shell: CS/ SS Clad internals: SS

Severe corrosion for CS based on Calgary Research Centre lab tests and field experience

C-2 (V-24218)

Amine Absorber # 2


C-3 (V-44118)

Amine Absorber # 3


4.1.3 INJECTION AND MIX POINTS/DEAD LEGS It is recommended that antifoam agents be injected at the top of the absorbers or at the top of the stripper if flooding is severe (Reference SR.11.10343) 4.1.4 SAMPLE POINTS

- Absorber feed gas lines

- Upstream of level control valves from individual absorbers

- Off-gas for each absorber:

· Sample ahead of bypass / block valves

· Sample downstream of bypass / block valves

4.1.5 DETERIORATION MODES The failure modes for the respective corrosion mechanisms anticipated or experienced

in this Circuit and their likelihood of occurring are listed below:

1. Possible but unlikely within this Circuit;

2. Likely, if right conditions are met; and,

3. Likely under current operating conditions.


10

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD

NOTES Non-

Mitigated Mitigated

CO2 Corrosion All vessels

and piping 2 1 More severe if :

- absorber is operated at

higher acid gas

loading,

- amine strength is too

low or too high; in

areas where amine is

not present (vapor

phase pockets)

- heat stable amine salt

ties up amine

molecules, and,

- solids are not properly

removed by filtration

Amine Corrosion All equipment

in contact

with amine

solution

2 1 Similar to CO2 corrosion

but at a reduced magnitude

due to the inherent high pH

nature of amine solution

Amine Stress

Corrosion

Cracking

1 1 Unlikely if the materials are

SS or PWHT carbon steels

(see API 571 Paragraph

5.1.2.2.1)

Under-deposit corrosion

Absorber trays

2 1

Erosion due to impingement by

solids and/or gas breakout

Piping elbow, bends, etc. where fluid velocity is

high

2 1


11

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD

NOTES Non-

Mitigated Mitigated

Galvanic Corrosion

Inlet to the absorber

2 1 Where dissimilar metals are joined, such as stainless steel piping to CS vessel below the SS cladding

CO/CO2 Stress Corrosion Cracking

2 1 Maximum CO /CO2 partial pressures are 0.87/5.1 bars, respectively

Chloride Stress Corrosion Cracking

1 1 Only possible when there is an upset in the methane-steam reformer units (HMU) upstream which introduces Cl- carryover

4.1.6 OPERATING ENVELOPES

PARAMETER TARGET MIN/MAX CRITICALITY REASONS/CAUSES/ACTIONS

Temperature at Absorber

outlet

64°C 60°C/70°C High Lower temperature = lower efficiency ; higher temperature increases corrosion

Pressure 3097 kPa Low To maintain stable operations Actual acid gas loading

0.5 mol/mol Max 0.6 mol/mol

High Increased corrosion

Solids loading To be determined

based on filter change

frequency

Medium Solids increase risks of gas breakout

Amine circulation

rate

To be determined

Medium To be reviewed to optimize efficiency and corrosion based on:

- amine strength - acid gas loading - solids loading (filtration

results) - volume of syngas to be

treated, etc.

64° 60°C/70°C

0.5 mol/mol Max 0.6


12

- flow velocity and flow regime (single or 2-phase)

4.1.7 ON-LINE CORROSION MONITORING

LOCATION TOOL OR METHOD PURPOSE

Not required at this time

4.1.8 SPECIAL INSPECTION CONSIDERATIONS – EQUIPMENT (IN ADDITION TO API

510/573 AND 653)

ITEM LOCATION DESCRIPTION (E.G. Purpose,

Frequency, ETC.)

Localized corrosion

C1, C2, C3 Check (UT, RT) bottom part of vessels for localized corrosion (pits) during shut down

Water condensation in un-wetted areas

Cold spots where condensation may occur in tight spots where amine is not present to increase pH and lower corrosion rates (e.g. trays welded to vessel wall)

Check with UT/RT during shut down. SS reduces corrosion to a low (but not zero) magnitude

Erosion Areas of high turbulence where protective scale may be removed such as elbows, bends, inlet and outlet of C1, C2, C3

Check with UT/RT during shut down.

4.1.9 STARTUP AND SHUTDOWN CONSIDERATIONS

EQUIPMENT CONCERN PROCEDURES AND REFERENCES

Absorbers and piping

Ambient Temperature is lower than -29°C

Minimum design metal temperature = -29°C and equipment can fail due to brittle fracture; cannot start up or operate below 0°C due to water freezing

4.1.10 FINDINGS AND RECOMMENDED ACTIONS


13

- To be updated with operational data and experiences - Correlate filter frequency change with corrosion inspection data 4.2 CORROSION DEGRADATION CIRCUIT CC#02- WATER WASH

4.2.1 PROCESS DESCRIPTION Treated gas from absorbers is water washed to reduce amine carry over to less than 1

ppmw and to cool down to the same temperature as the raw gas.

Treated gas from the absorbers, C1/ C2/ C3 enters the water wash vessels V-1, V-2, V3, respectively, at trays 1 and exits at the top sections. Wash water is circulating from trays 6 to bottom of vessel by pumps P4 A/B, P5 A/B, P6 A/B, respectively through water coolers, E1, E2, E3, respectively. A portion of the circulating water is removed by level control valves to waste water disposal facilities. For HMU 3 only, the waste water goes through a Purge Water Flash Drum V-44115 (not covered in this loop) to remove residual gas before being sent to waste water disposal facilities. Make up water is added at trays 9 in the water wash vessels to remove residual amine and

to cool down the treated gas to 35°C, the same as in the raw syngas. The make-up water

line is covered in the next Corrosion Degradation Loop, CC # 02A.

From a safety viewpoint, this circuit (and circuit CC- 01 above) is very critical. Any failure (pinhole leak or rupture) might present a hydrogen-laden atmosphere with a potential explosion of extreme consequences.

Table 4.2.1: Circuit Process Conditions Parameter Typical Range Drawings 241.0051.000.059.005 Rev. 0A

242.0051.000.059.006 Rev. 0A 441.0051.000.059.005 Rev. 0A

Line/Equipment Water wash towers, V-1, V2, V3 H2S Content 0

CO2 Content 3.4%

CO Content 2.8%

Cl- Content 0 ppm

Organic Acids N/A

down the treated gas to 35°C


14

Water Saturated

Condensate (>C5+) 0

Feed Gas Treated gas from Absorbers C1, C2 and C3

Temperature 39°C in all absorbers

Pressure 3014 kPa to 3054 kPa

NOTE CO is not absorbed by amine. 4.2.2 REASONS FOR MATERIALS OF CONSTRUCTION

Equipment No.


E-1 (E-24129)

Absorber # 1 Circulating Water Cooler

Shell: CS/ SS Clad Channel: CS Tubes: SS

E-2 (E-24229)



E-3 (E-44129)



V-1 (V-24119)

Absorber # 1 Wash Water Tower


V-2 (V-24219)



V-3 (V-44119)



4.2.3 INJECTION AND MIX POINTS/DEAD LEGS Make up water is injected at Trays 9 for all 3 water wash vessels. 4.2.4 SAMPLE POINT Re-circulating wash water lines.

39°


15


in this Circuit and their likelihood of occurring are listed below: 1. Possible but unlikely within this Circuit; 2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION

MECHANISM AREAS AFFECTED

LIKELIHOOD

NOTES Non-

Mitigated Mitigated

CO2 Corrosion All equipment 2 1 Unabsorbed CO2

without the benefit of

high pH provided by

the amine

Amine Corrosion All equipment in

contact with amine

solution

2 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution


Wash water Vessel trays

2 1

Erosion due to impingement by solids

Piping elbow, bends, etc. where fluid velocity is high

2 1

Galvanic Corrosion

Dissimilar metals are joined

2 1 Where dissimilar metals are joined, such as stainless steels next to carbon steels

Flow Induced Corrosion

Turbulence created when a fluid flows over a surface breaking anomaly (such as welds)

2 1


16

DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated

Corrosion Fatigue 2 1 Piping subjected to vibration is susceptible to cracking

4.2.6 OPERATING ENVELOPES PARAMETER TARGET MIN/MAX CRITICALITY REASONS/CAUSES/ACTIONS

Temp 39°C 38-40°C Low Treated gas to wash water vessel

Pressure 3014 to

3054 kPa Low Operational Stability



None

4.2.8 SPECIAL INSPECTION CONSIDERATIONS – EQUIPMENT (IN ADDITION TO API 510/573 AND 653)

ITEM LOCATION DESCRIPTION (E.G. Purpose, Frequency,

ETC.)

Localized corrosion

V1, V2, V3 Check (UT, RT) bottom part of vessels for localized corrosion (pits)

Water condensation

Cold spots where condensation may occur in tight spots where amine is not present to increase pH and lower corrosion rates

Check with UT/RT

39° 38-40°


17


ETC.)

Erosion Areas of high turbulence where protective scale may be removed such as elbows, bends, inlet and outlet of V1, V2, V3

Check with UT/RT



Water wash vessels and piping



4.2.10 FINDINGS AND RECOMMENDED ACTIONS To be updated with operational data and experiences.

4.3 CORROSION DEGRADATION CIRCUIT CC#02A – WASH WATER MAKE-UP

4.3.1 PROCESS DESCRIPTION Condensate from the outlet of Condensate Cooler E-24507 is added at trays 9 in the water

wash vessels as make-up water. The make-up water flows by gravity to water wash vessel

V3 and through pumps P-24609A/B (Pumps not covered in this circuit) before being split to

water vessels V1 and V2.

Table 4.3.1: Circuit Process Conditions Parameter Typical Range Drawings 246.0051.000.059.004 Rev. 0A Line/Equipment Piping only H2S Content 0

CO2 Content 0


18

Oxygen Content 0

Cl- Content 0 ppm

Organic Acids N/A

Water 100%

Condensate (>C5+) 0

Feed Gas None

Temperature 35°C

Pressure 3014 kPa to 3054 kPa

NOTE Traditionally, this line should be addressed in the Utilities Manual. However, the consequence of failure of this line is very high. As each of the 3 water wash vessels requires 4.5, 4.5 and 6.6 m3/hr of make-up water, respectively, on a continuous basis, the disruption of the make-up water line can stop all water washing activities. 4.3.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No.


Piping From outlet of Condensate Cooler E-24507 to water wash vessels V1, V2 and V3, respectively

Carbon steels with 1.5 mm corrosion allowance, not PWHT

Low corrosion if CO2 is effectively removed from Utilities steam generation (?)

4.3.3 INJECTION AND MIX POINTS/DEAD LEGS pH conditioning (by caustic?) to Recovered Clean Condensate Tank TK-25101 4.3.4 SAMPLE POINT For alkalinity and oxygen levels of condensates from bottom of Condensate Flash Drum V-24507.

4.3.5 DETERIORATION MODES

35°


19

The failure modes for the respective corrosion mechanisms anticipated or experienced in this Circuit and their likelihood of occurring are listed below:

1. Possible but unlikely within this Circuit; 2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated

CO2 corrosion CS Piping 2 1 Residual CO2 in

condensates

Oxygen Corrosion CS Piping 1 1 Residual O2 in

condensates

Galvanic Corrosion





2 1


4.3.6 OPERATING ENVELOPES PARAMETER TARGET MIN/MAX CRITICALITY REASONS/CAUSES/ACTIONS

Temp 35°C 30-40°C Low Operational Stability

Pressure 3014 kPa

3054 kPa (HMU #3) Low Operational Stability


35° 30-40°


20


None


ITEM LOCATION DESCRIPTION (e.g. Purpose,

Frequency, ETC.)

Localized corrosion

Piping Check (UT, RT) for localized corrosion (pits)

Erosion

Areas of high turbulence where protective scale may be removed such as elbows, bends, inlet to V1, V2, V3

Check with UT/RT



Make-up water piping



4.3.10 FINDINGS AND RECOMMENDED ACTIONS To be updated with operational data and experiences. 4.4 CORROSION DEGRADATION CIRCUIT CC#03 - RICH AMINE SECTION 4.4.1 PROCESS DESCRIPTION Rich amines flow out of the three absorbers C-1, C-2, and C3, respectively, via level- controlled valves to a common piping to the lean/rich plate exchanger E4.


21

Table 4.4.1: Circuit Process Conditions Parameter Typical Range Drawing 246.0051.000.059.001 Line/Equipment Lean/Rich Plate Exchanger E4 H2S Content 0

CO2 Content 99+% (in gas composition)

Cl- Content 0 except from upsets

Organic Acids Not available

Water 55 wt%

Condensate (>C5+) 0

Raw Gas CO2

Temperature 106°C

Pressure 2452 kPa

NOTE 4.4.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No. Description Materials Comments E-4 (E-24602 A/B)

Lean/Rich Amine Exchangers

SS Plates and EPDM Gaskets

Piping SS 4.4.3 INJECTION AND MIX POINTS/DEAD LEGS None 4.4.4 SAMPLE POINT None 4.4.5 DETERIORATION MODES The failure modes for the respective corrosion mechanisms anticipated or experienced

in this Circuit and their likelihood of occurring are listed below: 1. Possible but unlikely within this Circuit;

106°


22

2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated

CO2 corrosion All equipment 2 1 Gas breakout will

increase corrosion

severity


contact with amine

solution

2 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution

Amine Stress

Corrosion

Cracking

All equipment in

contact with amine

solution

2 1 Unlikely if the

materials are SS or

PWHT carbon steels

(see API 571 Para

5.1.2.2.1)

Erosion due to impingement by solids and/or gas breakout


2 1 After the pressure letdown valve, CO2 might break out

Galvanic Corrosion

2 1 Where dissimilar metals are joined, such as stainless steels welded or flanged to carbon steels



2 1


23

DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated



Plates in exchangers 2 1



Temp 64°C TBD High Leaving absorbers Temp (rich

amine outlet from E4)

106°C TBD High Higher T increases gas breakout tendency

Pressure 3057 kPa TBD High Delta P across valves dictates gas breakout tendency

Actual acid gas loading

0.5 mol/mol

TBD High Actual acid gas loading can be much higher than calculated value, resulting in more severe corrosion.

Solid Loadings

TBD TBD High

Unfiltered solids can plug plate exchanger, increase rich outlet temperature and increase gas breakout tendency

Heat Stable amine salts

TBD TBD Medium Increases actual gas loading

TBD: to be determined as they are inter-related



None required


64°

106°

0.5


24


ETC.)

Erosion Areas of high turbulence where protective scale may be removed such as elbows, bends, inlet and outlet of V1, V2, V3

Check with UT/RT



All vessels and piping



4.5 CORROSION DEGRADATION CIRCUIT CC#04 - HOT RICH AMINE SECTION

4.5.1 PROCESS DESCRIPTION

The combined rich amine stream first passes through the Lean / Rich Amine Exchanger E4 where it is heated by hot lean amine coming from the bottom of the Amine stripper. The rich amine from the heat exchanger is heated at 106°C and de-pressurized from 2752 kPa (a) to 162 kPa (a) through a pressure control valve located upstream of the stripper column. The hot rich amine enters the stripper at above tray 20 and flow downward to Tray 1. Hot steam (from the re-boiler E6 A/B) flows upward below tray 1 to heat up the rich amine to strip off the CO2 from the amine solutions. This degradation circuit covers the middle section of the stripper, from tray 1 to tray 20.

Table 4.5.1: Circuit Process Conditions Parameter Typical Range Drawing 246.0051.000.059.001 Rev. 0A Line/Equipment Amine stripper (Tray 1 to 20) H2S Content 0

it is heated by hot lean amine coming from the bottom of the Amine stripper. The rich amine from the heat exchanger is heated at 106°C and de-pressurized from 2752 kPa (a) to


25

CO2 Content,% 99+%

Cl- Content 0

Organic Acids N/A

Water 55 wt%

Condensate (>C5+) 0

Raw Gas Acid gas (CO2)

Temperature 83C

Pressure 172 kPa (g)

NOTE If solids have not been adequately removed by filtration (degradation loop # 6), CO2 gas breakout might begin in the piping downstream of the Lean/Rich Exchanger E-4. Two-phase flow results in increased liquid velocity and also potential cavitations due repeated bubble formation/collapse. Erosion corrosion can happen even when the liquid velocity was calculated to be within the limit for single phase flow. 4.5.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No. Description Materials Comments C-4 (V-24601)

Amine Stripper Shell: CS (PWHT) / SS Clad internals: SS

E-5 (E-24601A/B)

Stripper OVHD Condenser

Shell: SS Channel: CS Tubes: SS

E-6 A/B (E-24603A/B)

Stripper Reboiler Shell: CS/ SS Clad internals: SS

V-4 (V-24602)

Reflux Drum Shell: SS internals: SS

4.5.3 INJECTION AND MIX POINTS/DEAD LEGS Antifoam agents might be injected if flooding is severe in the stripper. 4.5.4 SAMPLE POINT None

83C


26



DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES

Non-Mitigated Mitigated

CO2 corrosion All equipment 2 1 Gas breakout will

increase corrosion

severity


contact with

amine solution

2 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution

Amine Stress

Corrosion

Cracking

1 1 Unlikely if the

materials are SS or

PWHT carbon steels

(see API 571 Para

5.1.2.2.1)

Erosion due to impingement by solids and/or gas break out


2 1 Severity depends on filtering efficiency

Galvanic Corrosion




27

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES




2 1


External Corrosion Under Insulation

Insulated piping/vessels

1 1 Not insulated


Stripper trays 2 1



Temp (rich amine outlet

from E4)

106°C TBD High Higher T increases gas breakout tendency

Pressure 3057 kPa TBD High Delta P across valves dictates gas breakout tendency

Actual acid gas loading

0.6 mol/mol

TBD High Actual acid gas loading can be much higher than calculated value, resulting in more severe corrosion.

Solid Loadings

TBD High Unfiltered solids can plug plate exchanger, increase rich outlet temperature and increase gas breakout tendency

Heat Stable amine salts

TBD TBD Medium Increases actual gas loading

TBD: to be determined as they are inter-related


106°

0.6


28


None


ITEM LOCATION DESCRIPTION (E.G. Purpose,

Frequency, ETC.)

Erosion Areas of high turbulence where protective scale may be removed such as elbows, bends, etc.

Check with UT/RT during shut down

Pitting Beneath sludge deposits on trays

Check with UT/RT during shut down



All vessels and Piping



4.6 CORROSION DEGRADATION CIRCUIT CC#05 – HOT LEAN AMINE SECTION 4.6.1 PROCESS DESCRIPTION Lean Amine from the bottom of Amine stripper C-4 through Amine stripper re-boiler E6 A/B back to the Amine stripper (vapor and liquid lines). Lean Amine from stripper C-4 to Lean/Rich Amine exchanger E-4 is also included. The bottom of Amine stripper C-4 below tray 1, Amine stripper re-boiler E6 A/B and the lean plate side of the plate Lean/Rich Exchanger E-4 are all included in this circuit.

Table 4.6.1: Circuit Process Conditions


29

Parameter Typical Range Drawing 246.0051.000.059.001 Rev. 0A Line/Equipment Lean/Rich Amine Exchanger, Amine coolers and

Trim coolers, Amine stripper re-boilers H2S Content 0

CO2 Content 0.03 mol/mol loading

Cl- Content 0

Organic Acids N/A

Water 55%

Condensate (>C5+) 0

Raw Gas Acid gas

Temperature 119°C


NOTE While CO2 partial pressure is low, the high temperature in this circuit depresses the pH and there might be pockets of equipment free of amine. Without the benefits of amine, corrosion might be high. High turbulence, especially in the Re-boiler can cause severe corrosion 4.6.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No. Description Materials Comments E-7 A/B (E-24604 A/B)

Lean Amine Cooler

Shell: SS; Channel: CS; Tubes: SS

E-8 A/B (E-24605 A/B)

Lean Amine Trim Cooler

SS plates and EPDM Gaskets

(Titanium plates?)

4.6.3 INJECTION AND MIX POINTS/DEAD LEGS None

4.6.4 SUGGESTED SAMPLE POINTS: None 4.6.5 DETERIORATION MODES The failure modes for the respective corrosion mechanisms anticipated or experienced

in this Circuit and their likelihood of occurring are listed below:

119°

0.03 mol/mol loading


30

1. Possible but unlikely within this Circuit; 2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES


CO2 Corrosion All vessels and

piping 2 1 Gas breakout will

increase corrosion

severity

Amine Corrosion All equipment

in contact with

amine solution

2 1 Similar to CO2

corrosion but at a

reduced magnitude due

to the inherent high pH

nature of amine solution

Amine Stress

Corrosion

Cracking

1 1 Unlikely if the materials

are SS or PWHT carbon

steels (see API 571

Paragraph 5.1.2.2.1)


Exchanger plates

2 1

Erosion due to impingement by solids and gas break out


2 1

Galvanic Corrosion





2 1


31



Temp 119°C TBD High Pressure 1309 KPa TBD High

TBD: To be determined from many factors (see section 4.5.6) 4.6.7 ON-LINE CORROSION MONITORING


None



ETC.)


Check with UT/RT



Stripper and piping

Brittle fracture Minimum design metal temperature = -29°C and equipment can fail due to brittle fracture; cannot start up or operate below 0°C due to water freezing

4.7 CORROSION DEGRADATION CIRCUIT CC#06 – WARM AMINE SECTION 4.7.1 PROCESS DESCRIPTION

119°


32

A slip stream lean amine from Lean/Rich heat exchanger outlet, E-4 is circulated through Lean Amine cooler E7 A/B, and Amine Trim cooler E8 A/B to the Filtration section.

Table 4.7.1: Circuit Process Conditions Parameter Typical Range Drawing 246.0051.000.059.001 Rev. 0A Line/Equipment Lean Amine Cooler, Lean Amine Trim Cooler H2S Content 0

CO2 Content 0.03 mol/mol loading

Cl- Content N/A

Organic Acids Unknown

Water 55%

Condensate (>C5+) 0

Raw Gas Acid gas

Temperature 78°C


Heat stable amine salts Unknown but could be significant and increasing with time if solution is not reclaimed

Solids loading Unknown but could be significant and increasing with time if solution is not properly filtered

NOTE In this circuit, CO2 partial pressure is low but due to relatively still high temperature and the possible presence of heat stable amine salts and solids, corrosion can still be severe. 4.7.2 REASONS FOR MATERIALS OF CONSTRUCTION Equipment No.


E-7 A/B Lean Amine Cooler


Severe CO2 corrosion due to turbulence and lack of protective scale lead to SS steel shell and tubes design, Channel sees less turbulence, hence CS can be

78°

0.03


33

used E-8 A/B Lean Amine

Trim Cooler SS plates and EPDM Gaskets

(Titanium plates?)

4.7.3 INJECTION AND MIX POINTS/DEAD LEGS

None

4.7.4 SAMPLE POINTS

· Upstream of Lean Amine Charge Pumps · Upstream of Lean / Rich Amine Exchanger



DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated

External Corrosion Under coating 1 1 Not insulated

CO2 Corrosion All 2 1 More severe if

organic acids, heat

stable amine salts

are present


contact with amine

solution

2 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution


34

DEGRADATION


LIKELIHOOD

NOTES Non-

Mitigated Mitigated

Amine Stress

Corrosion

Cracking

1 1 Unlikely if the

materials are SS or

PWHT carbon steels

(see API 571

Paragraph

5.1.2.2.1)


Low spots 2 1

Erosion due to impingement by solids and gas break out


2 1

Galvanic Corrosion





2 1




PARAMETER TARGET MIN/MAX CRITICALITY

REASONS/ CAUSES/

ACTIONS

Temp at L/R Exchanger Outlet

78°C Low 78°


35

Pressure 1109 KPa Low



None



ETC.)

Erosion

Areas of high turbulence where protective scale may be removed such as elbows, bends, etc.

Check with UT/RT



All vessels and Piping Ambient Temperature is

lower than -29°C


4.8 CORROSION DEGRADATION CIRCUIT CC#07 - FILTERING SECTION 4.8.1 PROCESS DESCRIPTION The cooled lean amine is treated in the filtration section before it is returned to the amine absorbers. The filtration section consists of one main particulate filter (Lean Amine Filter, F-1) followed by a slipstream Lean Amine Carbon Filter (D-1) and its after-particulate filter (Lean Amine Post Filter, F-2). The main particulate filter is sized for 25% of the lean amine flow whereas the, carbon filter is sized for approximately 5% of the lean amine flow. The filtered lean

-1) and its after-particulate filter (Lean Amine Post Filter, F-2). The main particulate filter is sized for 25% of the lean amine flow whereas the, carbon filter is sized for approximately 5% of the lean amine flow. The filtered lean


36

amine is finally pumped back to the amine absorbers by lean amine charge pump (P-3 A/B). The flow of amine to the amine absorbers is under flow control.

Table 4.8.1: Circuit Process Conditions Parameter Typical Range Drawing 246.0051.000.059.001 Rev. 0A Line/Equipment Lean amine cooler intlet H2S Content 0

CO2 Content 0.03 mol/mol

Cl- Content 0


Water 55%

Condensate (>C5+) 0

Raw Gas Residual acid gas

Temperature 78C


NOTE 4.8.2 REASONS FOR MATERIALS OF CONSTRUCTION

Equipment No.


E-7 A/B Lean Amine Cooler


Severe CO2 corrosion for CS

E-8 A/B Lean Amine Trim Cooler

Titanium plates and EPDM Gaskets

D-1 Lean Amine carbon filter



78C

0.03 mol/mol


37

4.8.4 SUGGESTED SAMPLE POINTS Water content of the amine can be determined by Karl Fischer analysis and should be checked at regular intervals. If the percent weight of amine in the solution is being monitored daily, the water content check by Karl Fischer can be performed two or three times a week. Otherwise, the water content should be checked at least once per day. It is recommended that water content be measured by each shift. 4.8.5 DETERIORATION MODES The failure modes for the respective corrosion mechanisms anticipated or experienced in this Circuit and their likelihood of occurring are listed below: 1. Possible but unlikely within this Circuit; 2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES



piping 2 1 For water wet

locations


contact with

amine solution or

with amine carry-

over

2 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution

Amine Stress

Corrosion

Cracking

1 1 Unlikely if the

materials are SS or

PWHT carbon steels

(see API 571

Paragraph

5.1.2.2.1)


Low velocity area 2 1


38

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES


Erosion due to impingement by solids and gas breakout


2 1

Galvanic Corrosion





2 1





Temp at outlet of trim cooler E-8

30°C Low Operational stability

Pressure 816 KPa Low Operational stability



None

30°


39



ETC.)

Localized corrosion

All Check (UT, RT) bottom part of vessels/piping for localized corrosion (pits)

Water condensation

Cold spots where condensation may occur in tight spots where amine is not present to increase pH and lower corrosion rates

Check with UT/RT


Check with UT/RT



All vessels and Piping

Brittle fracture Minimum design metal temperature = -29°C and equipment can fail due to brittle fracture; cannot start up or operate below 0°C due to water freezing

4.9 CORROSION DEGRADATION CIRCUIT CC # 08 - AMINE REFLUX SECTION

4.9.1 PROCESS DESCRIPTION Stripped acid gas leaves the top of the Amine Stripper C-4 is cooled in the Stripper overhead condenser E-5 to the Reflux Drum V-4 and to the CO2 compression unit. Condensing water with carried-over amine returns to Stripper C-4 above tray 24

Table 4.9.1: Circuit Process Conditions

Parameter Typical Range Drawing 246.0051.000.059.001 Rev. 0A Line/Equipment Stripper Reflux Drum


40

H2S Content 0

CO2 Content 99.9 mole %

Cl- Content 0 ppm


Water vapor 0.028 mole %

Condensate (>C5+) 0

Raw Gas Stripper overhead gas

Temperature 36C


NOTE

The stripped dry gas, containing mainly CO2, minor water vapour but no liquid water, should not be corrosive.

- Calculated equilibrium water vapour from steam table at 36°C is 0.0595 bars = 6 kPa (a)

- Calculated water vapour pressure at Reflux Drum gas outlet = 0.028 x 244 kPa(a) = 0.068 kPa (a)

- Gas stream is therefore dry, not corrosive However, upset in the operations might allow liquid water to be carried over. Depending on the water wetting on the CO2 phase, corrosion could be severe downstream of this unit as the benefits of high pH provided by amines will not be realized as amine carry over is practically nil. CO2 corrosion in this section should be considered only for upset conditions and prevailing only during the “water wet” upset periods. Average CO2 corrosion = Wet CO2 Corrosion x water wet time fraction. Typical wet CO2 corrosion at 36°C and 144 kPa (g) pressure, 99% CO2 for CS is about 2 mm/y (deWaard nomogram). Upset Duration per year

Water wet time fraction

Average CS CO2 corrosion rate

Comments

1 day 0.0027 0.0054 mm/y Nil 10 days 0.027 0.054 mm/y Nil 30 days 0.082 0.16 mm/y Minor

36C


41

It is not likely that the plant will be operated with more than 30 days of upset per year, hence CO2 corrosion should not be a concern.

4.9.2 REASONS FOR MATERIALS OF CONSTRUCTION

Equipment No.


V-4 Stripper Reflux Drum Shell: CS/ 304L SS Clad internals: 316 SS

E-5 Stripper Overhead Condenser

Shell: SS Clad Tubes: SS


4.9.4 SUGGESTED SAMPLE POINTS 4.9.5 DETERIORATION MODES The failure modes for the respective corrosion mechanisms anticipated or experienced in this Circuit and their likelihood of occurring are listed below: 1. Possible but unlikely within this Circuit; 2. Likely, if right conditions are met; and, 3. Likely under current operating conditions.

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES



piping 2 1 For water wet

locations


contact with

amine solution

or with amine

carry-over

1 1 Similar to CO2

corrosion but at a

reduced magnitude

due to the inherent

high pH nature of

amine solution


42

DEGRADATION

MECHANISM

AREAS

AFFECTED

LIKELIHOOD NOTES


Amine Stress

Corrosion

Cracking

1 1 Unlikely if the

materials are SS or

PWHT carbon steels

(see API 571

Paragraph 5.1.2.2.1)


Low velocity area

3 2

Erosion due to impingement by solids


1 1

Galvanic Corrosion





2 1



Water vapor content

Below water condensation point

High Wet CO2 corrosion

Temperature Above dew point High Wet CO2 corrosion 4.9.7 ON-LINE CORROSION MONITORING


None


43



ETC.)

Piping Discharges of Pump P-2 A/B

Check (UT/RT for erosion/corrosion

Cooler E-5 In/outlet nozzles Check (VT/RT for erosion/corrosion 4.9.9 STARTUP AND SHUTDOWN CONSIDERATIONS


Stripper overhead piping

CO2 line leakage can cause temperature drop to below -29°C (Joule Thompson gas expansion effects)


07-0-ra-4804-0001 - corrosion control manual - to goa · shell canada energy, chevron canada...

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