YR V11 CCD (SAER-6353)

Engineering ReportSAER-6353 23 July 2011Corrosion Control Document – Yanbu Refinery Continuous Catalytic Regeneration (CCR) Platformer Plant V11

Table of Contents

1 Introduction............................................................ 2

2 Process Description............................................... 2

3 Top Corrosion Challenges..................................... 5

4 Corrosion Loops and Damage Mechanisms……. 12

5 Risk Assessment.................................................. 22

6 Corrosion Management Strategies....................... 23

7 Plant Integrity Windows........................................ 28

8 CMP Dashboard……………………………………. 33

9 Technologies........................................................ 33

10 Assessment Findings........................................... 35

11 References........................................................... 35

Appendix I - Corrosion Loop Drawings....................... 37

Appendix II - Customized Damage MechanismNarratives…………………………….….. 43

Appendix III - List of CMP Deployment Observations. 61

Previous Issue: New Next Planned Update: 1 August 2012Page 1 of 71

Primary contact: Al-Ghamdi, Sami Mohammed on +966-3-876-0313

Copyright©Saudi Aramco 2011. All rights reserved.

SAER-6353 Corrosion Control Document - Yanbu Refinery CCR Platformer Plant V11Issue Date: 23 July 2011 Next Planned Update: 1 August 2012

1 Introduction

This Corrosion Control Document provides guidelines for Yanbu Refinery CCR Platformer Plant V11 to proactively manage risks due to corrosion, identify, monitor damages and provide corrosion control options in the Operation & Maintenance phase of the asset life cycle of CCR Platformer Unit V11.

The document provides basic information on material and corrosion considerations for the unit. It includes corrosion loops, potential damage mechanisms, corrosion control plans, plant integrity windows, key performance indicators and assessment findings.

The guidelines laid out in this document will permit to:

Ensure minimal foreseeable risk on safety and reliability

Assure maximum life expectancy of aging equipment

Meet increasing production demands

Provide prioritized input for fiscal planning

Identify areas of new technology applications

This document will require periodic revisions based on facility performance reviews, corporate audits, T&I findings, changes in design, feed composition, capacity and operational parameters.

2 Process Description

Yanbu Refinery Plant V11 was originally designed as a Fixed-Bed Platformer Unit to process 35 MBPD Heavy Straight Run Naphtha (HSRN) and produce 28 MBPD Platformate at 94 RON. The unit was shut down every 6 to 8 months to regenerate (burn-off coke and re-activate) the catalyst. The unit was later revamped to convert it to a Continuous Catalyst Regeneration (CCR) Platformer. The unit is now designed to process a higher capacity of 40 MBPD HSRN and produce 30.2 MBD Platformate at 100 RON. The CycleMax CCR regenerator is designed to continuously regenerate UOP-R234 catalyst at 100 % circulation rate (2000 lb/hr) to maintain the catalyst selectivity and activity. The spent catalyst from the 3 stacked reactors’ side is transported to the regeneration tower in the CCR to burn off the coke and distribute the platinum over the catalyst. The regenerated catalyst is then transported back to the reduction zone above the Platformer stacked reactors to reduce the catalyst and complete the regeneration steps. A simplified process flow diagram is provided in Figure 1.

2.1 Platformer Reactor Section

The CCR Platforming Plant consists of three (3) stacked reactors (C-0102 – C-0104), product recontacting and stabilization. Hydrotreated naphtha feed from Naphtha Hydrotreater (NHT) Plant V09 is combined with Hydrogen-rich, recycle gas from the recycle compressor (C1 A/B) before entering the tube-side of four parallel vertical combined feed heat exchangers (E1 A-D). In the heat exchangers, the combined feed is heated by the effluent from the 3 rd

reactor. The different feed streams then recombine and flow to the charge heater (H1) which heats it to 549oC (design). The combined feed then enters the 1st reactor (C-0102) which undergoes several reactions over platinum catalyst in the stacked reactors to produce high octane gasoline blending product, hydrogen, and LPG. The predominant reactions are

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endothermic decreasing the temperature to 92oC, so interheaters are used between each reactor to reheat the charge feed to reaction temperature. The first interheater (H2/H3) heats the effluent from C-0102 to required operating temperature before entering the second reactor (C-0103). The effluent is reheated again in the new second interheater (F-0101) from 62 to 549oC before entering the 3rd reactor (C-0104). The product stream then passes through the shell-side of E1 A-D heating the feed before being cooled in the air-cooled product condensers (E2 A-F) and water-cooled product trim coolers (E3 A-D) down to 38oC.

The product stream is split into vapor (H2 gas) and liquid (unstabilized reformate) products in the product separator (V4). The unstabilized reformate, which is composed of high octane reformate, light ends (propane and butane), and dissolved hydrogen, is pumped to the Saturated Gas & LPG Recovery for further processing. A slip stream is sent to the recontact drum (D-0103) to enhance the recovery of liquids from the net gas stream.

2.2 Hydrogen Gas Compression Section

Hydrogen concentration in the product separator gas is around 85% while the remainder is light end gases. The gas leaving V4 is compressed by C1 A/B and is then split into three (3) streams:

Recycle gas which is combined with the fresh feed into E1 A-D

Purge gas to catalyst collector on the bottom of the reactors’ stack

Net gas to the net gas system

The net gas stream is cooled in the net gas cooler (E0101) and net gas trim cooler (E0102) before entering the suction drum (D-0102). Recovered liquids are sent back to V4. The product net gas is split into three (3) streams:

Around 10% is sent to the suction of the booster compressors (C2 A-C) for further recontacting with the platformate for recovery of heavier components in D0103

Around 10% is sent to the suction of the new booster compressors (K-0106 A/B) then to the chloride treater (D-0104) to be used as make-up gas for NHT and LSRN Hydrotreater Plants.

Around 80% is sent to the Advanced Extraction Technology (AET) LPG Recovery section. The process absorbs gaseous LPG from the net gas in a rich platformate stream from the debutanizer feed from Plant V14. Recovered LPG is separated in the debutanizer of V14 and off gas is routed to the Fuel gas system.

2.3 AET LPG Recovery Section

The AET LPG recovery unit is designed to recover 97% LPG from the Platformer net gas and subsequently increases the H2 purity from 80 to 89% for CCR Platformer unit & fuel gas consumption. The net gas is chilled down to -28.9oC while passing through the gas/gas cross exchanger (E-0106) and feed gas chiller (E-0107) using closed-loop propane refrigeration (-33oC) before entering the bottom of absorber (C-0101). The rich platformate stream was also cooled down to -28.9oC through the cross exhangers (E-0110 A-D) and platformate chiller (E-0111) using propane refrigeration before entering C-0101. In the absorber, which contains three (3) packed beds, the gas is washed by a counter-current flow of the platformate entering below the top bed. The LPG-rich stream leaves C-0101 bottom to the debutanizer (V14-V1)

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for separation and recovery. The absorber overhead gas is quenched with debutanizer bottoms and cooled and particially condensed in the presat chiller (E-0108). Separated gas passes from the presat separator (D-0110) to the fuel gas system via the net gas chloride treater (D-0105 A/B), while separated liquid is pumped back to C-0101 top.

2.4 Continuous Catalytic Regeneration (CCR) Section

The CCR is designed to regenerate the catalyst continuously by burning off with air the coke deposited on the catalyst surface. The CCR is a pressurized and valveless design. The Catalyst Regeneration Section performs two functions: catalyst regeneration and catalyst circulation.

In CCR regeneration section, the spent catalyst from the reactors is regenerated at certain circulation rate to maintain catalyst activity and selectivity. Regenerated catalyst is recycled back to the stacked reactors. The spent catalyst is continuously withdrawn from the last reactor, regenerated in the CCR regenerator tower (D-0140), and then returned to the first reactor (C-0102). This ensures a continuous operation of the plant at higher severities for better quality products with higher yields. Spent catalyst chips and fines are elutriated in the disengaging hopper (D-0151) using nitrogen gas and removed in the dust collector (D-0156). The CCR performs the following four main functions in various zones of the catalyst regeneration system:

2.4.1 Burn Zone

Coke burning takes place in presence of oxygen. It results in temperature rise on the catalyst. The coke burning is performed in a controlled manner by maintaining the oxygen content at 0.5 to 0.8 mol%.

2.4.2 Chlorination Zone

The chloride content on the catalyst is adjusted in this zone. Chloride maintains the acidic function of the platforming catalyst and re-disperses the metal on the catalyst surface. Chloride is maintained at 0.8-1.1 wt% during normal operations. Perchloroethylene (PERC) is normally injected as chloride.

2.4.3 Drying Zone

The excess moisture from the catalyst is removed in this zone. Drying air is a combination of instrument air and preheated air from the cooling zone below. Air from drying zone, which is required for coke burning in the burn zone enters the chlorination zone and the excess air exits the regeneration tower.

2.4.4 Reduction Zone

The final step of catalyst regeneration occurs in the reduction zone. The reduction zone is located at the top section of the lock hopper (D-0153). Catalyst is lifted to the reactor surge drum at the top of the reactor structure by hydrogen lift gas where it then flows by gravity to the first reactor (C-0102). The reduction step converts the metals from an oxidized state to a reduced state using pure hydrogen gas. This must be done after the oxychlorination step to return the metals to an optimum state before returning catalyst to the reactors. The conditions favor this reduction step are high hydrogen purity, sufficient reduction zone temperatures and adequate reduction gas flow rate.

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2.5 Vent Gas Wash Tower Section

Circulating caustic solution with a concentration of 0.2 %wt, pH between 7.5 – 8.5 and total solids of 1.0 %wt is mixed with the combustion gas from D-0140 with a temperature of 472oC first in the venturi scrubber (D-0141) then again in the vent gas wash tower (D-0137). The intent is to scrub the vent gas free of residual chloride prior to being vented to the atmosphere. The HCl removal efficienty is between 95 and 99%.

Figure 1 – Simplified YR CCR Platformer Process Flow Diagram

3 Top Corrosion Challenges

Several corrosion challenges have been historically noted in the CCR Platforming Plant V11, as follows:

3.1 LPG Recovery (AET) Corrosion

Chlorides can be stripped from the catalyst and react to form HCl that is carried through the effluent trains, regeneration system as well as the recycle gas, net gas, off-gas and fuel gas systems. Excessive corrosion can also be found after mixing dry chloride containing streams with others containing water.

In 2009, severe corrosion was observed in several stagnant locations; drain lines, sight glass lines, valves and piping. Also, E-109 tubes showed 20-40% metal loss due to HCl corrosion in a few years. A comprehensive evaluation conducted in October, 2009 identified the use of Chloride Treaters upstream of the AET to be the best long-term solution. During 2011 TRS, tie-in connections were made for Chloride Treaters installation.

From 2010 Health Check, the recommendation to extend cold insulation around the drain connections was addressed to ensure there was no condensation leading to HCl corrosion

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(Figure 2). Also, insulation throughout the unit was inspected to ensure it was completely sealed and was not damaged especially around the valves.

Figure 2 – 1” drain line in Plant V11 that experienced a pinhole leak due to HCl corrosion. (Ref. CSD/ME&CCD/L-065/11)

Severe corrosion was observed in the impeller of AET Absorber Bottoms Pump (G-0109). This was most likely due to condensation during the standby mode. Also, plugging was observed in the strainer upstream of Platforming Product Separator Bottom Pump (G-0103), which is also attributed to the presence of chlorides and moisture.

To address the above challenges, the following recommendations are proposed:

Expedite the installation of the Chloride Treaters. That will only minimize future deposit formation; plugging due to existing deposits can still be expected.

Support YR effort to raise the AET operating temperature to around -10oC to minimize the formation of liquid water. The economic trade-off need to be evaluated for the loss of LPG recovery.

Flush the pump soon after being on standby and during T&I to prevent condensation and HCl corrosion. If pH is still low, flush with caustic solution.

3.2 Vent Gas System Corrosion

The cause of the severe corrosion in the vent gas system is mostly due to acidic conditions resulting from pH control concerns, high chloride content of the feed and ineffective caustic neutralization; refer to Figure 3. The resulting high solids content can result in under-deposit corrosion. Frequent leaks were observed in the 2" vent line, flanges and the 10" to 8" reducer in the venturi scrubber discharge. This had led to the bypassing of the tower for as long as 10 months. The metallurgy for Wash Tower (D-0137) is CS with APCS 2G (polyglass VEF) coating which required minor repairs during the 2008 T&I but not during 2009 inspection. D-0137 was not part of the 2011 TRS because it was not a shutdown item. Severe corrosion and leaking of the operating CS Caustic Circulation Pump (G-0117) are still continuing with the spare pump in the shop.

From 2010 Health Check, the recommendation to upgrade the metallurgy to Hastelloy C-2000 from the Venturi Scrubber to the Wash Tower was addressed. Also, modification to the caustic injection scheme is being considered to ensure reliability of neutralization.

The following recommendations are proposed to address above concerns:

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Maintain circulating caustic solution at target total alkalinity of 0.2 – 0.35 wt%, pH between 7.5 and 8.5, and total solids less than 1.0 wt% (10,000 ppm).

Flush the pump soon after bypassing VGWT to prevent salt accumulation and corrosion.

Utilize isolation kits between the dissimilar materials in the spent caustic system.

Consider use of nonmetallic for the pumps and venturi discharge piping (thermoplastic liner) to the wash tower.

If APCS 2G coating fails during next inspection, then it is advised to conduct coating failure analysis and consider alternative coatings (APCS 2H/APCS 27) of SAES-H-001.

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Figure 3 – Plant V11 VGWT Caustic Solution Alkalinity, TSS, and pH trends for 2010.

3.3 Sea Water Corrosion

The malfunction of the current NaOCl disinfection system and consequent low chlorine residuals (around 0.03 ppm) is allowing bacterial growth and biomass build-up leading to microbial corrosion and fouling. The repair of the current system is possible, but is not complete. Also, the installation of the new ClO2 system is advantageous but has been delayed for years now. Repeated failures of the sea water exchanger 70-30 Cu-Zn and 90-10 Cu-Ni tubing and Monel weld overlays were observed (Figure 4). Also, concerns with the intake

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filters are allowing large objects and marine life to enter the cooling system further aggravating the fouling problems (Figure 5).

Figure 4 – MIC of Plant V11 Caustic Cooler V11-E-0125 Monel 400 tubes. (Ref. CSD/ ME&CCD/L-095/10 & YR-EIU-056/2010)

Figure 5 – Fouling and Macrobiological Organisms found in Plant V11 Platforming Products Trim Cooler V11-E3 (A-D)

Premature failures of cement lined/coated CS spools have been repaired using elastomer and CS clamps. Also, there were repeated coating failures in the channel heads, e. g. APCS 3 coal-tar epoxy coating in E-003 B/D. Permanent repair and replacement in-kind are normally done at the next shutdown.

The following are recommendations to resolve above challenges:

Ensure adequate chlorination of the cooling water make-up and maintain the sea water intake filter integrity. Utilize ClO2 which is a better alternative disinfectant.

Perform routine monitoring of the microbiological profile of the cooling wate.

Consider coatings (applied at 8-10 mils) to minimize fouling in heat exchanger tubes and under deposit/MIC corrosion. Use heavy duty coatings as per APCS-28 in SAES-H-001 in the channel heads, piping, spools and associated valves.

Consider alternative cost effective options such: a. Thermoplastic (PP) lined carbon steel pipes or nonmetallic (RTR) pipes replacement. b. Composite repairs to restore the pipe integrity as a temporary measure.

3.4 Corrosion Monitoring Deficiencies

3.4.1 Coupons

Corrosion coupons are removed on a 6-12 month frequency or sooner, if high corrosion rates are observed. Data off of the coupons need to be supplemented by OSI program to confirm the results; however, review of available data did not indicate if the coupons were recently retracted.

3.4.2 Probes

Corrosion probes installed at different locations in Plant V11 are providing acceptable corrosion rates ranging between 0.09 to 0.36 mpy. It is preferable to correlate these readings with OSI program to confirm accuracy. YR can use the planned RBI study to

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identify the highest risk locations to optimize installation of the corrosion coupons and probes. The system has been recently bypassed to upgrade to wireless data gathering.

3.4.3 OSI

Review of measured UT data available in SAIF showed that out of 6000+ TMLs 767 points had a corrosion rates > 5 mpy, out of which 47 TMLs also had a remaining life < 10 years. The most severe location is located in circuit # ¾”-FG-0605AC-1CC1P-S with a corrosion rate of 126 mpy and a remaining life of 4.2 years.

The following are recommendations to address above findings:

Define high risk locations from RBI study to re-activate corrosion monitoring. Also, use the RBI study to prioritize the ongoing effort to establish UT baseline data for corrosion analysis.

Consider installing corrosion coupons of different metallurgy in the seawater system (V11-E-3 and V11-E-0125) and vent gas systems (wash tower piping) where severe corrosion has been observed. Additional installation locations can be identified after completing the requested OSI readings specified in section 3.5.

Maintain trending records of corrosion probes and coupons data over the years to build-up a historical performance that will clearly provide the corrosion behavior over time.

Utilize both corrosion rates and remaining life to detect locations of high penetration rates

3.5 Corrosion Review

Based on a review of CLs and potential DMs, several high priority locations were identified for further detailed evaluation. Currently, analysis could not be conducted due to lack of required data. These locations are discussed below:

Potential HCl corrosion due to condensation in 4"-P-203-3CA1B, Recontact Chiller (E-0116) to Recontact Drum (D-0103) in CL#3, but OSI data was not available in SAIF.

Potential HCl corrosion in C-0101 Absorber Bottom in CL#7, but OSI data was not available in SAIF and individual readings were not analyzed.

Potential HCl corrosion in 12"P-0133/134-1CA1B, C-0101 Absorber to G-109 A/B in CL#7, but OSI data was not available in SAIF and individual readings were not analyzed while UT readings are taken every 3 months.

Potential HCl corrosion in 6"P-0124-1CA1B, from G-109 A/B to E-109 A/B in CL#7, but OSI data were not available in SAIF.

Potential corrosion pitting in 3"P-0220-3CJIP, Reactor to E-0120 in CL#8, but OSI data was not available in SAIF.

Potential corrosion due to stagnant conditions in 24" P-1256-3CDIP, Regen. Blower (K-0110) to Regeneration Cooler (E-0126) in CL#11, but OSI data was not available in SAIF. The location was previously cracked and pitted then replaced, in-kind, with 316SS. A new connection was installed from dryer to loop to reduce moisture.


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Expedite the entry and analysis of the UT and RT data into the SAIF program so detailed corrosion analyses could be performed.

Send samples of repeated failures to MEU Lab for a detailed failure analysis e.g. 24" P-1256-3CDIP.

Utilize this Corrosion Control Document to focus on highly critical variables and conduct your annual review/audit.

3.6 Coating Application and Maintenance

3.6.1 Coatings under Insulation

External corrosion was observed on insulated piping, valves and flanges (including bolts and nuts) in low temperature service, e.g. outlet piping valve of E-109 A-D, E-123, and E-116. The inorganic zinc coating (APCS-17A) does not provide adequate corrosion control for piping in such service with moisture and ice forming externally under the existing foam glass insulations. There was damage observed in this cold insulation and other hot insulation (calcium silicate). There was no vapor barrier, top-coating, over the cold insulation to keep moisture from forming on the piping surface.


For cold insulation: a) use immersion resistance coatings based on epoxies APCS-2A/2E/2I, under cold insulation instead of inorganic zinc coating, and b) apply vapor barrier elastomeric top-coating type over foam glass in cold service.

For hot insulation: a) use APCS-11C coatings designed for temperature cycling under calcium silicate, or b) use APCS-5B sprayable insulating coatings as a cost-effective alternative. The latter can insulate irregular shapes with valves and flanges

For bolts and nuts use floupolymer coating standard 09-SAMSS-0107. This will protect fasteners from corrosion and seizing during dismantling.

3.6.2 Coating for Heaters H-1/2/3 and F-101

The silicone based external coating (APCS-11A) was failing in the burner areas and on the heater roof side. Also, there might not have been any anti-corrosion coating applied before the installation of the refractory. Also, there was external scale formation on heater tubes that might lead to localized hot spots.

Damper plates and shafts were distorted by high temperature. In the last TRS, the metallurgy of the shaft was recently upgraded to 25Cr-12Ni and for the plates to 310 SS with bolts and nuts. The dampers may still be exposed to higher than design temperatures due to original design deficiency of not having convection section in the heaters' stacks that can lower flue gas temperatures.


For heaters’ external surface use APCS-11C coating which has better surface tolerance and high temperature resistance.

For heaters’ casings, including anchors, use high temperature coatings based on aphaltic-ureathane.

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For heaters’ dampers consider the use of thermal barrier coating technology, if distortion is still observed.

3.6.3 Flare Header Isolation Valves

It was observed that external top-coatings over pressure safety valves (PZVs) is aluminum pigmented coating instead of the orange pigmented system.

It is recommended to select proper external coating system that contain orange pigment in their top-coat from SAES-H-001 after checking the process temperatures.

3.7 Heater Transfer Lines Terminal Welds

There has not been any inspection for the potential damage mechanism of creep cracking for the heaters' transfer piping. This includes the externals of heater to reactor terminal welds where stress levels can be very high and creep can initiate. This has been an industry-wide concern; refer to Figure 6.

Figure 6 – Tyical creep cracking usually found in high temperature piping terminal weldments of low alloy steels.

It is advised, during next opportunity or T&I, to conduct inspection of the terminal welds of all low-alloy transfer piping.

4 Corrosion Loops and Damage Mechanisms

The CCR Platformer Plant V11 was divided into fourteen (14) corrosion loops (CL's). These were defined mainly on the basis of similar process conditions, materials of construction or active/potential corrosion, materials degradation and fouling mechanisms. Eighteen (18) unit specific damage mechanisms (DMs) were identified and the narratives derived from the SABP-A-033 “Corrosion Management Program (CMP) Manual (Volume 3 of 3) – Damage Mechanism Narratives.” These were customized to account for differences in process streams, metallurgy and historical maintenance/operational experience for YR CCR Platformer Plant. This section can also be used in the development of the Plant Integrity

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http://standards/docs/Best_Practices/PDF/SABP-A-033.PDF


Windows (PIWs), Key Performance Indicators (KPIs), and Dashboard as well as in the undertaking of the risk-based inspection (RBI) study.

It is noted that the damage mechanism numbers in the materials of construction section below refer to a Saudi Aramco numbering system adapted from API RP 571. Also, for process details refer to Section 2 “Process Description.” The Corrosion Loop Drawings (CLDs) and customized DMs Narratives are provided in Appendix I and II, respectively.

4.1 Corrosion Loop (CL-1): Hydrotreated Naphtha Feed

4.1.1 Description

This corrosion loop contains the naphtha piping from the battery limit (Plant V09 - NHT) to the Platforming Combined Feed Exchangers (V11-E1 A-D), upstream of H2 gas injection from Platforming Recycle Gas Compressors (V11-C1 A/B).

4.1.2 Materials of Construction

Piping Materials PWHT InternalCladding

Internal

Coating

Insulation

8-O-47001-A2B2-H25 Seamless CS N N N Y

4.1.3 Potential Damage Mechanisms

None

4.2 Corrosion Loop (CL-2): Combined Feed

4.2.1 Description

Hydrotreated naphtha is combined with recycle H2 gas before entering the tube-side of E1 A-D. The combined feed is heated by the effluent from the 3 rd reactor (C-0104). The stream then flows to the charge heater (H1) before entering the 1st reactor (C-0102). The first interheater (H2/H3) reheats the effluent before entering the 2nd reactor (C-0103). The effluent is reheated again in the new second interheater (F0101) before entering C0104. The product stream then passes through the shell-side of E1 A-D heating the feed.

This corrosion loop contains C-0102/3/4, E-0112 (tube side), E1 A-D, F-0101, H1/2/3, and interconnecting piping.


Equipment/Piping Materials PWHT InternalCladding

Internal

Coating

Insulation

V11-C-0102/3/4 2.25 Cr - 1 Mo Y N N YV11-E-0112 TS 1.25 Cr - 0.5 Mo Y - N -V11-E1 A-D SS 1.25 Cr - 0.5 Mo Y N N YV11-E1 A-D TS 1.25 Cr - 0.5 Mo Y - N -V11-F-0101 9 Cr - 1 Mo Y - N -V11-H1/2/3 2.25 Cr - 1 Mo Y - N -

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24-O-47005-E2B1-H100 1.25 Cr - 0.5 Mo Y N N Y


(3) Creep/Stress Rupture(10) High Temperature Hydrogen Attack(11) Oxidation(12) Thermal Fatigue(30) Short Term Overheating(59) Metal Dusting

4.3 Corrosion Loop (CL-3): Unstabilized Reformate/Separator Liquid Product

4.3.1 Description

The platformate product stream from E1 A-D gets cooled in the air-cooled Product Condensers (E2 A-F) and water-cooled Products Trim Coolers (E3 A-D) before entering Product Separator (V4) where H2 gas is separated from unstabilized reformate. A liquid drain from the Booster Gas Coalescer (D-0147) is also routed to V4. The Separator liquid product, which is composed of high octane reformate, light ends, and dissolved H2, is pumped offsite to the Saturated Gas & LPG Recovery for further processing. A slip stream is sent to the Recontact Drum (D-0103) to enhance the recovery of liquids from the Net Gas stream.

During normal operations, there is 0.5 – 1 ppm HCl in the separator liquid, especially from E-0116 to D-0103. Also, there is around 5 – 6 ppm HCl and 30 ppm of moisture in the unstabilized reformate. However, during plant start-up, around 750 – 1,000 ppm of water is processed in the reactor effluent which only occur after elongated shutdowns (every 5 years). The process dries out down to normal moisture levels in around 5 days of plant operation. Finally, there is only 1 ppm of N2 in the hydrotreated naptha feed to the unit.

This corrosion loop contains D-0103 bottom, E2 A-F, E3 A-D (shell-side), E-0116 (shell-side), V4 bottom, outlet piping from D-0147 and interconnecting piping.



Internal

Coating

Insulation

V11-D-0103 bottom CS N N N YV11-E-0116 SS CS N N N YV11-E3 A-D SS CS N N N YV11-E2 A-F FF CS N N N -V11-V4 bottom CS N N N N30-O-47016-A2B2 Killed ITCS N N N N10-P-0152-1CA1P Killed ITCS N N N N4-P-0203-3CA1P Killed ITCS N N N Y


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(9) HCl Corrosion

4.4 Corrosion Loop (CL-4): Recycle/Net H2 Gas

4.4.1 Description

H2 gas from V4 is compressed in the Recycle Gas Compressor (C-1A/B) and is split into three streams. The temperature of C1 A/B discharge is around -65oC. Recycle gas is combined with the naphtha feed into E1 A-D. Another stream is heated in the shell side of Reactor Purge Exchanger (E-0112) and is sent to the Catalyst Collector at the bottom of the reactor stack. The final stream (Net Gas) is cooled in Net Gas Cooler (E-0101) and Net Gas Trim Cooler (E-0102) before entering the Net Gas Compressor Suction Drum (D-0102). Recovered liquids from D-0102 are sent back to V4. During normal operations, there is 3 – 4 ppm HCl, 20 – 25 ppm H2O, and < 0.5 ppm H2S in the recycle gas.

This corrosion loop contains D-0102 bottom, E-0101, E-0102 (shell-side), E-0112 (shell-side), V4 top, and interconnecting piping.


Equipment/Piping Materials PWHT

InternalCladding

InternalCoating

Insulation

V11-D-0102 bottom CS Y N N NV11-E-0101 FF CS N N N -V11-E-0102 SS CS N N N NV11-E-0112 SS 1.25 Cr - 0.5 Mo Y N N YV11-V4 top CS N N N N26-O-47020-A2B2 Killed ITCS N N N N20-O-47022-A2B2-P25 Killed ITCS N N N Y18-P-0162-1CA1P Killed ITCS N N N Y2-P-0174-3CJ1P-HC 1.25 Cr - 0.5 Mo Y N N Y


(9) HCl Corrosion(31) Brittle Fracture(54) Mechanical Fatigue

4.5 Corrosion Loop (CL-5): Net/Make-up H2 Gas Compression

4.5.1 Description

The product Net Gas from D-0102 top is split into three streams. Around 10% is sent to the suction of the Booster Compressors (C2 A-C) then cooled in Net Gas Compressor Discharge Cooler (E-0103). Another 10% is sent to the suction of the Booster Compressors (K-0106 A/B) then to the Make-up Gas Chloride Treater (D-0104) to be used as make-up gas for NHT and LSRN Hydrotreater Plants. However, the majority (around 80%) is sent to the AET LPG Recovery section.

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This loop contains D-0102 top, D-0104, D-130 A-H, D-0162 A/B, E-0001 A/B, E-0103 and interconnecting piping.



InternalCladding

InternalCoating

Insulation

V11-D-0102 top CS Y N N NV11-D-0104 CS N N N YV11-D-130 A-H KCS N N N YV11-D-0162 A/B KCS N N N YV11-E-0001 A/B FF SS 316L N N N -V11-E-0103 FF CS N N N -18-P-0105-1CA1P KCS N N N Y6-P-0182-1CA1P KCS N N N N


(9) HCl Corrosion(23) Chloride SCC(54) Mechanical Fatigue

4.6 Corrosion Loop (CL-6): Presat/Reduction Gas Chloride Treating

4.6.1 Description

The separated gas from the Presat Separator (D-0110) is heated in the shell side of the gas/gas cross exchanger (E-0106) then is combined with the moist Reduction Gas from C-0102 via Reduction Gas Exchanger (E-0123) shell side. The combined gas (2 – 3 ppm HCl) is routed to the Refinery Fuel Gas System via the Net Gas Chloride Treaters (D-0105 A/B).

This loop contains D-0105 A/B, E-0106 (shell-side), E-0123 (shell-side) and interconnecting piping.



InternalCladding

InternalCoating

Insulation

V11-D-0105 A/B CS N N N NV11-E-0106 SS CS Y N N YV11-E-0123 SS 1.25 Cr - 0.5 Mo Y N N Y16-FGH-0372-1CA1P Killed ITCS N N N N14-FGH-0373-1CA1P Killed ITCS N N N Y


(9) HCl Corrosion

4.7 Corrosion Loop (CL-7): AET LPG Recovery

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4.7.1 Description

Net Gas from D-0102 is combined with gas from the Debutanizer Overhead Reciever (V14-V2) before passing through the tube-side of E-0106 to be cooled. The mixture is further cooled in the feed gas chiller (E-0107) tube-side before entering the Absorber (C-0101). Rich Platformate from Debutanier (V14) feed is also cooled via tube-side of the Cross Exhangers (E-0110 A-D) and tube-side of Platformate Chiller (E-0111) before entering C-0101. Absorber overhead gas is quenched with Debutanizer (V14-V1) bottoms before further cooling in the tube-side of Presat Chiller (E-0108) and partial condensing in D-0110. The condensed fluids are returned to C-0101 top. The LPG-rich stream leaves C-0101 bottom to V14-V1 via shell-sides of E-0110 A-D and E-0109 A-D for separation and recovery.

The LPG recovery was designed with no chlorides in the feed, while actually there is around 6 ppm. Also, operation of LPG recovery is close to the gas stream dew point around -32oC. the combined effect of both factors lead to excessive corrosion of CS components and piping.

This loop contains C-0101, D-0110, E-0106 (tube-side), E-0107 (tube-side), E-0108 (tube-side), E-0109 A-D (shell/tube-sides), E-0110 A-E (shell/tube-sides), E-0111 (tube-side), piping from D-0102, piping to/from V14-V1, piping from V14-V2, and interconnecting piping.


Equipment/Piping Materials PWHT Internal Cladding InternalCoating

Insulation

V11-C-0101 top CS Y SS A20 Strip Lining N YV11-C-0101 bottom CS Y SS A20 Strip Lining N YV11-D-0110 CS Y SS A20 Strip Lining N YV11-E-0106/7/8/11 TS ITCS N - N -V11-E-0109 A-D SS CS Y SS A20 Strip Lining N YV11-E-0109 A-D TS ITCS N - N -V11-E-0110 A-E SS CS Y SS A20 Strip Lining N YV11-E-0110 A-E TS ITCS N - N -16-P-0113-1CA1P ITCS N N N N4-P-0223-1CA1P ITCS N N N Y


(9) HCl Corrosion(31) Brittle Fracture(46) Corrosion Under Insulation

4.8 Corrosion Loop (CL-8): Booster Gas

4.8.1 Description

Hydrogen gas from the top of D-0103 is routed to the to Booster Gas Coalescer (D-0147). A portion of the booster gas is heated in the tube-side of the Booster Gas Heater (E-0124) before being routed to the Lock Hopper (D-0153) for catalyst reduction. Lock Hopper

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Gas is routed to the to the Fuel Gas Drum (D-0101). This gas is added to the fuel gas used for the Reactor Heaters (H1/H2/H3 and F-0101). Also, a portion of the gas from E-0124 goes to the catalyst line near FCV-0254/0256 to help with fluidization.

The other portion of the booster gas is heated in the Reduction Gas Exchanger (E-0123) tube-side and the Reduction Electric Gas Heater No. 1 & 2 (E-0119 and E-0120) before entering C-0102 at a temperature around 480oC.

This loop includes, D-0101, D-0103 top, D-0147, E-0119 (shell-side), E-0120 (shell-side), E-0123 (tube-side), E-0124 (tube-side), and interconnecting piping.



InternalCoating

Insulation

V11-D-0101 CS N N N NV11-D-0103 top CS N N N YV11-D-0147 KCS N N N YV11-E-0119 SS SS 304H - N N YV11-E-0120 SS SS 304H - N N YV11-E-0123 TS 1.25 Cr - 0.5 Mo Y - N -V11-E-0124 TS KCS N - N -10-FG-0601-1CC1P CS N N N Y10-FG-0602-1CC1P CS N N N N3-P-0205-3CA1P ITCS N N N Y


(10) High Temperature Hydrogen Attack(11) Oxidation

4.9 Corrosion Loop (CL-9): Circulated Catalyst

4.9.1 Description

Spent catalyst received from C-0104 is sent to the Disengaging Hopper (D-0151) before entering the Regeneration Tower (D-0140) top. Make-up catalyst is added to the reactor discharge line via Catalyst Addition Funnel No. 1 (D-0149) and Catalyst Addition Lock Hopper No. 1 (D-0150). Catalyst from the bottom of D-0140 goes to the Nitrogen Seal Drum (D-0136) to the top of D-0153. Again, make-up catalyst can be added to D-0136 via Catalyst Addition Funnel No. 2 (D-0154) and Catalyst Addition Lock Hopper No. 2 (D-0155). Regenerated catalyst from the bottom of D-0153 is sent to C-0102 top.

Gas vented from D-0151 is separated from catalyst dust in the Dust Collector (D-0156). Dust fines are collected in the Fines Collection Pot (D-0152) and are then sent to the catalyst fines drum. The fines are also sent to the Fines Removal Blower (K-0112) back to inlet of D-0151. The gas from D-0156 is sent to the Lift Gas Blower (K-109) then mixes with C-0104 catalyst withdrawal line going to D-0151. Some of the gas also meets the K-0112 outlet prior to going to D-0151.

This loop includes D-0136, D-0147, D-0149 to D-0156, and interconnecting piping.

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InternalCoating

Insulation

V11-D-0136 CS N N N YV11-D-0147 CS N N N YV11-D-0149 SS 304 N N N NV11-D-0150 SS 304 N N N NV11-D-0151 CS N N N NV11-D-0152 CS N N N NV11-D-0153 CS N N N YV11-D-0154 CS N N N NV11-D-0155 CS N N N NV11-D-0156 CS N N N N4-CAT-1063-1CA0P ITCS N N N N3-CAT-1087-1CC0P CS N N N Y


(9) HCl Corrosion(10) High Temperature Hydrogen Attack(20) Erosion/Erosion-Corrosion

4.10 Corrosion Loop (CL-10): Sea Water Cooling

4.10.1 Description

Sea water is used as cooling media for different process streams. This loop includes the tube side of Net Gas Trim Cooler (E-0102), Caustic Cooler (E-0125), Platforming Product Trim Cooler (E3 A-D), and interconnecting piping.



InternalCoating

Insulation

V11-E-0102 TS 70Cu-30Ni or Monel

- - N -

V11-E-0125 TS 70Cu-30Ni or Monel

- - N -

V11-E3 A-D TS 70Cu-30Ni or Monel

- - N -

10-CW-47007-X8F2 Seamless CS N N Y N3-CWS-1098-1NM1C Seamless Ni-Cu N N N N


(51) Microbiologically Induced Corrosion (MIC)(80) Under-Deposit Corrosion

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4.11 Corrosion Loop (CL-11): Catalyst Regeneration

4.11.1 Description

Catalyst from D-0151 enter D-0140 top in the “coke burning” section. The regeneration gas is driven by the Regeneration Blower (K-110) to the Regeneration Cooler (E-0126) where it is cooled from 519oC to 481oC by atmospheric air. The temperature can be maintained by the Electric Regeneration Gas Heater (E-0121). The gas is then returned to D-0140.

Catalyst flows downward by gravity to the “chlorination/oxidation section” where platinum on the catalyst is oxidized and dispersed and chloride content is adjusted. Organic chloride is injected into D-0140 via a steam jacketed pipe.

Finally, the catalyst is dried off in the “drying section”. After removing moisture in the instrument air by the Air Dryer Package, it is further heated in the Electric Air Heater (E-0122).

This corrosion loop includes D-0140, D-0148 A/B, E-0121 (shell-side), E-0122 (shell-side), E-0126, and interconnecting piping.



InternalCoating

Insulation

V11-D-0140 CS N N N YV11-D-0148 A/B CS N N N NV11-E-0121 SS SS 316H - N N YV11-E-0122 SS SS 304H - N N YV11-E-0126 SS 316 - N N Y24-P-1259-3SD1P SS 316L - N N Y6-P-1175-3SC1P SS 304H - N N Y8-P-1176-3SC1P ITCS N N N Y


(9) HCl Corrosion(12) Thermal Fatigue(20) Erosion/Erosion-Corrosion(23) Chloride SCC

The potential for Chloride SCC and HCl corrosion is predominantly during extended shutdown of VGWS without proper drainage. HCl is also of concern in relief and stagnant lines.

4.12 Corrosion Loop (CL-12): Vent Gas Wash System

4.12.1 Description

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Vent Gas from E-0121 outlet (D-0140 inlet) containing chloride compounds and CO2 is initially mixed with 1% caustic solution in the Venturi Scrubber (D-0141). The stream is routed into the Vent Gas Wash Tower (D-0137) where it is further washed with caustic for better neutralization of HCl before venting to atmosphere. The spent caustic is circulated to the Caustic Cooler (E-0125) to help cool it down. Some spent caustic is drawn off to maintain low total solids. Fresh caustic from the Caustic Break Tank (D-0138) is injected to maintain pH and alkalinity, while water from the Water Break Tank (D-0139) is injected to maintain concentration and circulation rate.

This loops contains D-0137, D-0138, D-0141, E-0125, and interconnecting piping.



InternalCoating

Insulation

V11-D-0137 CS Y N Y NV11-D-0138 CS Y N N NV11-D-0141 C-2000 N N N YV11-E-0125 SS CS Y N N Y6-P-1261-3SD1P SS 316L - N N Y6-P-1267-ICC4P CS N N N Y6-CA-1040-1CC1C4 CS N N N N


(9) HCl Corrosion(18) Caustic SCC(19) Caustic Corrosion(23) Chloride SCC(53) Galvanic Corrosion (Coating, Dissimilar Metals)(80) Underdeposit Corrosion (Salt)

4.13 Corrosion Loop (CL-13): Propane Refrigeration

4.13.1 Description

Propane from Propane Accumulator (D-0111) is chilled in the HP Economizer (D-0116) to Suction Drums (D-0112/0113/0114) and LP Economizer (D-0115). The propane gas is compressed again in the Propane Compressors (K-0104) then cooled in Propane Condenser (E-0105) before returning back to D-0111 to complete the close-loop refrigeration circuit. Propane from D-0115 is used in the shell-side of the chillers E-0107/0108/0111 to cool the process streams.

This loop consists of D-0112 to D-0116, E-0105 A-M, E-0107 (shell-side), E-0108 (shell-side), E-0111 (shell-side), E-0116 (tube-side), and interconnecting piping.

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InternalCoating

Insulation

V11-D-0111 ITCS N N N NV11-D-0112 ITCS N N N YV11-D-0113 ITCS N N N YV11-D-0114 ITCS N N N YV11-D-0115 ITCS N N N YV11-D-0116 ITCS N N N YV11-E-0105 A-M FF ITCS N N N -V11-E-0107 SS ITCS N N N YV11-E-0108 SS ITCS N N N YV11-E-0111 SS ITCS N N N YV11-E-0116 TS ITCS N N N Y24-RP-0646-3CA1P ITCS N N N Y10-RP-0667-3CA1P ITCS N N N N


(31) Brittle Fracture(46) Corrosion Under Insulation (CUI)

4.14 Corrosion Loop (CL-14): Waste Heat Boiler/Steam System

4.14.1 Description

Boiler feed water enters Steam Drum (D-0122) to tubes in the Waste Heat Boiler (F-0104) heating by the hot flue gases from the reactor heaters and the produced MP steam goes to the main header. The blowdown goes to Blowdown Tank (D-0106) and finally to Waste Heat Boiler Effluent Tank (D-0108).

This loop contains D-0106, D-0122, E-0124 (shell-side), and interconnecting piping.



InternalCoating

Insulation

V11-D-0106 CS N N N YV11-D-0122 CS Y N N YV11-E-0124 SS CS N N N Y12-150S-1011-3CS1P KCS N N N Y3-BBD-0481-1CC1P CS N N N Y


(26) Steam Blanketing(50) Boiler Water/Condensate Corrosion

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5 Risk Assessment

The main objective of the Risk Assessment is to identify the probability and consequences of the potential DMs. The overall risk of the equipment or piping is driven by the worst of safety, production loss (economic), and environment risks that may result from different failure scenarios based on the identified potential DMs. The Risk Assessment will provide the priority ranking for the Corrosion Management Plan (CMP) implementation. Focus will be towards the highest risk items.

The procedure for determining the risk and prioritizing begins by listing all plant equipment and piping then by identifying all potential DMs. For YR CCR Platformer Plant V11, this has already been developed and is provided in Section 4 of this CCD. This information can then be used to determine the probability, determine the consequences, and assess the risk based on worst failure scenario. The latter part can be determined using the company-approved API-RBI software based on API Publication 581, Risk-Based Inspection Base Resource Document. Figure 7 provides a typical risk matrix generated from the API-RBI analysis. Although the methodology uses the risk assessment for inspection planning, it can also be used to plan for CMP implementation.

Figure 7 – A typical risk matrix generated by API-RBI software.

Since risk assessment represents a key requirement of CMP, the following is recommended:

Conduct an RBI study on YR CCR Platformer Plant V11 for prioritization of CMP implementation.

As for piping OSI data necessary for the study but are unavailable in the SAIF program, utilize the list of equipment and piping in Section 4 to estimate conservative corrosion rates for representative piping based on connected equipment at similar process conditions, materials of construction and potential damage mechanisms. Utilize resulting risk ranking to prioritize ongoing OSI to detect for identified potential DMs.

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6 Corrosion Management Strategies

The various methods of corrosion prevention, control and monitoring in CCR Platforming plants are described below:

6.1 Process Variables

The key primary process-related corrosion variables are high temperatures, corrosive liquids and gases, and erosive solids that can lead to excessive metal losses. Key areas of concern and process mitigation measures are discussed below:

6.1.1 Recycle Gas Moisture and Chlorides

High moisture in the recycle gas can accelerate corrosion in the net gas recontact and AET section in stagnant locations. Chloride stripped from the catalyst, upsetting the catalyst acid/metal balance, can later form HCl in the presence of water. This acid attacks the carbon steel drain systems and stainless steel valve internals. This is especially true if the affected drain piping was not sloped to allow for drainage.

To manage corrosion, the target recycle gas moisture level should be from 15 to 25 ppmv while ensuring the online moisture analyzer reliability to detect elevated level. Stable control of the catalyst chloride level should be maintained by reducing the average chloride level to 0.9 wt% for regenerated catalyst and 0.8 wt% for the spent catalyst. Another option is to use upstream chloride treaters to minimize chloride concentration circulation throughout the unit.

6.1.2 Catalyst Fluctuation Erosion

The catalysts piping and nozzles affected by frequent catalyst circulation rate fluctuation leads to high velocities that may increase erosion and metal loss. In the past, this has also caused undesirable hot shutdowns, leading to depressurization of the lock hopper and switching the CCR to black burn mode.

The circulation can be adjusted by continuously monitoring the CCR operating parameters, general operating curves or by reducing the operating severity.

6.1.3 Spent Caustic pH Control

The cause of the severe corrosion in the vent gas system is mostly due to acidic conditions resulting from pH control concerns, high chloride content of the feed and ineffective caustic neutralization. The resulting high solids content can also result in under-deposit corrosion

Operating guidelines include maintaining circulating caustic solution at target total alkalinity of 0.2 – 0.35 wt%, keeping the pH from 7.5 to 8.5, and maintaining total solids less than 1.0 wt% (10000 ppm).

6.1.4 Sea Water Chlorine Residuals

Widespread microbiological fouling can lead to severe corrosion and repeated failures of all metallurgies including 70-30 Cu-Zn and 90-10 Cu-Ni tubing and Monel weld overlays. The main causes are malfunctioning disinfecting chlorinators and problems

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with intake filters. Utilizing chlorine dioxide as an alternative provides superior disinfection by eliminating sessile biological films at a significantly lower cost.

Adequate chlorination of the cooling water make-up can be assured by maintaining a 0.5 – 2 ppm residual chlorine and performing routine monitoring of the microbiological profile of the cooling water such as GAB and SRB.

6.2 Materials Selection

The majority of the equipment and piping in a catalytic reformer is made of carbon steel unless the temperature is above 500 °F (260°C). The presence of hydrogen requires the use of low-alloy steels containing chromium, which prevent HTHA above 500 °F (260°C).

Stainless steel may also be used for internal surfaces that may come in contact with a mixture of hydrogen sulfide and hydrogen, which causes high-temperature sulfidation of steel.

6.2.1 Reactors

Reactors are heavy-walled vessels fabricated from chrome-bearing steels. The reactors in the combined feed are made of 2.25Cr–1Mo alloy to resist HTHA.

6.2.2 Exchanges and Piping

Heat exchanger metallurgy varies with stream composition and temperature. Feed/effluent exchanges and associated piping have to resist hydrogen on the feed side and hydrogen sulfide/hydrogen streams on the effluent side. Heat exchangers are mainly made of carbon steel except for the following cases:

1.25Cr–0.5Mo used for HTHA;

Cu-Ni alloys for sea water in non-hydrocarbon services;

Impact tested carbon steel for low temperature services.

The piping material used is mostly carbon steel except for the following cases:

Impact tested carbon steel for low temperature services;

1.25Cr–0.5Mo used for HTHA;

304H/316H SS for high temperature piping in the regenerator section;

316SS for corrosion resistance in the vent gas system piping system.

Nonmetallic materials can be utilized as piping material to handle corrosive fluids. Polytetrafluoroethylene (PTFE) or Polypropylene (PP) lined carbon steel pipework is suitable to handle cooling seawater and caustic solutions. Also Reinforced Thermoset Resin (RTR) pipes can be considered to handle corrosive water solutions.

6.2.3 Fired Heaters

Heater tubes are subject to high temperature corrosion both on the process side and in the fire-box. 2.25Cr–1Mo and 9Cr–1Mo alloys are commonly used in reactor section to resist hydrogen attack in furnace tubing while providing good oxidation resistance externally.

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6.3 Corrosion Monitoring and Inspection

6.3.1 Coupons

Retractable coupons can give reliable data under turbulent and laminar flow conditions. Typical locations for installing coupons are the susceptible locations of well known damage mechanisms such under deposit corrosion (MIC) and caustic and acid corrosion in seawater and vent gas systems, respectively.

Generally, corrosion coupons are removed on a 6-12 month frequency or sooner if high corrosion rates are observed either from past coupon/probe data or the OSI analysis. Coupon data needs to be supplemented by OSI inspection program to confirm results.

6.3.2 Probes

Probes offer the advantage of continuous data collection without the need for frequent replacements. However, if there is pitting or high velocity the thin probe element used can fail by fatigue. Below table listed all corrosion probes presently installed at V11 where all of these are showing acceptable readings at these locations.

Table 1 – Corrosion Probes’ Locations and Corresponding Corrosion Rates

Probe Number

Location Corrosion Rates (mpy)Maximum Average

V11-CE-0001 V11-E-0107 inlet (tube side) 0.7 0.14V11-CE-0003 V11-E-0109 outlet 0.2 0.03V11-CE-0005 V11-E-2 outlet 1.1 0.2V11-CE-0007 V11-E-0102 outlet 0.2 0.2V11-CE-0009 V11-E-0116 outlet 2 0.1

6.3.3 Non-Destructive Techniques

Details on corrosion monitoring and locations are provided in the individual potential DMs’ narrative provided in the Appendix II. Key areas of concern and monitoring highlights are provided below:

Corrosion Under Insulation is external corrosion of piping, pressure vessels and structural components resulting from water trapped under insulation or fireproofing materials. Vulnerable areas can be found in the recycle/net gas, AET and the propane refrigeration units. Multiple inspection techniques can be used to provide the most cost-effective approach. Below are some of these techniques:

Visual examination of partially or fully stripped insulation. UT inspection for thickness verification. Real-time profile x-ray (for small bore piping). Neutron backscatter techniques for identifying wet insulation. Deep penetrating eddy-current inspection (can be automated with a crawler). IR thermography to identify wet insulation and damaged insulation under the jacket

Creep can be observed in heater tubes, tube supports, hangers and other furnace internals. Monitoring techniques include:

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Visual examination for bulging, blistering, sagging, and diametrical expansion. UT, RT, Eddy Current Testing and/or diametrical measurements may be required to

assess remaining life as per API RP 579. Destructive sampling and metallographic examination are used to confirm and

determine the degree of creep damage and available remaining life. Life assessment calculation as per API 530 accounting for creep and metal loss.

HCl and Erosion Corrosion is usually inspected for using UT, but specialized corrosion coupons and on-line corrosion monitoring probes have been used in some applications.

HTHA usually occur in reactors, heater tubes, and piping/heat exchangers in high pressure H2 service. The Inter-Critical Heat Affected Zone (ICHAZ) of reactor welds, especially nozzle welds & downstream of mixing tees are more susceptible to HTHA. In terms of monitoring, HTHA can be detected through visual Inspection for blistering, metallographic replication, and hardness measurements to check for surface decarburization. Also, Time Of Flight Diffraction (TOFD) and Advanced Ultrasonic Backscatter Technique (AUBT) can be used for fissuring or internal cracking.

Chloride SCC can be monitored using SWUT (or TOFD) around butt welds during T&I

Under-deposit corrosion can occur in cooling water exchangers (biological), stagnant areas in the AET unit (chlorides) and relief valve dead legs (condensation). In cooling water systems, special probes have been designed to monitor for evidence of fouling which may precede or coincide with MIC damage. An increase in the loss of duty of heat exchangers may be indicative of fouling and potential MIC damage. Also, conducting UT and/or RT as part of the OSI program is recommended.

Caustic SCC can be can inspected for at weld HAZ, deadlegs, drains and other locations where caustic could concentrated. Crack detection is best performed with WFMT, EC, RT or ACF techniques. Surface preparation by grit blasting, high pressure water blasting or other methods is usually required. Additionally, crack depths can be measured by external SWUT.

6.4 Coatings

Engineered coatings are applied on various structures and operating equipment in the refinery externally or internally to protect against corrosion and erosion, act as thermal barriers, prevent fouling, etc. The engineered coating can be organic, metallic, ceramic or composite-based. Surface coating shall be considered as integral of the overall equipment.

6.4.1 Heaters

In high temperature applications, coatings can be applied on carbon steel shell under refractory and insulation, and welded anchors to serve as corrosion protection against acid gas dew point corrosion.

Ceramic (liquid) coatings can be applied (sprayed) externally on the heater tubes to prevent oxidation and scale build-up reducing the risks of hot spots and tube ruptures. This type of coating can be applied on the refractory surface to enhance its heat emissivities and reduce the fuel firing, reducing % of NOx and SOx in the flue gas. Also, ceramic (powder) coatings can be applied by thermal spraying on damper plates to prevent bulging and distortion.

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Advance coatings, with smart pigments and nano-fillers, are used to sense and monitor for over-heating. For example, temperature indication coatings are applied externally on refractory-lined equipment to detect for hot spots.

6.4.2 Insulated Piping, Fittings and Equipment

Special acrylic-based coatings with ceramic fillers can resolve the chronic hidden concerns with corrosion under thermal insulation. It can simply be applied on any surface with intricate shape without cladding.

6.4.3 Heat Exchangers

Thin film, heat-cured organic coating can be applied on the inner tube surface of heat exchangers in sea water service to avoid scaling and fouling build-up. The coating will enhance the flow through the tubes and exchanger duty.

6.4.4 Vessel, Drum, Tanks

Organic composite coatings with glass, ceramic or metals can be applied internally to protect equipment from corrosion and chemical attack up to 120oC in wet conditions and up to 180oC in dry conditions.

6.4.5 Instrumentation

Level gauges can be lined with chemical and corrosion resistance PTFE. Also, temperature sensing probes in corrosive service can be lines with glass type coating for reliable and accurate measurement.

6.4.6 Fasteners

Bolts and nuts in sweating piping and are insulated can be coated with PTFE type coating with dual coats (primer + top coat) as per 09-SAMSS-107.

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7 Plant Integrity Windows

Tables 2 (a,b) and 3 (a,b,c) list the customized, unit-specific Plant Integrity Windows (PIWs) based on the observations listed in Assessment Findings. The below tables provide the PIWs locations, variable names, DCS tag numbers, limits, urgency, consequences, and required action. These variables and others developed in conjunction with the PIW Team will be provided online to YR for their utilization.

Table 2 (a) – Plant Integrity Windows for YR Plant V11 Platformer Section #1

Location/EquipmentPlatformer Hydrotreated

Naphtha Feed Vertical Combined Feed

Exchanger V11-E-1AVertical Combined Feed

Exchanger V11-E-1BVertical Combined Feed

Exchanger V11-E-1CVertical Combined Feed

Exchanger V11-E-1D

Variable (Tag Name)

Nitrogen in Platformer Feed Hot End Approach Temperature

Hot End Approach Temperature



Tag # Not Available 11TI0232.PV - 11TI0210.PV 11TI0235.PV - 11TI0210.PV 11TI0242.PV - 11TI0210.PV 11TI0245.PV - 11TI0210.PV

Upper Safety Limit

Upper Integrity LimitUpper Performance Limit

0.5 110 110 110 110

Lower Performance Limit

80 80 80 80

Lower Integrity Limit

Lower Safety Limit

Unit ppmw oC oC oC oCControl (M. S.) Lab DCS DCS DCS DCS

Frequency W ----- ----- ----- -----

Urgency H H H H H

Consequences

Plugging and corrosion of Platformer equipment such as vertical combined feed exchangers, recycle and net gas compressors, and debutanizer overhead due to ammonium chloride deposits.

Additional load on Platformer furnaces which requires reducing Platformer feed rateIncreased tube skin temperature and reduced radiant tube life which could lead to Heater radiant tube failure.Reduced Platformer heater refractory life.




Possible Root Causes

Change of feed source due to improper operation of upstream units and/or nitrogen ingress with feed due to improper NHT operation.

Tube side fouling, Sulfiding agent / filmer interaction




Action Required

Reduces the N2 level of the feed, do mitigation with corrosion group & inspection.

Reduce Platformer feed rate and plan for cleaning with specialized contractor, calculate LMTD




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Table 2 (b) – Plant Integrity Windows for YR Plant V11 Platformer Section #2

Location/EquipmentPlatformer Recycle Gas Compressor V11-C-1 A/B

Platformer Recycle Gas Compressor V11-C-1 A/B

Platformer Recycle Gas Compressor V11-C-1 A/B

Platformer Net Gas to AET System

Variable (Tag Name)

Recycle Gas Moisture Recycle Gas HCL Recycle Gas H2S Net Gas Moisture

Tag # 11AI0843.PVManual (Need to be

automated)Manual (Need to be

automated)Not Available

Upper Safety Limit

Upper Integrity Limit 30 5 2 30

Upper Performance Limit

25 3 1


15 1 0.5

Lower Integrity Limit 5 5

Lower Safety Limit

Unit ppmv ppmw ppmw ppmv

Control (M. S.) DCS Other Other Other

Frequency ----- D D D

Urgency H H H H

Consequences

High: increases coke make, reduces recycle gas H2 purity, increases light ends production, and causes severe corrosion in downstream piping and equipment

High: Causes severe corrosion in downstream piping and equipment

High: Deactivates the platforming catalyst and causes severe corrosion in downstream piping and equipment

High: causes severe corrosion in downstream piping and equipment


Water ingress with feed due to improper operation of NHT Stripper, poor initial drying, high water injection rate, and steam leak to Recycle Gas.

High chloride injection rate and leaching of chloride from the catalyst.

Sulfur ingress with feed due to improper NHT operation and incorrect measurment of the sulfur injection rate.

Water ingress with feed due to improper operation of NHT Stripper, poor initial drying, high water injection rate, and high moisture content of the reduction gas vent.

Action Required

Reduce Platformer severity to 98 RON while adjusting the chloride injection and correcting the Stripper operation.

Reduce Platformer severity to 98 RON and adjust the chloride injection .

Reduce Platformer severity to 98 RON and adjust the chloride injection while checking the sulfur injection and Stripper operation.

Adjust the operation of the recovery plus unit (increasing chiller outlet tempeeratur) and check source of the high moisture.

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Table 3 (a) – Plant Integrity Windows for YR Plant V11 CCR Section #1

Location/Equipment Platformer Reactors Disengaging Hopper Regeneration Tower Regeneratoion Tower

Variable (Tag Name)

Spent Catalyst Lift Gas Velocity

Elutriation Gas Velocity Chloride Makeup Rate Regenerated Catalyst Chloride

Tag # Calc. Calc.V11-SP-7-02.CLWT - V11-

SP-7-01.CLWTV11-SP-7-02.CLWT

Upper Safety Limit

Upper Integrity Limit 1.1


5.5 2.4 0.3 1


0.1 0.8

Lower Integrity Limit

Lower Safety Limit

Unit m/s m/s wt% wt%

Control (M. S.) Cal Cal Lab Lab

Frequency ----- ----- 3PW 3PW

Urgency H H H H

Consequences

Accelerated Loss of metal at bends of catalyst lift line due to erosion, Leaks, H2 Fire, , and increase of catalyst fines.

Loss of metal at bends and increase of catalyst fines generation at the upper limit while allowing catalyst chips and fines to enter the regeneration tower and plug the screen at the lower limit.

Higher makeup rate indicates higher injection rate which causee severe corrosion and more severity

High chloride level increases coke make, reduces recycle gas H2 purity, increases light ends production, and causes severe corrosion


Erosion due to high lift gas flow, change of lift gas hydrogen purity

Erosion due to high elutriation gas velocity

High severity operation and loss of catalyst surface area

Loss of chloride injection control and/or excessive chloride injection.

Action Required

Optimize lift line operating parameters (Lift line flow, lift gas quality)

Optimize Elutriation gas operating parameters (Elutriation line gas flow, gas quality)

Adjust the chloride injection while checking for the right causes

Reduce reactors temperature while adjusting the chloride injection

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Table 3 (b) – Plant Integrity Windows for YR Plant V11 CCR Section #2

Location/Equipment Vent Gas Wash Tower Vent Gas Wash Tower Vent Gas Wash Tower Sea Water Cooler Fouling/Corrosion

Variable (Tag Name)

Spent Caustic Total Alkalinity

Spent Caustic pH Spent Caustic Total Solids

Chlorine Dioxide Residual

Tag # V11-SP-6-03.NAOHC V11-SP-6-03.PH V11-SP-6-03.TSNot Available "New chlorination system will be installed in the

near future"

Upper Safety Limit

Upper Integrity Limit 0.35 10000.0 0.5


8.5 0.5


7.5 0.1

Lower Integrity Limit 0.2 1000 0.1

Lower Safety Limit

Unit wt% pH ppmw ppm

Control (M. S.) Lab Lab Lab Lab

Frequency D D D Daily (during treatment period)

Urgency H H H H

Consequences

HCl corrosion of vent gas system at lower limit.Deposit formation at upper limit.

HCl corrosion of vent gas system at lower limit.Deposit formation at upper limit.

Lead to increase of under deposit corrosion

Fouling of cooling seawater system and exchangers


Causes for corrosion are lack of pH control due to excessive chlorides in vent gas and loss of caustic injection flow while causes forvdeposit formation are increase of caustic injection flow and high chloride level in the vent gas.

Lack of pH control due to excessive chlorides in vent gas and loss of caustic injection flow

Increase of caustic injection flow

Malfunction of chlorine dioxide generating unit

Action Required

Check and Adjust caustic injection flow, water injection flow and/or spent caustic flow

Check and Adjust caustic injection flow

Check and Adjust caustic injection flow, increase water injection flow and/or spent caustic flow

Alert Utilities

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Table 3 (c) – Plant Integrity Windows for YR Plant V11 CCR Section #3

Location/Equipment Dust Collector Dust Collector Lock Hopper Lock Hopper

Variable (Tag Name)

Mesh Size 14 & 16 of Catalyst Fines

Catalyst Fines Rate Regenerated Catalyst Lift Gas Velocity

Catalyst Circulation

Tag #V11-SP-FD.SIEVEUS14 + V11-SP-FD.SIEVEUS16

Calc. (Catalyst Fines Weight needs to be automated to enable

automatic calculation of fine make rate)

Calc. 11FI0181.PV

Upper Safety Limit

Upper Integrity Limit 0.03 100


35 7.6 90


15 60

Lower Integrity Limit 50

Lower Safety Limit

Unit % wt% CCR m/s %

Control (M. S.) Lab Other Cal DCS

Frequency W W ----- -----

Urgency H H H H

Consequences

Loss of metal at bends of catalyst lift line due to erosion, Leaks, H2 Fire, , and increase of catalyst fines.

Increase of catalyst fines generation causes unstable CCR opeeration leading to shutdown.

Accelerated Loss of metal at bends of catalyst lift line due to erosion, Leaks, H2 Fire, and increase of catalyst fines.

Unstable CCR operation and Erosion in the catalyst lift lines



Erosion due to high elutriation gas velocity


Measurement not accurate, abnormal CCR operating parameters, increase catalyst fines generation, and higher operating severity

Action Required


Optimize Elutriation gas operating parameters (Elutriation line gas flow, gas quality)


Check CCR operating parameters and check general operating curve

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8 CMP Dashboard

The CMP dashboard is a visual display of the high level, corrosion-related performance variables with color-coding to indicate compliance to set limits to adequately manage corrosion. Table 4 provides the dashboard for YR CCR Platformer Plant V11 based on PIWs from previous Section 7 and key performance indicators (KPIs) provided in Appendix II & Appendix III.

Table 4 – Corrosion Performance Dashboard for YR CCR Platformer Plant V11

Performance Measure Timescale KPI Method Compliance Deviation Impact

Corrosion-Related PIWs within Limits

Daily 100% CMP Dashboard

Based on individual PIW

TMLs with High Corrosion Rates(> 5 mpy)

Quarterly 0 SAIF Corrosion

Chemical Treatment Program Performance

Annually 100% Lab Sampling Corrosion and/or Fouling

Critical Corrosion Failures

Annually 0 Investigation Reports

Plant availability and Mechanical Integrity

Lost Profit Opportunity due to Corrosion

Annually 0 $$ Manufacturing Planning

Profitability

Significant (negative) deviation from targetModerate (negative) deviation from targetCompliance with or exceeds target

9 Technologies

9.1 On-line Clamp-On Erosion-Corrosion Monitoring System

The monitoring system is a non-intrusive device that enables measurement of corrosion or erosion damage in piping. It is based on acoustic guided lamb wave’s techniques. Utilizing this approach will provide flexibility in selecting the monitoring locations in congested areas where tools required maintaining intrusive devices may not have enough space function. It can enhance the plant safety and reliability by identifying and monitoring the loss in the pipe wall thickness. Corrosion detected by these devices could then be addressed through implementing appropriate corrosion mitigation measures.

The subject system has been installed, as a field trial, downstream of the heat exchanger V14-E-0103 B to Debutanizer (V14-V1). Currently, the technology is available to all producing, pipelines, gas plants and refineries departments.

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9.2 Protective Coatings

The following are some coating technologies that can used by YR CCR Platformer Plant:

9.2.1 Thermal insulating coating can be used for cooled hydrogen piping and exchangers as an alternative to exiting insulation on equipment, piping and valves.

9.2.2 Ceramic coatings can be used for heater tubes and refractory. They can:

prevent oxidation and scale build-up on the tubes, thus extending tube life obtain uniform tube wall temperature with lower fuel firing, thus preventing

overheating and subsequent tube rupture enhance heat emissivity of refractory, thus increasing radiant heat transfer

efficiency, protecting against flue gas erosion, and preventing dust accumulation lower corrosive NOx and CO2 emission with efficient heater performance

9.2.3 Thermal barrier coating for heaters damper plate to prevent over-heating damage.

9.2.4 Temperature indicating coating on refractory lined equipment to indicate hot spots.

9.2.5 Thin film, heat cured modified phenolic coating for heat exchanger tubes in sea water service. It can protect against corrosion and reduce fouling by reducing the surface tension and the ability of micro and macro foulants to adhere to tube surface.

9.2.6 PTFE linings can be used for instrumentation piping and bridles.

9.2.7 Glass lining can be used on temperature thermowell probes.

9.3 Deployment of Non-Metallics & Composites

The use of nonmetallic material products should be considered to control corrosion in YR CCR Platformer Plant V11. The following are some of the technologies to be considered:

9.3.1 Thermoplastic lined carbon steel according to 12-SAMSS-025 or ASTM F1545: Polytetrafluoroethylene (PTFE) or Polypropylene (PP) lined carbon steel pipework is suitable to handle cooling seawater and caustic solutions. This technology can be utilized to replace the existing venturi discharge piping to the wash tower; and the seawater cooling piping system.

9.3.2 Reinforced Thermoplastic Pipe (RTR): RTR pipe to handle corrosive water such as seawater cooling water. RTR should be considered to replace the existing cement lined carbon steel piping system.

9.3.3 Composite Repair: Composite repair systems can be utilized to restore the integrity of pipes with wall thickness loss due to corrosion or erosion such as the seawater cooling water piping system which shows leaking defects in several locations.

9.3.4 Nonmetallic Pumps: Composite or thermoplastic pumps are an alternative material to control corrosion and avoid the constant maintenance cost of the existing metallic pumps in caustic service which show recurrent failures..

9.3.5 Nonmetallic Fiber Reinforced Plastic (FRP) Tanks: FRP material can be utilized to manufacture caustic solution storage tanks as a cost-effective alternative.

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10 Assessment Findings

Details of the assessment findings made in conjunction with CMP deployment at YR CCR Platformer Plant V11 are given in Appendix III. This table also provides possible root causes, recommendations, associated gaps in the work processes and attributes, associated PIWs, KPIs, assigned priority, and phased at which the gap occurred in the assets’ life cycle. This information is also included in the Asset Performance Management (APM) program report for integration and consolidation with other APM teams’ findings and recommendations.

The top corrosion challenges from the assessment findings were previously presented in Section 3 of this report.

11 References

11.1 Saudi Aramco References

Saudi Aramco Engineering Procedure

SAEP-1135 On-Stream Inspection Administration

Saudi Aramco Engineering Standards

SAES-A-007 Hydrostatic Testing Fluids and Lay-Up Procedures

SAES-H-001 Coating Selection & Application Requirements for Industrial Plants and Equipment

SAES-L-132 Material Selection for Piping Systems

SAES-L-133 Corrosion Protection Requirements for Pipelines, Piping and Process Equipment

SAES-W-010 Welding Requirements for Pressure Vessels

SAES-W-011 Welding Requirements for On-Plot Piping

Saudi Aramco Materials System Specifications

01-SAMSS-035 API Line Pipe

Saudi Aramco Best Practices

SABP-A-033 Corrosion Management Program (CMP) Manual (Volume 3 of 3) - Damage Mechanism Narratives

Saudi Aramco Engineering Report

SAER-6344 Corrosion Control Document - ShGP CCD-1 ShGP Gas Treat Units #1/2/3/4

11.2 Industry Codes and Standards

American Petroleum Institute

API STD 530 Calculation of Heater Tube Thickness in Petroleum Refineries

API RP 570 Inspection, Repair, Alteration and Rerating of In-Service Piping Systems

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API RP 571 Damage Mechanisms Affecting Fixed Equipment in the Refining Industry

API RP 579 Fitness-for-Service

API PUB 581 Risk-Based Inspection Base Resource Document

API RP 941 Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants

National Association of Corrosion Engineers

NACE RP 0198 The Control of Corrosion Under Thermal Insulation and Fireproofing Materials - A Systems Approach

NACE SP 0403 Avoiding Caustic Stress Corrosion Cracking of Carbon Steel Refinery Equipment and Piping

NACE SP 0590 Prevention, Detection, and Correction of Deaerator Cracking

11.3 Publications

Metals Handbook, “Corrosion,” Volume 13, ASM International

D.N. French, “Metallurgical Failures in Fossil Fired Boilers,” John Wiley & Sons, Inc., NY, 1993.

Corrosion Basics – An Introduction, NACE International

Revision Summary23 July 2011 New Saudi Aramco Engineering Report.

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Appendix I – YR CCR Platformer Plant V11 Corrosion Loop Drawings

Corrosion Loops Diagram No. 1 (CLD-1) for YR CCR Platformer Plant V11

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SAER-6353 Corrosion Control Document - Yanbu Refinery CCR Platformer Plant V11

Issue Date: 23 July 2011 Next Planned Update: 1 August 2012

Appendix II – YR CCR Platformer Plant V11 Customized Damage Mechanism Narratives

The damage mechanisms identified during the corrosion loop development have been addressed in the below narratives customized to YR CCR Platformer Plant V11.

6.1 Creep/Stress Rupture (SA-03)

Damage Mechanism Creep/Stress RuptureDamage Description Occurs at high temperatures due to deformation of stressed components

under loads below yield stress.Deformation leads to damage that may eventually lead to a rupture.Creep damage is not reversible. Once detected, much of the life has been

used up and the options are to repair or replace.Affected Materials &

EquipmentAll metals and alloys.Susceptible equipment are the H-1, 2, 3 and F-0101 heater tubes.Heater tubes in fired heaters are especially susceptible as well as tube

supports, hangers and other furnace internals.Control Methodology Generally, increases of 25°F (12°C) or 15% on stress can cut the remaining

life in half or more, depending on the alloy.· Alloys with improved creep resistance may be required for longer life.

Heaters should be designed and operated to minimize hot spots and localized overheating

Minimizing process side fouling/deposits and fire side deposits/scaling can maximize tube life.

Monitoring Techniques · Visual inspection for bulging, blistering, cracking, sagging, bowing & diametrical expansion.

UT, RT, Eddy Current Testing and/or diametrical measurements may be required to assess remaining life per API RP 579.

Destructive sampling and metallographic examination are used to confirm damage and conduct testing to determine degree of creep damage and available remaining life

Calculation life assessment per API530 taking into account both creep and metal loss

Inspection Frequency Most inspections are performed at every T&IKPIs Number of visual/NDT inspections carried out

Number of tube failuresReferences API RP571 (DM #3)

API Standard 530API RP579, Fitness-For-Service

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6.2 HCl Corrosion (SA-09)

Damage Mechanism HCl CorrosionDamage Description Hydrochloric acid (aqueous HCl) causes both general and localized

corrosion.Damage is most often associated with dew point corrosion where vapors

containing water and hydrogen chloride condense. The first water droplets that condense can be highly acidic (low pH) and promote accelerated attack.

Dry HCl is normally not corrosive.The critical factors are HCl acid concentration, temperature and alloy

composition. The severity of corrosion increases with increasing HCl concentration, temperature and oxidizing agents (oxygen, ferric and cupric ions).

Affected Materials & Equipment

Carbon steel and low alloy steels are subject to excessive corrosion at pH below about 4.5. 300 and 400 series SS are subject to pitting attack. Alloy 400, titanium and some nickel base alloys have good resistance.

Chlorides may be stripped from the catalyst and react to form HCl that carries through the effluent trains, regeneration system (stagnant and relief valve piping) as well as the recycle, net gas and fuel gas systems.

Serious corrosion can also be found at mix points where dry chloride containing vapors mix with streams containing free water or where water saturated streams are cooled below the dew point.

Control Methodology Special adsorbents in chloride beds and chloride treaters can be used to remove chlorides.

Minimize carryover of water and chloride salts from upstream units including neutralizing amine hydrochloride salts.

Maintain regenerated catalyst chloride between 0.9 to 1 wt% and moisture level 15 to 25 ppmv to minimize corrosion in the net gas, recontact and AET sections.

Selective use of corrosion resistant nickel base alloys.Monitoring Techniques Strategically placed corrosion probes and/or corrosion coupons

Chloride levels in the Platformer unit gas stream and the AET unit inlet and outlet gas streams

Inspection Frequency Locally thinned areas can be found by using automatic ultrasonic scanning methods or profile radiography.

KPIs Chloride Level ExceedancesCorrosion Rates

Reference Resources API RP571(DM #9)

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(Standards/GIs/BPs)Metals Handbook, “Corrosion,” Volume 13, ASM International

6.3 High Temperature Hydrogen Attack (SA-10)

Damage Mechanism High Temperature Hydrogen Attack (HTHA)Damage Description Hydrogen decomposes into atomic hydrogen at the surface and enters the

steel. At the elevated temperatures, this hydrogen reacts with carbon (from carbides) to form methane (CH4) at grain boundaries. The resulting decarburization lowers material strength.

Methane pressure builds up, forming bubbles or cavities, and microfissures at grain boundaries. Eventually, fissures may combine to form cracks. Blistering at internal locations may also occur at an advanced stage.

Failure can occur when the cracks reduce the load carrying ability of the pressure containing part.


In order of increasing resistance: carbon steel, 1Cr-0.5Mo, 1.25Cr-0.5Mo, 2.25Cr-1Mo, 2.25Cr-1Mo-V, 3Cr-1Mo, 5Cr-0.5Mo.

Reactors and heater tubes are the main focus. Also, piping & heat exchangers in the high pressure hydrogen circuits (reactor and booster gas sections) should be considered.

Inter-Critical Heat Affected Zone (ICHAZ) of reactor welds, especially nozzle welds & downstream of mixing tees are more susceptible to HTHA

Control Methodology Use Cr-Mo steels per Nelson Curve described in API 941.Verify that the proper steel has been installed and that the proper weld

metal has been used in all the areas where HTHA is likely. PMI the unit for rogue material in HTHA environment

Follow temperature limits of API RP 941 curves for specific alloys, with a 50 F (28 C) safety factor

An integral austenitic stainless steel cladding or weld overlay would be expected to reduce the effective hydrogen partial pressure acting on the underlying base metal. Ferritic or martensitic stainless steel cladding would not be expected to provide a similar benefit.

Monitoring Techniques Visual Inspection for blisteringMetallographic replication and hardness checks to check for surface

decarburization, i.e. early signs of HTHATime Of Flight Diffraction (TOFD) and Advanced Ultrasonic Backscatter

Technique (AUBT) for fissuring or internal crackingInspection Frequency Visual examination, metallographic replication and hardness checks at

every T&I.Temperature trends and major process upset or temp. excursion

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AUBT at susceptible locations if metallurgical replication shows evidence of carburization

KPIs Number and duration of temperature exceedances.Number of Inspections Completed

References API 571 (DM #10), API 941, API 581 BRD for R

6.4 Oxidation (SA-11)

Damage Mechanism OxidationDamage Description Oxygen reacts with carbon steel and other alloys at high temperature

converting the metal to oxide scale. It is most often present as oxygen in the surrounding air (approximately 20%) used for combustion in fired heaters and boilers.

Oxidation of carbon steel begins to become significant above about 1000F (538C), 1.25Cr-0.5Mo at xxxxF and 2.25Cr-1Mo at xxxxF. The 300 Series SS are resistant to scaling up to about 1500F (816C).


Carbon steel and low alloy steels.All 300 Series SS, 400 Series SS and nickel base alloys also oxidize to

varying degrees, depending on composition and temperature.The fired heaters (H-1, 2, 3) in the reactor section with 21/4 Cr–1Mo tubes

and the 304/316 SS in the regenerator section can be particularly susceptible.

Control Methodology Establish a maximum oxidation temperature given by API 571. Note that these maximum temperatures are also limited by creep (per API 530) and may be lower.

Resistance to oxidation is best achieved by upgrading to a more resistant alloy.

Chromium is the primary alloying element that affects resistance to oxidation.

Strictly avoid scaling as this generally indicates that a metal has been exposed to a temperature exceeding its high temperature mechanical capability (i.e. it is in the creep range).

Monitoring Techniques Process conditions should be monitored for establishing trends of high temperature equipment where oxidation can occur.

Temperatures can be monitored through the use of tube skin thermocouples and/or infrared thermography.

Loss in thickness due to oxidation is usually measured using external ultrasonic thickness measurements and radiography.

Inspection Frequency NDE and visual inspection at T&IInfrared surveys at regular intervals

KPIs Temperature ExceedancesReference Resources API 571 (DM #11)

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(Standards/GIs/BPs)API 579 Part 11API 530

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6.5 Thermal Fatigue (SA-12)

Damage Mechanism Thermal FatigueDamage Description · Thermal fatigue is cracking due to the result of cyclic stresses

caused by variations in temperature. Damage frequently occurs where relative movement or differential expansion is constrained, particularly under repeated thermal cycling.

The cracks usually initiate on the surface of the component and are generally wide and often filled with oxides due to elevated temperature exposure. Cracks may occur as single or multiple cracks. They generally propagate transverse to the stress and they are usually dagger-shaped and transgranular.

Key factors are the magnitude of the temperature swing and stresses and the frequency (number of cycles). Time to failure decreases with increasing stress and increasing cycles.

Start-up and shutdown of equipment increases susceptibility to thermal fatigue. As a practical rule, cracking may be suspected if the temperature swing exceeds about 200°F (93°C).

Damage is also promoted by rapid changes in surface temperature that result in a thermal gradient through the thickness or along the length of a component

Materials & Equipment All materials of construction are affected.Susceptible equipment are in the reactor and regenerator sections including

the reactors, heat exchangers, welds and piping connections.Notches (such as the toe of a weld) and sharp corners (such as the

intersection of a nozzle with a vessel shell) and other stress concentrations may serve as initiation sites.

Control Methodology Thermal fatigue is best prevented through design and operation to minimize thermal stresses and thermal cycling. These include:

Designs that incorporate reduction of stress concentrators, blend grinding of weld profiles, smooth transitions and sufficient flexibility to accommodate differential expansion.

Controlled rates of heating and cooling during startups and shutdowns.Considering differential thermal expansion between adjoining components

of dissimilar materialsMonitoring Techniques VE, MT and PT are effective methods of inspection.

External SWUT and TOFD can be used for NDTHeavy wall reactor internal attachment welds can be inspected using

specialized ultrasonic techniques.Inspection Frequency Periodic at T&IsKPIs # of failures

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References API RP-571 (2003)

6.6 Caustic SCC (SA-18)

Damage Mechanism Caustic SCCDamage Description Characterized by surface cracks primarily adjacent to non-PWHT’d welds.

Cracking is always intergranular in carbon steels. Caustic concentration exceeding 5 wt% in the aqueous phase can produce

SCC in CS. It can occur at lower levels due to local concentration effects by evaporation.

It occurs at temperatures from~46°C(115°F) to boiling.Affected Materials &

EquipmentCarbon steel, low alloy steels and 300 Series SS are susceptible. Equipment affected is in the vent gas caustic injection system and

neutralization. This includes piping, tankage, pumps, exchangers and valves.

Control Methodology Cracking can be effectively prevented in carbon steels by PWHT, up to a given service temperature that depends on caustic concentration. This also applies to repair welds and internal and external attachment welds.

Above certain caustic concentrations and temperatures, 300 Series SS offer little advantage in resistance over CS.

Steam out of non-PWHT’d carbon steel must be avoided. Equipment can be water washed before steam out to remove all traces of caustic.

Monitoring Techniques Inspect for cracking at weld HAZs at deadlegs/drains & other locations where caustic concentrations could occur

Crack detection is best performed with WFMT, EC, RT or ACF techniques. Surface preparation by grit blasting, high pressure water blasting or other methods is usually required.

Crack depths can be measured by external SWUT.AET can be used for monitoring crack growth and locating growing cracks.

Inspection Frequency Internally inspect vulnerable locations every T&IKPIs Caustic concentration

· Temperatures References API RP571 (DM #18)

API 581-2008NACE SP0403-2008

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6.7 Caustic Corrosion (SA-19)

Damage Mechanism Caustic CorrosionDamage Description Localized corrosion due to the concentration of caustic or alkaline salts that

usually occurs under evaporative or high heat transfer conditions. However, general corrosion can also occur depending on alkali or caustic solution strength.


Carbon Steel, low alloy steels and 300 Series Stainless Steel.Equipment in the vent gas caustic injection system during long periods of

shutdown.Control Methodology Shutdown corrosion in the vent gas caustic injection system can be

controlled by flushing the system and proper mothballing procedure (SAES-A-007).

In process equipment, caustic injection facilities should be designed to allow proper mixing and dilution of caustic in order to avoid the concentration of caustic on hot metal surfaces.

Carbon steel and 300 Series SS have serious corrosion problems in high strength caustic solutions above about 150F (66oC). Alloy 400 and some other nickel base alloys exhibit much lower corrosion rates.

Monitoring Techniques For process equipment, UT and RT are useful to detect and monitor general corrosion.

Injection or mixing points should be inspected in accordance with API 570.Inspection Frequency UT, coupons and visual inspection at T&IKPIs Corrosion Rate

# of leaksReferences API 571 (DM #19)

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6.8 Erosion/Erosion-Corrosion (SA-20)

Damage Mechanism Erosion – CorrosionDamage Description Erosion is the accelerated mechanical removal of surface material as a

result of relative movement between, or impact from solids, liquids, vapor or any combination thereof.

Erosion-corrosion occurs when corrosion contributes to erosion by removing protective surface films or scales.

Metal loss rates depend on the size, hardness, velocity and concentration of impacting particles, the hardness and corrosion resistance of material and the angle of impact.

Damage is characterized by localized loss in thickness, as pits, grooves, gullies, waves, rounded holes and valleys, often exhibiting a directional pattern. Failures can occur in a relatively short time.


All materials of construction: metals, alloys and refractories. Some alloys have recognized fluid & gas velocity limits to minimize erosion/erosion-corrosion, e.g. alloys for seawater service.

Susceptible equipment are catalyst piping and nozzles, dust fines piping and regenerator section piping and heat exchangers

Control Methodology Consider design improvements involving changes in shape, geometry and materials selection, e.g. increasing the pipe diameter to decrease velocity; streamlining bends to reduce impingement; increasing the wall thickness; and using replaceable impingement baffles

Improved resistance can be achieved through increasing substrate hardness using harder alloys, hardfacing or surface-hardening treatments.

Erosion-corrosion is best mitigated by using more corrosion-resistant alloys and/or altering the process environment to reduce corrosivity.

Heat exchangers utilize impingement plates and occasionally tube ferrules to minimize problems.

Monitoring Techniques Visual, UT and RT of vulnerable locations such as bends, elbows, tees and reducers; injection points, downstream of letdown valves and block valves, heat exchanger tubing.

Specialized corrosion coupons and on-line corrosion monitoring electrical resistance probes have been used in some applications

Inspection Frequency OSI TMLs for pipingKPIs Piping erosional velocity limits (per SAES-L-132) exceedances

Solids/catalyst concentration References API 571 (DM #20)

API 570SAES-L-132

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6.9 Chloride SCC (SA-23)

Damage Mechanism Chloride SCCDamage Description Surface initiated cracks caused by environmental cracking of 300 series SS

under the combined action of tensile stress, temperature and an aqueous chloride environment. The presence of dissolved oxygen increases the cracking susceptibility. Trace levels of chloride can concentrate even at very low levels

Branched, mostly transgranular cracks with a crazed or spider-web and brittle appearance.

This can occur in the regenerator section during shutdowns - 304H SS (drying section) and 316SS (coke burning, chlorination/oxidation and vent gas piping)


300 Series austenitic stainless steels ≥ 60⁰CDuplex stainless steels ≥ 130⁰C, depending on the grade and heat treatment

Control Methodology Use more resistant materialsAvoid designs that allow stagnant areas where chlorides can concentrate or

deposit. Slope to drain with no pocketsIf problematic, replace socket welds with resistant materials (Alloy 625,

825)When hydro testing austenitic stainless steel, use low chloride content

water. Follow SAES-A-007Do not soda ash wash equipment that cannot be fully drained.Maintain tight control of soda ash chloride impurities in accordance with

SABP-A-001.Monitoring Techniques Monitor chloride in soda ash per SABP-A-001 and RIMs

Shear wave UT (or Time Of Flight Diffraction) around butt welds during the T&I

PT of exposed surfacesInspection Frequency Shear wave 10% of butt welds during each T&I at selected high risk

locationsKPIs Chloride level exceedances

# of cracks foundReference Resources

(Standards/GIs/BPs)API RP571(DM #23)SAES-A-007SAES-L-133

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6.10 Steam Blanketing (SA-26)

Damage Mechanism Steam BlanketingDamage Description The flow of heat energy through the tube wall results in the formation of

discrete steam bubbles (nucleate boiling) on the ID surface. The moving fluid sweeps the bubbles away. When the heat flow balance is disturbed, individual bubbles join to form a steam blanket, a condition known as Departure from Nucleate Boiling (DNB). Once a steam blanket forms, tube rupture can occur rapidly, as a result of short term overheating, usually within a few minutes.

These failures always show an open burst with the fracture edges drawn to a near knife-edge. The microstructure reveals severe grain structure elongation due to the plastic deformation.

Failure occurs as a result of the hoop stress in the tube from the internal steam pressure at the elevated temperature.

Heat flux and fluid flow are critical factors. On the water side, anything that restricts fluid flow (for example, pinhole leaks lower in the steam circuit) can lead to steam blanketing conditions.


rbon steel and low alloy steels in the Waste Heat Boiler

Control Methodology Proper Boiler Feed Water (BFW) treatment can help prevent some conditions that can lead to restricted fluid flow.

Maintain uniform flue gas flowMonitoring Techniques Tubes should be visually inspected for bulging Inspection Frequency Routinely during normal operator rounds and at the T & IKPIs # of Tube FailuresReference Resources

(Standards/GIs/BPs) API RP571 (DM #26)D.N. French, “Metallurgical Failures in Fossil Fired Boilers,” John Wiley

& Sons, Inc., NY, 1993.

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6.11 Short-Term Overheating (SA-30)

Damage Mechanism Short-Term OverheatingDamage Description Permanent deformation, typically from 3% to 10%, occurring at relatively

low stress levels as a result of localized overheating.Eventually results in bulging and failure by stress rupture characterized by

open “fishmouth” and with thin lip fracturesIn ferritic steels, bulging is typically associated with local microstructural

changes that confirm high temperature exposure It is a fairly common in utility boiler tubes and is sometimes associated

with starvation (loss of steam/water on the tubeside). Overheating may also be caused by deposit built-up inside furnace tubes or

in streams with coking tendencies. Affected Materials &

Equipment All fired heater and boiler tube materials.Susceptible equipment are the H-1, 2, 3 and F-0101heater tubes.

Control Methodology Verify the material selection conform to the design temperatures and pressure and that metal temperatures do not exceed design limits

Monitor for flame impingement using visual inspection via peep holes, or local overheating with.

Fired heaters require proper burner management and fouling/deposit control to minimize hot spots and localized overheating.

Utilize burners which produce a more diffuse flame pattern.Perform remaining life assessment per API Standard 530 or API RP 579 to

determine the impact of having higher temperature than normal.

Monitoring Techniques In fired heaters, visual observation, tubeskin thermocouples, infrared guns or thermography are used to monitor temperatures.

Check for distortion and diametric growth during turnaround inspection.Metallographic replication and hardness testing can be used for micro-

structural categorization to detect overheatingInspection Frequency Monitor temperature trends every shift especially in hotter/outlet sections

of fired heatersInternal inspection and diametric dimensional checks at T&IMetallographic replication and hardness testing after process upsets or

temperature excursions. KPIs # of internal visual inspection

# of temperature excursions (over design limits) and durationsReferences API RP571 (DM #30)

API Standard 530API RP 579, Section 10

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6.12 Brittle Fracture (SA-31)

Damage Mechanism Brittle Fracture Damage Description Sudden rapid fracture under stress (residual or applied) where the material

exhibits little or no evidence of ductility or plastic deformation.


Carbon steels and low alloy steels are of prime concern, particularly older steels.

Areas having impact tested carbon steel including the net gas, AET and propane refrigeration sections.

Control Methodology Brittle fracture is best prevented by using materials specifically designed for low temperature operation.

Control the operating conditions (pressure, temperature), minimizing pressure at ambient temperatures during startup and shutdown, and periodic inspection at high stress locations.

Establish the minimum pressurization temperature (MPT) from reactor manufacturers or derive from Charpy tests conducted with samples removed from the vessel.

Monitoring Techniques Inspect to verify that reactors are crack-free, since defects promote brittle fracture.

Inspection Frequency Every T&I to check for cracks by visual and conventional Non-Destructive Testing

KPIs MPT deviations· Number of cracks found and repaired

References API RP571 (DM #31)API RP 579, Fitness-For-Service

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6.13 Corrosion Under Insulation (SA-46)

Damage Mechanism Corrosion Under InsulationDamage Description External corrosion of piping, pressure vessels and structural components

resulting from water trapped under insulation or fireproofing materials.


Carbon steel, low alloy Steels, 300 Series SS and duplex stainless steels.Vulnerable areas can be found in the recycle/net gas, AET and the propane

refrigeration units. NACE RP0198 can be used for guidance.

Control Methodology Use immersion resistance coatings depend on surface temperature suitable for process conditions (cold, hot, cycling).

Use appropriate cold or hot insulations/sealing materials/vapor barrier coating and corrosion resistance jacket to prevent moisture ingress.

Use low chloride insulation and halide free coating on 300 Series SS to minimize the potential for pitting and chloride stress corrosion cracking (SCC).

Another option is to use thermal insulation coating systems with appropriate anti-corrosion primer coating instead of conventional insulation.

Monitoring Techniques Utilize multiple inspection techniques to produce the most cost effective approach, including:

Partial and/or full stripping of insulation for visual examination.UT for thickness verification.Real-time profile x-ray (for small bore piping).Neutron backscatter techniques for identifying wet insulation.Deep penetrating eddy-current inspection (can be automated with a robotic

crawler).IR thermography looking for wet insulation and/or damaged and missing

insulation under the jacket.Guided wave UT.

Inspection Frequency T&I Inspections KPIs CUI Program Implementation

# of failuresReferences API 571 (DM #46)

NACE RP0198

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6.14 Boiler Water/Condensate Corrosion (SA-50)

Damage Mechanism Boiler Water/Condensate CorrosionDamage Description General corrosion and pitting in the boiler system and blowdown piping is

usually the result of dissolved gases, oxygen and carbon dioxide.Oxygen corrosion tends to be pitting type damage. Oxygen is particularly

aggressive in economizers where there is a rapid water temperature rise.

Carbon dioxide corrosion results in a smooth grooving of the pipe wall. Some oxygen pitting can occur if the oxygen scavenging treatment is not working correctly.

Critical factors are the concentration of dissolved gas (oxygen and carbon dioxide), pH, temperature, quality of the feedwater and the specific feedwater treating system.


Primarily carbon steel, some low alloy steel, some 300 Series SS and copper based alloys.

Corrosion can occur in the waste heat boiler and blowdown system used to recover heat from the heater flue gases that produces medium pressure steam.

Control Methodology Lay down and continuously maintain layer of protective Fe3O4 (magnetite).Oxygen scavenging treatments typically include catalyzed sodium sulfite

or hydrazine and proper mechanical deaerator operation.The chemical treatment for scale and deposit control must be adjusted to

coordinate with the oxygen scavenger.Monitoring Techniques Water analysis is the common monitoring tool. This includes the pH,

conductivity, chlorine or residual biocide, and total dissolved solids.Inspection Frequency Visual shutdown inspections.

Use WFMPT inspection to check for deaerator cracking problems.KPIs # of tube leaks

pH deviationsReference Resources

(Standards/GIs/BPs)API RP571(DM #50)NACE SP0590-2007, “Prevention, Detection, and Correction of Deaerator

Cracking”

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6.15 Microbiologically Induced Corrosion (SA-51)

Damage Mechanism Microbiologically Induced Corrosion (MIC)Damage Description · Caused by living organisms such as bacteria, algae or fungi. It is

often associated with the Presence of tubercles or slimy organic substances.· Microbes require water to thrive· Sulfate-reducing bacteria (SRB) is the most common in oil industry and reduce the sulfate to the corrosive H2S, which again reacts with steel to form iron sulfides.· H2S is generated in aqueous environments, and is patent in stagnant or low-flow conditions that allow and/or promote the growth of microorganisms.· Observed as localized corrosion (pitting) under deposits

Affected Materials · Carbon and low alloy steels Control Methodology · Maintain proper sea water treatment with chlorine or ClO2.

· Maintain flow velocities above minimum levels. · Minimize low flow or stagnant zones to avoid solid deposits.· Maintain coatings· Prevent oxygen incursion.

Monitoring Techniques · Measuring residual chlorine or chlorine dioxide in the sea water outlet channel during the treatment period.· Establish bacteria monitoring program to be taken in a regular basis in order to obtain useful baseline data and assess long term trends.· Install flush coupons for evidence of fouling coinciding with MIC damage.· Periodic UV surveillance.

Inspection Frequency Regular UT, coupons, OSI, and visual inspection at T&ILab analyses on a weekly basis to detect and quantify MIC

KPIs SRB: 10 -> 102 (count of the bacteria in 1 mm2)Reference Resources (Standards/GIs/BPs)

· SAES-H-001· SABP-A-018· SABP-A-019· ASTM A 123· API 571

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6.16 Galvanic Corrosion (SA-53)

Damage Mechanism Galvanic CorrosionDamage Description Occurs at the junction of dissimilar metals when they are joined together in a

suitable electrolyte, such as a moist or aqueous environment, or soils containing moisture.

Affected Materials All metals with the exception of most noble metalsVent gas system equipment: carbon steel, 316SS (inlet vent gas piping),

Hastelloy 2000 (venture scrubber internal) and coating (vent wash tower internal).

Control Methodology Avoid contact of different alloys in conductive environments unless the anode/cathode surface area ratio is favorable.

Rivets, bolts, and fasteners should be of as more noble metal that the material to be fastened.

Use metallic coatings, such as inert barrier, organic or vitreous for the more noble material.

Use nonmetallic inserts, washers, fittings at the joint between the materials to eliminate their electrical connection. (Insulation kits for flanges)

Provide an appropriate corrosion allowance for more active metalsAvoid dissimilar-metal crevices such as those that occur at threaded

connections. Crevices should be seal welded. Monitoring Techniques Visual Inspection

UT SurveyInspection Frequency al during T&IsKPIs Corrosion RateReferences API 571 (DM#53)

Corrosion Basics – An Introduction,” NACE International.

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6.17 Metal Dusting (SA-59)

Damage Mechanism Metal DustingDamage Description It is a form of carburization resulting in accelerated localized pitting which

occurs in carburizing gases and/or process streams containing carbon and hydrogen. Pits usually form on the surface and may contain soot or graphite dust. It is also known as catastrophic carburization.

In low alloy steels, the wastage can be uniform but usually is in the form of small pits. The corrosion product is a voluminous carbon dust containing metal particles which will be swept away by the flowing process stream.

Metal dusting involves a complex series of reactions involving a reducing gas such as hydrogen, methane, propane or CO. It usually occurs in the operating temperature range of 900°F to 1500°F (482°C to 816°C).

Metallography will show a heavily carburized under the attacked surface.Critical factors are stream composition, operating temperature and alloy

composition. Damage increases with increasing temperature. It can also occur under alternating reducing and oxidizing conditions.

Materials & Equipment There is currently no known metal alloy that is immune to metal dusting under all conditions.

Susceptible equipment are the H-1, 2, 3 and F-0101 heater tubes.Control Methodology An aluminum diffusion treatment to the base metal substrate can be

beneficial in some applications.Monitoring Techniques For heater tubes with suspected damage, compression wave ultrasonic

testing is probably the most efficient method of inspection since large areas can be inspected relatively quickly.

RT techniques can be employed to look for pitting and wall thinning.If internal surfaces are accessible, visual inspection is effective.Filtering the cooled furnace or reactor effluent may yield metal particles

that are a tell tale indication of a problem upstream.Inspection Frequency Every T & I if the composition and operating temperatures are in the metal

dusting range.KPIs # of inspections conductedReference API RP-571 (2003)

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6.18 Under-Deposit Corrosion (SA-80)

Damage Mechanism Under-Deposit Corrosion Damage Description A localized internal corrosion attack that occurs due to any build up of

debris/sand, adherent corrosion/scale deposits, biological bacteria growth and sea water barnacles.

Affected Materials& Equipment

Most materials of construction including carbon and low alloy steels, 300 & 400 Series SS, copper and some nickel base alloys.

Susceptible equipment are the cooling water exchangers (biological), stagnant areas in the AET unit (chlorides) and relief valve dead legs(condensation).

Control Methodology For cooling water systems - treat with biocides such as chlorine dioxide to control bacterial growth.

Maintain flow velocities above minimum levels for the different materials. Minimize low flow or stagnant zones.

Hydrotest water shall be emptied quickly with blowing dry air.Using a combination of pigging, blasting, chemical cleaning and biocide

treatment.Applying protective coatings/linings and cathodic protection. can minimize

fouling and under deposit corrosion/leaks in heat exchanger tubes. Monitoring Techniques In cooling water systems, monitor chloride residual, microbial counts and

visual appearance.Special probes have been designed to monitor for evidence of fouling

which may precede or coincide with MIC damage.An increase in the loss of duty of heat exchangers may be indicative of

fouling and potential MIC damage.Conduct UT and/or RT as part of the OSI program.Perform Internal visual or NDT inspections during T&I.

Inspection Frequency Periodic Cooling Water chloride residuals, microbial counts.Chloride levels in the recycle and net gas systemsUT and RT per OSI output.

KPIs Chloride limit exceedanceHigh microbial counts Number of failures

References API 571 (DM #51)

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Appendix III – List of Observation from the Corrosion Management Program deployment in YR CCR Platformer Plant V11

Observations Root Causes Recommendations WPs PIWKPI /

AttributesPriority Phase

1

Corrosion Loops ReviewReview of existing Corrosion Loops (CL) that were developed during the 2010 Health Check indicated that there was a need to revise some of the DMs based on the detailed review of the current Operations, Maintenance and available T & I and Inspection data.

---- 1. Conduct a CL workshop that will identify any process, design, mechanical changes and associated Damage Mechanisms.

2. Perform the RBI study to determine high risk equipment and develop corresponding integrity plans.

EWP-04-05-01-02: Perform Corrosion Risk Assessment

AWP-02-03-02-01-02: Identify Damage Mechanisms

AWP-02-03-02-01-01: Identify Corrosion Loops

MOC Implementation

----

High Design

2 LPG Recovery (AET) CorrosionStream operating near dew point, so condensation leads to HCl corrosion in presence of high chloride conc. above design limits. HCl attacked CS drains and SS valve internals. In addition, some of the affected drain pipings were not sloped to allow for proper drainage.

In 2009, severe corrosion was observed in several stagnant locations; drain lines in C-101, D-110 and E-107, 4" Level Troll sight glass, valves and piping. Also, the E-109 tubes showed 20-40% metal loss in a few years. X-ray surveys at 54 locations showed only a few

1. Design Deficiencies

2. Improper Construction

3. No procedure for regularly flushing pumps

New1. Expedite the installation of the chloride treaters. This will only help in future deposit formation - some issues with existing deposits can still be expected.

2. Support YR effort to raise the AET operating temperature to around -10oC to minimize the formation of liquid water. The economic trade-off need to be evaluated for the loss of LPG recovery.

3. Flush the pump soon after being on standby and during

EWP-04-04-02-02: Plan Maintenance Tasks

EWP-04-05-01-01: Develop Corrosion Management Strategy

1. Chloride Level

2. Moisture Level

3. Operating Temperature

1. corrosion rate < 5 mpy

2. # of Leaks

High Operations

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locations had minor corrosion attack.

Also, a comprehensive evaluation conducted in October, 2009 identified the use of chloride treaters upstream of the AET to be the best long term solution. During the 2011 TRS, tie-in connections were made for future installation of the chloride treaters that are currently in the refinery. 21 to 40% tubes metal losses had been reported.

From 2010 Health Check, the recommendation to extend cold insulation around the drain connections to ensure there was no condensation was addressed. Also, insulation throughout the unit was inspected to ensure it was completely sealed and was not damaged especially around the valves.

Severe corrosion was observed in the G-0109, AET Absorber Bottoms pump impeller. This was most likely due to condensation during the standby mode. Also, plugging was observed in the strainer upstream G-0103, Platforming Prod. Separator Btm., which is also attributed to the presence of chloride and moisture.

T&I to prevent condensation and HCl corrosion. If pH is still low, flush with caustic.

3 Vent Gas Wash Tower (VGWT) System CorrosionFrequent leaks were observed in the

1. Design Deficiencies

New1. Flush the pump soon after bypassing VGWT to prevent

EWP-04-05-04-01: Act on Operations

1. Caustic Solution pH


Low Operations

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2" vent line, flanges and the 10" to 8" reducer in the venturi scrubber discharge. This had led to the bypassing of the tower for as long as 10 months. The metallurgy for D-0137, Wash Tower, is CS with APC 2G (polyglass VEF) coating which required minor repairs during the 2008 T&I. In 2009, the vessel was inspected and was shown to be in good condition with no coating damage. It was not part of the 2011 TRS because it is not a shutdown item. Severe corrosion and leaking of the operating CS caustic circulation pumps, G-0117, are still continuing with the spare pump in the shop.From 2010 Health Check, the recommendation to upgrade the metallurgy to Hastelloy C-2000 from the Venturi Scrubber to the Wash Tower was addressed.Review of 2010 trend data showed that severe corrosion was mostly due to acidic conditions resulting from the difficulty in controlling pH based on vent gas high chloride content. Also, modification of the caustic injection scheme is being considered to ensure reliability of caustic neutralization from a process stand point.

2. No procedure for regularly flushing pumps and backwashing exchangers

salt accumulation and corrosion.

2. Consider use of nonmetallic for the pumps and venturi discharge piping (thermoplastic liner) to the wash tower.

3. Utilize isolation kits between the dissimilar materials in the spent caustic system.

4. If APCS-2G coating fails during next T&I, then it is advised to conduct coating failure analysis and consider alternative coatings APCS-2H/APCS-27 of SAES-H-001.

EWP-02-05-03-03: Develop Process Stream Monitoring Strategy

2. Caustic Solution Alkalinity

3. Caustic Solution TSS

2. fouling rate

3. % VGWT system utilization

4 Sea Water CorrosionRepeated failures of the sea water exchanger 70-30 Cu-Zn and 90-10 Cu-Ni tubing and Monel weld

1. Corrective action not yet implemented (chlorination

Previous1. Utilize ClO2 which is a better alternative disinfectant to gaseous Cl2 and bleach. It

EWP-04-05-04-01: Act on Operations

1. Cl2 or ClO2 residuals

2. Bacteria


2. fouling rate

High Operations

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overlays (i.e. E-3, E-125, E-117, E-130, cooler to K-102) were observed. Also, the sacrificial zinc anodes in the channel boxes were rapidly consumed.

Fouling was observed in Plant V11 sea water header. Also, concerns with the intake filters are allowing large objects and marine life to enter the cooling system further aggravating the fouling problems.

The malfunction of the current NaOCl disinfection system and consequent low chlorine residuals (around 0.03 ppm) is allowing bacterial growth and biomass build up leading to microbial corrosion and fouling. The repair of the current system is possible, but is not complete. Also, the installation of the new ClO2 system is advantageous but has been delayed for years now.

Premature failures of cement lined/coated CS spools have been observed in the cooling water system. These leaks have been temporarily repaired using elastomer and CS clamps. Also, there were repeated coating failures in the channel heads, e. g. APCS-3 coal tar epoxy coating in E-

system)

2. Infrequent review of the cooling water KPIs

3. Faulty installation (of lining)

4. Improper coating selection.

provides superior disinfection with lower cost of maintenance and power consumption

2. Ensure adequate chlorination of the cooling water make-up (0.5 ppm residual chlorine min.) and maintain the sea water intake filter integrity.

3. Perform routine monitoring of the microbiological profile of the cooling water, i.e. GAB (General Aerobic Bacteria), SRB (Sulphate Reducing Bacteria), etc. Samples for these analyses can be routed to Dhahran.

New1. Expedite repairing and operating the current chlorination system until the system is upgraded to ClO2.

2. Expedite implementation of previous recommendations3. For heat exchanger tubes, consider coatings applied at 8-10 mils to minimize fouling and low velocity under deposit/MIC corrosion

TWP-02-05-02: Develop Corrosion Management Design Strategy Basis

TWP-05-03-01:Conduct Full Root Cause Analysis

EWP-04-04-02-02: Plan Maintenance Tasks

AWP-04-05-01-04-04: Plan for Paints, Coatings and Linings

EWP-02-05-03-01: Select Materials

(SRB/GAB) sessile count 3. Cl2 or ClO2

treatment rate

4. Cl2 or ClO2 conc. at SW outlet (during treatment)

5. Cl2 or ClO2 treatment time per spec.

6. Macro-fouling results (inlet/outlet canals)

7. sessile SRB count (inlet/outlet canal)

8. minimum flow rate in each exchanger bank

9. # of tube leaks

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003 B/D. Permanent repairs - replacement in kind are normally done at the next shutdown.

4. Alternative cost effective options for repair and replacements are: a. Thermoplastic (PP) lined carbon steel pipes or nonmetallic (RTR) pipes. b. Composite repairs to restore the pipe integrity

5. Use heavy duty coatings as per APCS-28 in SAES-H-001 in the channel heads, piping, spools and associated valves. Use non-metallic composite repairs to stop leaks occurring on the cement lined piping.

5 Coating Application and MaintenanceCoatings Under InsulationExternal corrosion was observed on insulated piping, valves and flanges (including bolts and nuts) in low temperature service, e.g. outlet piping valve of cross exchanger 1 (E-109A-D), reduction gas exchanger (E-123), and recontact chiller (E-116). The inorganic zinc coating (APCS-17A) does not provide adequate corrosion control for piping in such service with moisture and ice forming externally under the existing foam glass insulations. There was damage observed in this cold

1. Design deficiencies

2. Improper coatings selection

Coatings Under InsulationCold Insulation: a. Use immersion resistance coatings based on epoxies APCS-2A/2E/2I as stated in SAES-H-001, under cold insulation instead of inorganic zinc coating. b. Apply elastomeric top-coating type over foam glass (cold service) to serve as a vapor barrierHot Insulation: Use coatings designed for cycling approved for APCS-11C, under calcium silicate. An alternative cost-effective

EWP04-05-04-02: Act on Maintenance

AWP-04-05-01-04-04: Plan for Paints, Coatings and Linings

---- corrosion rate < 5 mpy

Medium Operations

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insulation and hot insulation (calcium silicate). There was no vapor barrier, top-coating over the cold insulation needed to keep moisture from forming on the piping surface.

Coating for Heaters H-1/2/3 and F-101The silicone based external coating (APCS-11A) was failing in the burners areas and on roof side areas.There might not have been any anti-corrosion coating applied before the installation of refractory.There was external scale formation on heater tubes that might lead to localized hot spots.Damper plates and shafts were distorted by high temperature. The damper metallurgy was recently upgraded to 25Cr-12Ni for shaft and 310SS for plates with bolts/nuts in the last TRS. The dampers may still be exposed to higher than design temperature due to not having a convection section in the heaters' stacks that can lower flue gas temperatures.

Flare Header Isolation ValvesExternal coating system over PZV valves and the top-coat color is aluminum pigmented coating system instead of orange pigmented system

option is to use sprayable insulating coatings approved for APCS-5B in SAES-H-001. This will eliminate the risk of hidden corrosion under conventional bulky insulations. It can insulate irregular shapes; valves and flanges with only spraying the coating.Bolts & Nuts: Use floupolymer coating standard 09-SAMSS-0107. This will protect fasteners from corrosion and seizing and difficulty in dismantling during maintenance.

Coating for Heaters H-1/2/3 and F-101External: Use APCS-11C coating which has better surface tolerance and high temperature resistance. Internal: Use special high temperature coatings based on aphaltic-ureathane on heater casing including anchors.Heater Dampers: Consider the use of thermal barrier coating technology if problems continue.

Flare Header Isolation Valves

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Check the process temperature and select proper external coating system that contain orange pigment in their top-coat from SAES-H-001.

6

Heater Transfer Lines Terminal WeldsThere haven't been any inspection for the potential damage mechanism of creep cracking for the heaters' transfer piping. This includes the externals of heater to reactor terminal welds where stress levels can be very high and creep can initiate. This has been an industry-wide concern

Previously not identified as a potential DM

During next opportunity/TRS, conduct inspection of the terminal welds of all low-alloy transfer piping.


EWP-04-05-01-01: Develop Corrosion Management Strategy

---- ----

Medium Operations

7 Annual Corrosion Review:Based on a review of CL and potential DMs, several high priority locations were identified for detailed evaluations. Analysis could not be conducted due to lack of required data. These locations are discussed below:Potential HCl Corrosion due to condensation - CL#3 - 4" P-203-3CA1B Recontact Chiller (E-0116) to Recontact Drum (D-0103), (OSI data not available)Stagnant Corrosion- CL#11 A - 24" P-1256-3CDIP, K-0110 Regen Blower to Regeneration Cooler (E-0126) was cracked and pitted. Replaced in kind with 316SS and shifted valve down to pipe during the

No work process

1. Expedite the entry and analysis of the UT and RT data into the SAIF program so that a detailed corrosion analysis could be performed.

2. Send samples to MEU Lab for a detailed failure analysis e. g. 24" P-1256-3CDIP.

3. Utilize Corrosion Control Document to focus on highly critical variables and conduct your annual review/audit.

EWP 04-03-02-02: Carry out On-Stream Inspections

EWP 04-05-01-01: Develop Corrosion Management Strategy


EWP-04-05-03-01: Corrosion Data Assessment

1. Chloride Level

2. Moisture Level


2. # of failures

High Operations

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2011 TRS. Installed new connection from dryer to loop to reduce moisture. (OSI data not in SAIF)Potential Cl Pitting- CL#8: 3"P-0220-3CJIP Reactor to E-0120 - 304H 366ºC v/s 120ºC (OSI data not in SAIF) Corrosion CL#7C: C-0101 Absorber Bottom (OSI data not in SAIF, individual readings not analyzed)Potential HCl Corrosion - CL#7C: 12"P-0133/134-1CA1B C-0101 Absorber to G-109A/B - currently taking UT reading every 3 months. (OSI data not in SAIF, individual readings not analyzed)Corrosion CL#7C: 6"P-0124-1CA1B - G-109A/B to E-109A/B (OSI data not available)

EWP-04-05-03-02: Corrosion Management Review

8 Corrosion Management DeficiencyCoupons:Retractable coupons can give reliable data under turbulent and laminar flow conditions. Typical locations for installing coupons are susceptible locations of well known damage mechanisms such underdeposit corrosion (MIC) in seawater and caustic or acid corrosion in VGWT system.. Generally, corrosion coupons are removed on a 6-12 month frequency or sooner if high corrosion rates are observed either from past

1. Lack of Corrosion Management

2. Accepted Plant Upgrade without establishing equipment/piping baseline thicknesses.

1. Define high risk locations from RBI study to re-activate the corrosion monitoring. Also, use the RBI study to prioratarize the ongoing effort to establish UT baseline data for corrosion analysis.

2. Additional installation locations can be identified after completing the requested OSI reading on the specified locations in item #6.

TWP-04-05-01 Plan: Corrosion Management


EWP-04-05-02-03: Implement Corrosion Monitoring Strategy

---- corrosion rate < 5 mpy

Low Design

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coupon/probe data or the OSI analysis. Coupon data needs to be supplemented by OSI inspection program to confirm the results; however, review of available data did not indicate if the coupons were recently retracted.

Probes:Probes offer continuous data collection without the need for frequent replacements. However, if there is pitting or high velocity the thin probe element used can fail by fatigue. As a major finding, corrosion probes installed at different locations in V11 are providing acceptable readings/corrosion rates ranging between 0.09 to 0.36 MPY. It is preferable to correlate these readings with OSI program to confirm accuracy. YR can also get additional benefit out of the RBI studies to identify the high risk locations where installation of corrosion coupons or probes at these identified spots would to very sufficient.The system has been recently bypassed due to the upgrade to wireless data gathering.

YR has exerted a huge effort to establish baseline thickness readings for hundreds of TML's in Plant V11,

3. Maintain trending records of corrosion probes and coupons data over the years to build up a historical performance that will clearly provide the corrosion behavior over time.

4. Utilize corrosion rates and remaining life to detect locations of high penetration rates

5. Consider installing corrosion coupons of different metallurgy in the seawater system (V11-E-3 and V11-E-125) and vent gas systems (wash tower piping) where severe corrosion has been observed.

EWP-04-05-03-02: Corrosion Management Review

Page 70 of 71




but there still are many more that might be of greater importance. Having said that, review of already measured UT data that are available in SAIF showed:Out of 6000+ TMLs, 767 points had a corrosion rates > 5 mpy, out of which 47 TMLs also had a remaining life < 10 years. The most severe location is that located in circuit # ¾”-FG-0605AC-1CC1P-S with corrosion rate = 126 mpy and remaining life of 4.2 years.

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Documents

YR V11 CCD (SAER-6353)