Failure of inlet line in gas oil desulphurisation unit.pdf

7/30/2019 Failure of inlet line in gas oil desulphurisation unit.pdf

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FAILURE OF INLET LINE TO HOT SEPARATOR GAS COOLER IN GAS OILHYDRO-DESULPHURISATION UNIT

M. Vinayakumar,DGM ( Engineering )

Mangalore Refinery andPetrochemicals Limited

Background

A Gas Oil Desulphurisation Unit at MRPL experienced failure of an inlet pipelineto hot separator gas cooler. This paper deals with the incident, probable causesof failure and recommendations for corrective and preventive action.

Details of the Unit

The Gas Oil Hydro- desulphurisation Unit has a design throughput capacity of30,000 BPSD, and treats sour gas oil. The unit was commissioned in September1999. The original design feed stock comprises a mix of straight run HGO (2 wt%S); 370 C (-) cut VGO (2.2 wt% S) and Visbreaker Naphtha (1 wt% S). As peroriginal design conditions, de-sulphurised Gas Oil should have a sulphurspecification of 0.05 wt% maximum, and a flash point of minimum 38 C.

This unit receives the feed oils and the H 2 gas from the phase 1 and 2 refinerycomplex along with utilities. Products and other process streams are returned tothe refinery. Lean Amine and other chemicals are received from the refinery.Rich Amine is returned to the refinery Amine Treatment Unit for regeneration.

Sour gas is sent to the refinery sour fuel gas header for treatment. Sour water issent to the refinery Sour Water Stripping Unit. The plant flare piping is connectedto the refinery flare network. Treated GasOil is used as HSD blend stock. Washwater injection is done upstream of hot gas separator cooler for removal ofdeposits and is removed from the system at the stripper receiver.

The unit underwent a catalyst change during a shut down in April 2006. The newcatalyst is intended to reduce the sulphur content of de-sulphurised gas oil to50ppm, to bring the diesel product in line with improved fuel specifications.

A flow chart of the relevant section of the unit is attached as Annexure A. Failure

occurred at the inlet to Hot Separator Gas Cooler EC45501Incident

Gas Oil Hydro Desulphurisation Unit ( GOHDS) was in normal operatingcondition on July 9, 2006 operating at 125 CuM/Hr. The operating staff heard aloud noise at around 5:45 PM and witnessed a spray of hydrocarbon and gasesfrom the air cooler platform area. Simultaneously, control room personnel noticed


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the drop in pressure and initiated emergency shut down proceedings. Unitpersonnel also operated sprinkler system available in the air cooler area tocontain the leak. Their immediate actions of shutting down the unit and fightingthe emergency ensured that the situation was brought under control swiftly.

There was no fire or any injury to any person. Subsequently it was noticed thatthe inlet line to the air cooler was found to have a rupture on the vertical portion,below a water injection point. No other damage was observed.


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General Information of the inlet line.

The design conditions of the line are given below:

Line size at the point of rupture - 6

Design Pressure - 64 Kg/sqcmgDesign Temperature - 160 0COperating pressure - 53 Kg/sqcmgOperating temperature - 136 0CMaterial of construction (of line ) - A106GrB to NACEMR0175Provided thickness - Sch 80 (10.97 mm +-

12.5%)Water injection rate - ~7 CuM/ Hour

Observations :

1. A thin lip type of opening was noticed at a location below the waterinjection point on the South side inlet. The opening approximately oval inshape with dimensions of about 150 * 65 mm.

2. Thinning of pipe was observed at the region of failure. This thinning islocalised, with severe thinning limited to only the region of failure.

3. The elbow below the failed location ( at a distance of about 800 mm fromthe center line of wash water injection ) had shown some amount ofthinning, along the line of water injection ( and not on the outer radius ofthe elbow )

4. Thinning was also noticed on the vertical spool below water injection onthe North side inlet.

5. As per P&ID, the water injection nozzle projected into the middle of theprocess piping. A variance to this was noticed at site on both North andSouth inlet

Location offailure

Sout

Air Cooler EC45501

Water injectionWater injection

North


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6. The condition of both the tees were satisfactory, both visually and onthickness measurements.

7. No deposits were observed in both the line. Material scraped off from theinternal surface of the North side and south side pipes showed sulphidesalts of ammonia and iron. No chloride salts were detected.

INSTALLATION OF WATER INJECTION PIPE

At the failure location (South inlet) On North side inlet

(Viewed from below after cutting the pipe)


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Operational History

As per operational history, the unit was operating steadily at around 200 CM / Hrtill 1700 Hrs. Afterwards, the feed was brought down to 125 CuM / Hr due to

process disturbance in Crude Distillation Unit 2. Minor fluctuations in pressureand temperature were noticed during this reduction in load .

A continuous water wash of about 7 CuM /Hr had been maintained at the inlet ofEC45501. The unit uses a mixture of fresh DM water and LP condensate aswash water.

Process Analysis of the area

Prior to Catalyst Change After Catalyst Change

Design Operatingconditions(six monthsaverage)

Design Operatingconditions (2monthsaverage)

Feed rate,Cu M / Hr

198.7 ~213.4 200 ~200

FeedComposition,Volume %

HS HGO-78%HS VDO 17%

VBUNaphtha 4%

HSHGO+VDO 60.55%BH GO 26.89 %

HS LGO 12.56%

HS HGO- 50%HS VDO 25%HS LGO

25%

HSHGO+VDO 78%HS LGO 6%BH GO - 16%

FeedSulphur, %

1.97 1.04 1.74 1.22

FeedNitrogencontent, ppm

Left blank inBasic Enggpackage

< 148.86ppm

369 ~ 141.9 ppmcomposite

ProductSulphur,

ppm

500 < 500 40 ~ 50

Pressure,Kg/ Sqcmg

53 51.5 53 51.5

Temperature- Air Coolerinlet , 0C

136 Nothistorised

136 141.9*


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Temperature- Air Cooleroutlet, 0C

55 51.4 55 50.81

Wash waterquantity,

CuM

7 7.43 No specificrecommendati

ons fromcatalystvendor orlicensor

7

Wash Wateras % of feed

3.5 3.45 --------------- 3.5

Wash watersource

DM water + LP condensate stored in an open tank

Wash waterrequired foroperatingconditions (Calculatednow,)**

1.99 CuM/Hr

0.93 v%

4.62 CuM/hr

2.31 v%

1.78 CuM/Hr

0.89 v%

* (average of 5 days prior to the failure , Previous history not recorded )** Maximum permitted NH 4HS concentration in sour water = 5 wt% assumed.

Inspection history of the line

The line has been periodically thickness surveyed by inspection department. Thelast thickness survey was done in four months prior to the failure

The points selected by Inspection on the straight spool are

Adjacent to the pipe to tee weld Adjacent to the pipe to elbow weld Elbow

Weld

Thickness surveypoints

690 mmbetween welds

Water in ection nozzleFailure


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The thickness on the pipe at the surveyed locations were satisfactory (minimumof 9.95 mm), with in the manufacturing tolerance of the pipe ( 10.97 +- 12.5% ).The elbow on the failed side had a minimum thickness reading of 9.73 mm,which again was with in manufacturing tolerance.

Subsequent to the failure, the thickness of failed spool piece (about 690 mmlong) was mapped extensively and the readings are indicating localised thinning.The regions regularly surveyed continued to show healthy readings even afterfailure.

Cause of failure

The immediate cause of the failure is the localised corrosion of the South sideinlet line. The line in the failed area has thinned sufficiently to cause a failure.From the analysis of data, it appears that there have been no operational

abnormalities or major deviations in operating parameters, which could havecaused a failure.

Known causes of corrosion in reactor effluent circuits

As the effluent from the reactor cools down, Ammonia (NH 3) combines withHydrogen Sulphide (H 2S) to form Ammonium Bi-sulphide (NH 4HS). In theabsence of liquid water, NH 4HS condenses directly from the vapour phase toform a crystalline solid, which can cause rapid plugging of the air cooler. SinceAmmonium Bi-sulphide is soluble in water, the precipitated solids can be washedaway by injecting water ahead of the air cooler. However, aqueous NH 4HS ishighly corrosive, and if left uncontrolled can cause corrosion. Several factorsinfluence the corrosion rate.

a. Adequate quantity of wash water is to be used. The quantity of waterinjected depends upon the quantity of Ammonium Bisulphide likely tobe formed in the effluent. This in turn depends on the de-nitrificationand de-sulphurisation levels in the reaction process.

b. Presence of oxygen in the wash water aggravates corrosion. Bydesign, the unit uses DM water + LP steam condensate stored in avessel open to atmosphere. A sample of water drawn from the vesselshowed Oxygen level of 5 ppm. However, opinions on the permittedlevels of Oxygen vary from 50 ppm to 0.05 ppm 1,2 . Several refinersoperate at an Oxygen level of 20 ppb to 50 ppb 3, though APIrecommended practice 4 states a desired level of 15 ppm of Oxygen inwash water.

c. Location of water injection point is to be selected in such a way thatmost of the water should vapourise immediately on injection. Ifchlorides are likely to be present in the effluent stream, about 20% of


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the water injection should remain as liquid to take care of dew pointcorrosion from hydrochloric acid.

d. Symmetry of inlet and outlet piping ensures that the wash water isevenly distributed. Such a symmetrical piping is present in GOHDS.

e. In addition to the above, the water injection quills have to be properly

selected and designed. As per P&ID as well as fabrication drawings,the water injection point quill was to be at the center of the pipe alignedalong the direction of flow at the centre of the pipe

Analysis of failure

a. It has been calculated ( as per 1 ) and concluded that adequatequantity of water (7 CuM / Hr) has been injected before and aftercatalyst change for the actual quality of GOHDS feed. As percalculations, about 60% the injected water is remaining in liquid phase.

b. It was observed that , the injection quill had been incorrectly mounted.The incorrect mounting of the injection point allows the water to flowalong the wall of the pipe. The effect of the incorrect mounting is likelyto equivalent to providing a simple stub in, with water impinging on thewall of the pipe. As the water flows down along the wall of the pipe, itcan get concentrated with NH 4HS from the process gas. The area thathas corroded the maximum must be the area that has seen the highestconcentration of aqueous NH 4HS. The pattern of thinning of the pipeis suggestive of this mechanism. (Theory postulates that above aparticular threshold concentration, a metal ammonium complex isformed which breaks down the protective layers on steel surfaceallowing bare metal to react with Ammonium bisulphide- 2). Increase invelocity breaks down the protective layers faster.

c. A 1998 API survey 4 of 24 refineries reported two areas for corrosion ininlet piping immediately around the water injection point and in theheaders before REAC. In this study, API has mentioned that aroundthe injection point, water impingement has been a problem. Whenexcessive vapourisation occurs, the amount of liquid water remainingcould be too low and this results in concentrated aqueous saltcorrosion. A 1996 survey by UOP, presented at a NACE 5 seminar hasanalysed failures of different failures of reactor effluent circuits at 45US refineries and had come across only one failure of inlet piping,where it was concluded that the failure occurred due to a local boildry condition, which presumably concentrated the salts. A similarphenomenon could have occurred in the current case also.

d. The failure does not appear to be due to erosion, since the areasimmediately adjacent to the quill where the water impinges has notcorroded. Rather, the corrosion appears to be along the line of flow ofwater, as is indicated in the thickness readings.


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e. Oxygen in wash water may have aggravated the corrosion, though theextent of contribution could not be established due to lack ofsupporting data.

f. Wash water, adequate for the operating conditions, has been usedprior to and after catalyst change.

Recommendations for corrective and preventive actions

a. As an immediate measure, the wash water injection point has beencorrected as per P&ID requirements. However, at the point of injection,about 60% of water is expected to be in liquid state. Hence it ispossible that the problem of corrosion could be transferred to the nextlocation where the water comes in contact with the pipe wall, in thiscase the down stream elbow. The area is to be monitored till a patternis established.

b. In addition, the licensors opinion is to be sought on

1. possibility of thinning on the elbow, as described above2. addition of any inhibitor which can protect the surfacedownstream of the injection point .

3. changes in quill design , for better distribution of water (a slightlydifferent design has been provided elsewhere in the refinery )

4. whether continuous washing can be replaced with intermittentwashing, since the quantity of precipitated NH 4HS appears to below.

c. Current practice on quantity of wash water injection and frequency ofinjection (continuous) is to be maintained, awaiting process licensorsviews.

d. Commence a periodic analysis of sour water from cold separator toestablish the concentration of ammonium salts. Troublesomecorrosion is not expected at concentrations less than 8 wt% in sourwater 5.

e. Revise the operating procedure to include washing with vast excess ofwater (say, 3 times the normal flow), once in 15 days, to remove anyformation of salt deposits downstream of injection area.

f. Recheck the requirement of wash water each time a major processchange (ex: product quality change, feed quality change) is effected.

g. Alternate source of wash water with nil oxygen should be beingconsidered. Either stripped sour water or BFW are likely sources.

h. Correctness of installation of all injection points and health ofconnected piping in the refinery should be re-checked.

i. Correctness of installation of injection quills should be a pre-commissioning check for all new units


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References cited in the report:

1. Turner J, Corrosion Control in wash water systems, HydrocarbonProcessing, June 1997

2. Kane R.D et al, Corrosivity in refinery sour water systems, Petroleum

Technology Quarterly, Summer 20013. Publication 932-A, A study of corrosion in hydroprocess reactoreffluent aircooler systems, American Petroleum Institute, September2002.

4. Recommended Practice 932-B, Design, Materials, Fabrication,Operation and Inspection of Guidelines for corrosion control inhydroprocessing reactor effluent systems, American PetroleumInstitute, July 2004

5. Singh, A., Harvey, C. Corrosion of Reactor Effluent Air Coolers,Corrosion 97, NACE International, Paper No: 490


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