1998: Case Study of CO2 Removal System ... - IFFCO : KANDLA

Case Study of CO2 Removal SystemProblems/Failures in Ammonia Plant

The article addresses the various problems/failures experienced in the CO2 removal system of anammonia plant in a short span operation of less than one year. Probable causes of failures and the

corrective steps taken to avoid such failures in the future have also been discussed.

V. K. Bali and A. K. MaheshwariIndian Fanners Fertilizer Cooperative Ltd. (IFFCO), Aonla Unit, Bareilly, Uttar Pradesh, India

Introduction

Indian Farmers Fertilizer Cooperative Ltd. operatestwo Ammonia plants, each with a name platecapacity of 1,350 MTPD of ammonia. Both of

these plants have been designed based on HaldorTops0e technology with steam reforming of naturalgas and/or naphtha. Ammonia-1 is designed for naturalgas feed stock and was commissioned in 1988.Ammonia-2 was commissioned in December, 1996and is designed for both natural gas and naphtha feed-stocks. The Benfield process was selected for the CO2

removal system of Ammonia-1 which has been con-verted into the Giammarco-Vetrocoke (GV) dual acti-vator system in April 1997 for achieving lower CO2

slip and energy savings. For the Ammonia-2 plant, theGV dual activator low energy process has been select-ed for CO2 removal system from the design stage.This article describes the problems/failures experi-enced in the CO2 removal system of the Ammonia-2plant during the very first year of its operation.

Process Technology Adopted For CO2

Removal System

The CO2 removal system of the ammonia Plant hasa conventional design based on the GV dual activatorprocess. The process is comprised of single-stageabsorption and two-stage regeneration. Figure 1 showsthe CO2 removal system flowsheet.

Carbon dioxide is removed by absorption in hotaqueous potassium carbonate solution containingapproximately 30 wt. % potash (K/jCCy, partly con-verted into bicarbonate (KHCO3). The solution furthercontains dual activators to effectively improve theoverall performance of the system. Vanadium oxide isused as a corrosion inhibitor.

The process gas from the shift reactors is passed tothe vetrocoke absorber, which contains stainless steelpacking material distributed in five beds. The absorp-tion is carried out in one stage. The major part of thecirculating solution is fed without cooling to the mid-dle of absorber at about 241°F (116°C). The remaining

AMMONIA TECHNICAL MANUAL 285 1999

solution is fed to the top of the absorber after coolingto about 140°F (60°C). In the lower zone of theabsorber, the bulk of the CO2 is absorbed. In the upperzone, the reduced stream of cold solution is used to getlow CO2 slippage due to the low CO2 vapor pressure

of the dual activated solution.The solution leaving the absorber bottom loaded

with CO2 is called the rich solution. The rich solutionis transferred to a two-stage regeneration system oper-ating at low pressures. The rich solution is depressur-ized through the hydraulic turbine and is sent to thetop of the first regenerator operating at 14.2 psig (1.0Kg/cm2g) pressure. A stream of rich solution extracted

from the top of first regenerator is depressurizedthrough a control valve and enters the top of the sec-ond regenerator, working at a low pressure of 1.42psig(0.1Kg/cni2g).

Corrosion Control In CO2 RemovalSystem

GV solution along with CO2 at boiling temperature

is very corrosive and would normally require stainlesssteel equipment. However, carbon steel equipmentwith passivation layers (oxidation layers) are beingused successfully. The desired passivation layer isformed by controlled passivation in two phases calledstatic passivation and dynamic passivation. The layerformed is tight, magnetic and tenacious and protectsthe carbon steel surfaces from corrosion. However,rubbing with hard sharp edges can scratch the layer.The GV system uses vanadium as a corrosioninhibitor. The recommended concentration of totalvanadium is around 0.5% by weight as V205.

The hot potassium carbonate inhibited with vanadi-um can be safely operated, but is very sensitive forcorrosion. In order to maintain the electrochemicalpotential required for the protection of the passivationlayer of metallic surfaces, it is necessary to keep 30 to40% of the total vanadium in the pentavalent form andnever be allowed to be lower than 20%. This ratio iskept by means of the oxidation unit which treats a sidestream solution with air.

Hence, formation of the proper passivation layer andits protection is very essential to avoid corrosion in the

GV system equipment. Any damage to the passivationlayer can cause very fast corrosion and subsequentleakages.

Problems/Failures Experienced

The various problems faced in the CO2 removal sys-

tem of the ammonia plant have been presented. Eachproblem/failure has been dealt with separately specify-ing the problem/failure faced, the cause of the prob-lem, and various corrective steps undertaken to avoidsuch occurance in the future.

Second regenerator

The second regenerator is a carbon steel tower pro-vided with stainless steel internals and operating at apressure of 1.42 psig (0.1 Kg/cm2g). It is a packed

tower having 129 in. (3,230 mm) diameter and 1,643in. (41,075 mm) height. It also contains stainless steelpacking material distributed in two beds. Broad speci-fications and the general arrangement drawing of thesecond regenerator are shown in Figure 2.

Problem/failure description

Based on the failure history of this equipment inother plants, it was decided to measure the thicknessof the second regenerator shell in the failure pronezones after about 9 months of operation. While thethickness measurement was in progress between A-2and A-7 nozzles, a leak was observed on the other sideof the shell on Nov. 9, 1997. This leak was locatedapproximately 6 in. (150 mm) above the A-2 nozzleand 88 in. (2,200 mm) circumferentially towards theM-3 manhole. Initially, a hole of approximately 0.8 in.(20 mm) in diameter was observed which enlarged toa bigger size "eye shaped" hole within 2 h of the startof leakage as shown hi Figure 3.

Thickness measurements were carried out aroundthe leaking hole to ascertain the extent of thining hithe shell. No thinning was found even around the hole,leading to the conclusion that the failure was localizedas shown in Figure 4. The area of leakage was coveredand welded with SS-304, 8 in. sch 10 pipe with a blindand a vent to arrest the leakage. The whole exercise


1ST REGENERATOR 2ND REGENERATORCO2GAS CO2 GAS

VETROCOKE ABSORBER

PROCESS*" GAS OUT

HYDRAULIC

TURBINE

TEMPERATURE (DEC. C)

PRESSURE (KG/CIUPG)

Figure 1. CO2 removal system flowsheet.

GAS OUTLET

RICHSOLUTION

INLET

LEANSOLUTION

INLET

SEMI- LEANSOLUTION

OUTLET

PACKING DETAILS

BED

1

2

VOLUME (M 3)

81.9

81.9

TYPE

SMTP 50

IMTP 50

SEMI-LEAN SOLUTION INLET

LEAN SOLUTION OUTLET

Figure 2. Second regenerator.


^ 15945

^15100r 14200^r • **«• w

180° 130° 103° 90

CIRCUM WElD SEAM

APPROX. 2200 M M t ^«-E

|fl ; Î 430 M MV^H^V f i fi?i if i •^ Hj|j ^ Pgiy

* " . ! Mray " "

i !; :

i

(Development Of Shell)

0

Figure 3. Second regenerator: leakage due to corrosion.

30

v 15945

v 15100v 14850v 14000

0° 285C

i

bi.

AW1I

180°: 130° 103° S1

CERCUM.WEU) SEAM !••• -.'• - " V;

• i

" ' • • ' m -: ' - <•• • m.• •• TX

f.; ,....... .... ' ' • -• ( iy -x A

\^S

»0°

v 15930

^ 15530

V-HOLE

A A*%f\f\v 14200

Figure 4. Second regenerator: leakage in shell due to corrosion.Thickness measurement was carried out in the hatched area. No reduction, except failure, was observed.


was carried out while the plant was in operation andthe equipment was in line.

As a preventive measure, it was decided to carry outthickness measurements around the affected area ofthe shell on a regular basis. It was observed that thethickness had been reduced to as little as 0.56 in. (14mm) around the 8 in. stainless steel pipe, which hadbeen welded to contain the leak. Stainless steel padswere welded around the 8 in. stainless steel pipe tostrengthen the shell. The second regenerator wasopened for inspection in October 1997. A hole ofapproximately 12 in. (300 mm) in diameter wasobserved from inside. Welding of the cleat betweenthe SS 304 shroud and the vessel was also found bro-ken. Photo 1 shows the damaged second regeneratorshell.

In addition to the leakage in the shell, the followingupset conditions of a minor nature were also observedin the second regenerator.

• Three segments of the steam distributor above thechimney at an elevation of 644 in. (16,100 mm) werefound lifted from their support beam by about six toeight in. (150 to 200 mm), as shown in Figure 5. Photo2 shows the disturbed internals of the steam distribu-tor.

• The Bed No. 1 liquid re-distributor (Norten type) atan elevation of 26,750 mm was found lifted from itssupport ring by about 50 mm on one side, as shown inFigure 5.

Cause of the problem

The mechanical design of the fluid entry zone ofsecond regenerator was found to be inadequate.

The support design of the stainless steel protectiveshroud was inadequate for the dynamic loads. Thisresulted in the shroud supports cracking and allowingthe cleats of the shroud to hit the wall which broke theprotective vanadium layer on the carbon steel shell.This allowed rapid corrosion of the shell and subse-quent failure of pressure vessel (Figure 6).

Upon investigation it was also discovered that thematerial of the cleats was carbon steel rather than thestainless steel material specified on the approveddrawings. Also, the number of cleats provided were atvariance with the approved drawings.

It was further concluded that an internal annular pas-sage should be avoided if possible to safeguard theinstallation against even the slightest possibility of anymeans of damaging the passivation layer. The weldingof cleats to the shell to support the annular passage,which is likely to have some degree of vibration due tothe process conditions, was identified to present such apossibility.

Various design options

Design problems in the fluid entry zone of the sec-ond regenerator were reported in 1993 in a 900 MTPDammonia plant operating in the southern part of India.The flow was directly hitting the chimney which brokeoff and rubbed against the tower wall. This resulted indamage to the passivation layer and caused corrosionwhich, in a short period of time, resulted in equipmentfailure. Another operating problem experienced in thisequipment was the difficulty in maintaining the propersolution level.

During the engineering and procurement phase ofthe IFFCO-Aonla Unit, it was decided to re-engineerthe inlet arrangement using a Norton type inletarrangement and providing an annular passage. Theinlet arrangement was designed to divert the flow intwo directions horizontally to avoid direct impinge-ment on the chimney. A stainless steel annular passagewas provided to prevent liquid impingement on theshell and possible disturbance of the passivation layerwhich could cause excessive corrosion. An annularpassage was provided with an annular ring at thelower end to limit the disturbance of the surface, thatis, to improve level measurement. The above arrange-ment is shown in Figure 7. Photo 3 shows the originalinlet distribution arrangement.

However, ammonia plant of Aonla Unit and othersimilar plants based on above design have reportedfailures in this equipment in the fluid entry zone.

Yet another design option has been consideredwhich has now been adopted and is described sepa-rately in this article.

Repairs/modifications

• The area of 24 in. x 24 in. (600 mm x 600 mm)


Photo 1. Damaged shell near solution inlet

SMTP 50PACKING

MULTI-BEAM SUPPORT PLATE

LIQU1 D REDISTRIBUTOR FOUNDLIFTED BY SO M M ON ONE SIDE

BED LIMITER

MULTI-BEAM SUPPORT PLATE

STEAM DISTRIBUTOR ( 3 SEGM ENTSFOUND LIFTED FROM ITS SUPPORTBEAM BY ABOUT 150 M M )

15100 M M

Figure 5. Second regenerator: failure of liquid redistributor and steam distributor.


Photo 2. Second regenerator: disturbed steam distributor.

SOLUTION INLETNOZZLE

CLEATS

IMPINGEMENT PLATESHELL

SHROUD

10 MM GAP

CHIMNEY

48 NOS. 20 $ HOLESFigure 6. Second regenerator.


SHELL (25 M M THK )

LiNER(SMMTHK)

IMPINGEMENT PLATE

rvSOLUTIONINLET NOZZLE( A 2 )

48 NOS. 20 0> HOLES

10 M M GAP

900 (j) CHIMNEY

Figure 7. Second regenerator (original arrangement).

Photo 3. Second regenerator: solution Met (original arrangement).


which was patched up from outside to arrest leakagewhile the plant was in operation, was removed. A newmatching plate of the same size was welded into theshell.

* The existing nozzle entry configuration and stain-less steel shroud was dismantled and removed.

• A new arrangement of the distributor and support-ing arrangement as shown in Figure 8 was provided.This arrangement removes the possibility of damagingthe passivation layer. At the same time, it ensures thatthe GV solution is uniformly distributed throughoutthe circumference of the second regenerator and doesnot hit the chimney and the surface of the tower.

Vetrocoke absorber

The Vetrocoke absorber is a carbon steel tower withstainless steel internals operating at 398 psig (28Kg/cm2g) pressure. It contains stainless steel packingmaterial distributed in five beds. Liquid distributorsand redistributors (called LRD) of stainless steel mate-rial have also been provided. Broad specifications andthe general arrangement drg. of the Vetrocokeabsorber is presented in Figure 9.

The overall performance of the Vetrocoke absorberwas satisfactory as the CÛ2 slip at the absorber exitwas less than the design figure of 300 ppm. However,a detailed analysis of the performance of each bedconducted in August 1997 indicated that the secondbed was not performing satisfactorily. Maldistributionof GV solution at top of the second bed was thought tobe the probable cause and it was decided to open theabsorber at the earliest opportunity.

Problem/Failure Description. The ammonia plantwas shut down in October 1997 and this opportunitywas utilized to open the various manholes of theabsorber for inspection. The following failures werefound as observed from various manholes.

Location: M3 Manhole. This manhole is locatedbetween Bed No. 2 and Bed No. 3 at an elevation of1,056 in. (26,400 mm).

The Bed No. 2 liquid redistributor (Norton type)called LRD located at elevation of 1,030 in. (25,750mm) was found buckled at the top and the J-bolts sup-porting the distributor had been sheared. The LRDwas raised about 6 to 8 in. (150 to 200 mm) from its

support ring.Further upward movement of the LRD was restrict-

ed by the semi-lean solution distribution parting boxesplaced above it, and by the semi-lean solution distribu-tion pipes of nozzles A2 and A3 located at an elevationof 1,066 in. (26,640 mm).

The distance between the LRD and the Bed No. 3containing IMTP 40 stainless steel packing had beenreduced to around 24 in. (600 mm). A few loose ringswere also found at the top of the LRD.

The parting box was also found damaged and buck-led at the ends.

A few 8 in. NB nipples attached with the semileansolution distributor pipes of A2 and A3 nozzles werealso found twisted.

The details indicating the above failures are given inFigure 10.

Location: M4 Manhole. This manhole is locatedbetween Bed No. 1 and 2 at an elevation of 631 in.(15,780 mm).

The Bed No. 1 liquid redistibutor (Norten type)called LRD located at an elevation of 610 in. (15,250mm), which should have been below the M4 manholelevel, was found hanging at approximately 20 in. (500mm) above the top of the manhole. The LRD wasfound in distorted condition and its middle portion hadtaken convex shape viewed from bottom.

The whole Bed No. 1 had lifted up by approximately64 in. (1,600 mm) from its original position. LooseIMTP 50 packing of Bed No. 1 were found all aroundthe M4 manhole. Photos 4 and 5 indicate the disturbedbeds of the absorber.

The support beam of bed No. 1 LRD with its endsdistorted was found loose above manhole M4 andbeing stuck up at ring support of Bed No. 2.

The multibeam support plate of Bed No. 2 alongwith its supporting beam was not clearly visible. Thebeam had sheared from its support bracket and enteredin the IMTP 40 packing of Bed No. 2 after leaving itsoriginal position.

Probable Causes. The possibility of constructiondefects and weak structure of the tower internals wereconsidered to be probable causes of the failure. Theplate thickness used for bed supports and clamps wasonly 2 mm. The extent of damage, however, suggestedthat forces of great magnitude acted in the upward


SHELL (25 M M TUK)

SOLUTIONINLET NOZZLE'< A 2 >

496« X10THK

900 (j) CHIMNEY

Figure 8. Second regenerator (modified arrangement).

LEAN SOLUTION INLET(A1) M1

MULTI-BEAM SUPPORT

SEMI -LEANSOLUTION,NLET (A 2 & A 3)

PROCESS GASINLET (A 4)

PACKING DETAILS

BED1234

5

VOLUME (M3)104.9104.948.348.3

11.0

TYPEIMTP50IMTP40IMTP40MELLAPACK250 Y

IMTP 70

LIQUID REDISTRIBUTOR PLATESBENT UPWARDS

MULTI BEAM SUPPORT GOTM4 DISPLACED FROM T.S.R.

L.R.D. WAS DAMAGED &LIFTED ABOVE M-4

(B2) RICH SOLUTION OUTLET

Figure 9. Vetrocoke absorber.


PACKING MATERIALOF BED NO. 1

MULTI-BEAM SUPPORTOF BED NO. 2 LYINGLOOSE IN THE BED.

DISTORTED/ DISPLACEDLRD OF BED NO. 1

DOUBLE C - BEAMLYING LOOSE

T.S.R. OF MULTI-BEAMSUPPORT

MANHOLE (M4)

T.S.R. OF LRD

Figure 10. Vetrocoke absorber.

Photo 4. Vetrocoke absorberDisturbed bed.


Photo 5. Vetrocoke absorber.Disturbed first bed liquid redistributor.

ORIGINAL

RICHGV

SOLUTION

8" HYDRAULIC TURBINEINLET NOZZLE

MODIFIED

RICHGV

SOLUTION

8" HYDRAULIC TURBINEINLET NOZZLE

Figure 11. Hydraulic turbine inlet piping.


GAS OUTLET ( B1

RICH SOLUTION INLET

LEAKAGE FROM C - SEAMWELD JOINT

PACKING DETAILS

BED

1

2

3

VOLUME(M3>

172.5

172.5

172.5

TYPE

SLOTTED RINGS

SLOTTED RINGS

SLOTTED RINGS

SOLUTION OUTLET

SOLUTION OUTLET

Figure 12. GV regenerator (old plant).

direction in the absorber. Hence, the cause of the fail-ure cannot be attributed only to the weak design.Further, absorbers of the same design have beenreported operating satisfactorily in other plants with-out any problems.

• The other possibility could be some suddenupward gas surge through the first and second bed ofthe absorber, which caused the upheaval of these bedsand buckling of LRDs.

The process gas entering at the bottom of theabsorber might have flowed backwards through thesemi-lean inlet line via the ARC-NRV circulation lineback to the solution draw-off tray in the second regen-erator. The upward lifting of the steam distributorabove the chimney in the semi-lean solution draw-offtray and also the uplifting of the first bed LRD of thesecond regenerator seems to support this view.

However, the above backflow could take placethrough this routine only when both ARC/NRV valvesand the solenoid operated valves are not holding.

A study of the construction of the ARC/NRV valvesindicated that a large quantity of gas passing backwardthrough the NRV portion and then through the ARCportion could be possible only if the internals of the

valve were severely damaged. These valves wereopened to check their condition. The springs of thesevalves were found broken. The discs of these valveswere also getting stuck up. The above conditions werecreating possibilities of backflow.

Each semi-lean pump had a solenoid valve at thedischarge which closes when the pump trips via theinterlock 1-301 A/B/C. For backflow to take place,these discharge valves must be in the open position.This can take place if the discharge valve does notclose during the tripping of the pumps, due to failureof the interlock 1-301. Malfunctioning of this inter-lock, however could not be confirmed.

Further, the backflow through the above route mayresult in reverse rotation of the semi-lean pumps.However, no damage to these pumps due to reverserotation was observed. However, the absence of areverse rotation of the semi-lean pump could beexplained by the reasoning that the liquid passing inbackflow through the valve was prevented by themotion of the decelerating machine.

• Another probable cause for the damage in theabsorber could be the fast depressurization of theabsorber by a sudden opening of the vent valve (PV-


60) located downstream of the absorber. This couldhave occurred during startup/shutdown of the plant.However, depressurization through this route couldhave resulted in the failures of the third and fourth bedas well. No failure in these beds, however, were found.This could be explained because the third and fourthbeds are inherently stronger than the first and secondbeds, as the diameter there is 99 in. (2,480 mm) com-pared to 150 in. (3,750 mm) at the first and secondbeds, even though the internals and fittings are of thesame thickness.

Repairs/Modifications. The following correctiveactions have been suggested based on all probablecauses of failures as discussed above.

• All damaged internals will be replaced with thenext highest thickness.

• In order to prevent backflow, the solenoid valvesshould be interlocked with the low speed of turbinesof the semi-lean solution pumps and lean solutionpumps so that before all the liquid is drained off, thevalve would have completely closed.

• The semi-lean flow control valve (FV-22) and thelean solution flow control valve (FV-23) should closeshut on very low solution flow.

• Extreme care should be taken to ensure that thedownstream vent valve (PV-60) is not opened sudden-ly under any circumstances.

• An additional NRV on each of the common head-ers of the semi-lean solution line and the lean solutionline should be provided.

Hydraulic turbines

The rich GV solution at high pressure coming fromthe bottom of the absorber is let down and flashed inthe upper portion of the first regenerator operating atlow pressure. This let down in pressure is carried outthrough hydraulic turbines to supply power to turbinedriven GV solution pumps and thus reduce the steamconsumption of turbines.

Problem/Failure Description. It was observed thatthe hydraulic turbine was not developing power as perdesign and thus the steam consumption of steam tur-bines was high. On inspection, the casing vanes ofhydraulic turbines were found to be eroded.

Probable Causes. Butterfly control valves have beenprovided at the inlet nozzle of the hydraulic turbine.

The shaft pins of these valves have also been found tobe broken probably due to flashing. The suddenincrease in volume and the two-phase flow at the tur-bine inlet nozzle were the probable causes of the dam-age to the hydraulic casing vanes.

Repairs/Modifications. The butterfly control valveshave now been shifted away from the inlet nozzle ofhydraulic turbine to achieve laminar flow to the tur-bine inlet, as shown in Figure 11.

First regenerator

The first regenerator is a carbon steel tower provid-ed with stainless steel internals with operating pres-sure of 14.2 psig (1 kg/cm2g). It is a packed towerhaving 147 in. (3,680 mm) diameter, 1,855 in. (46,375mm) height and contains stainless steel packing mater-ial distributed in three beds.

Problem/Failure Description. The rich solution line(20 in.) carrying rich solution from the bottom of theabsorber to the top of the first regenerator through twoinlet nozzles was vibrating heavily. Frequent leakswere observed at the welding joints at the upstreamstub end of the butterfly valves provided in the inletlines and these leakages were recurring frequently.

Probable Causes. The rich solution line is dividedwith two branches near the first regenerator and,hence, enters the vessel at two points. In both branch-es, butterfly valves have been provided near the firstregenerator. These valves were causing restriction inthe flow and hence the vibration in the lines. Vibrationresulted in the increased load on the welding jointsand the failure of the joints.

Repairs/Modifications. Both the 20 in. butterflyvalves and flanges were removed and the gaps werefilled by providing 20 in. SS-304 spool pieces.

G V regenerator

The GV regenerator in the CC>2 removal system ofAmmonia-1 has been in operation since 1988. Theplant was originally built with the Benfield processand was converted to the GV dual activator process in1997.

The regenerator is a carbon steel tower providedwith stainless steel internals and operating at 14.2 psig


NORTHODEG

180 DEGM2 SOUTH

LINER GAPEXISTS

NO LINERGAP

LINER GAPEXISTS

NO LINERGAP

LINER GAPEXISTS

Figure 13. GV regenerator: development of liner.

2 NOS.INLETNOZZLES180 DEGAPART

SUPPORTINGSTRIPS

10 NOS. SUPPORT CLEATS

10 MM GAP

SHELL (16MMTHK)

8 MM. THICK SHROUD

CIR. SEAM OF SHELL

8 NOS. SUPPORT CLEATS

TRAY SUPPORT RING

BED LIMITER GRID

BED SUPPORT

Figure 14. GV regenerator: sectional view.


NORTH ODEG 180 DEG SOUTH

M2

- SHELL

SHROUD

AREAS OF CORROSION ON SHELL

CIR.SEAMWELD

SHROUDLOWEREDGE

TRAY SUPPORT RING

Figure 15. GV regenerator: development of shell and shroud showing areas of corrosion.

(1.0 Kg/cm2g) pressure. It is a packed tower having196 in. (4,900 mm) diameter, 1,796 in. (44,900 mm)height, and contains stainless steel packing materialdistributed in three beds. Rich solution to the regener-ator is fed through two tangential entries (called anecklace), as shown in Figure 12. The above two inletnozzles are welded to the 8 mm thick stainless steelliner provided to protect the carbon steel shell fromsevere inlet flow conditions. Broad specifications andthe general arrangements drawing of the GV regenera-tor are presented in Figure 12.

The CO2 removal system of ammonia plant has beenoperating normally except that the CO2 slip was highat around 1,400-1,600 ppm. A consultants' expert inthese systems was called in the last week ofSeptember 1997 to analyze the problem of high CO2

slip. Following the recommendations of this consul-tant, various chemicals were added to the system toincrease the concentration of chemicals hi the solution.

Only marginal advantage in the reduction of CO2

sup was observed. However, it was observed that theiron content in the solution was increasing. The ironcontent in the solution had increased from 67 PPM on

September 30, 1997 to 127 ppm on October 15, 1997in a very short span of two weeks time and was aclear-cut indication of heavy corrosion taking place hithe system.

V+5 to total V ratio was being maintained at thesame level of around 15% as was maintained with theBenfield system. KNO2 and V2O5, however, wereadded to increase the ratio of V+5/V to stop furthercorrosion. However, iron level continued to increase inthe solution.

It was observed on October 18, 1997 that the GVregenerator had started leaking from the top, resultingin continuous GV solution droplets falling down. Theleaking zone was thoroughly inspected and the leakwas arrested by welding. On October 21, 1997 anotherleak was observed about 180° opposite the previousleak. An attempt was made to arrest the leakage byproviding a box around it. This was not possible as thevessel thickness had been reduced by corrosion to theextent that welding was impossible. Thickness mea-surements showed patches of reduced thickness. It wasdecided to shutdown the plant and carry out a thor-ough inspection and repair.


Problem/Failure Description. The Ammonia Plantwas shut down in October 1997 to carry out a thor-ough inspection and repair of the GV regenerator. Onopening the regenerator, the following observationswere made.

• Black color deposition was found above theshroud.

• Both the necklace weld joints with liner werefound cracked in two places in each joint. The lengthof the crack was about 12 in. (300 mm).

• The liner plate had gotten deformed and wastouching the regenerator main shell at several places,as shown in Figure 13. The gap between the liner andthe shell should be 10 mm as per design (Figure 14).

• Heavy corrosion on the shell near and includingthe tray support ring was found in three places, asshown in Figure 15.

• Corrosion of the shell at several places just belowthe lower edge of the S S liner were also found, asshown in Figure 15.

• Lower cleats welding with liner were foundcracked.

• Some of the weldings of end plates of Omega trayswere found broken. At two places, end plates weremissing. A broken piece of 690 mm x 280 mm wasalso found loose.

Probable Causes. The following reasons put togeth-er can be attributed to the fast corrosion in the GVregenerator and its subsequent leakage:

• The stainless steel liner plate became deformedand was touching the shell at various places. Cleats ofthe liner were also found cracked. Also, there is two-phase flow at the inlet. This must have resulted invibrations in the liner and damage to the passivationlayer. The places where there was no gap between theshell and liner corrosion could be due to stagnatedsolution.

• The V+5/V ratio was slightly on the lower side ataround 15% in comparison to the consultants recom-mendations of a mintmum value of 20% and probablywas not sufficient to give the desired protection to thecarbon steel shell.

• Increase in concentration of chemicals further

aggravated the situation for corrosion.Repairs/Modifications. • It was decided to cut the

liner by about 8 In. (200 mm) from the bottom at theplaces where there were no gaps between the liner andthe shell to check for further damage to the shell. Aftercutting, it was discovered that some of the shell areasand the circumferential seal welds behind the linerwere found badly corroded. Another 18 in. wide by 80in. long (450 mm x 2,000 mm) section of the liner wasremoved to inspect the condition of the shell. No fur-ther corrosion was observed on the shell behind theliner.

• A total of about 35 stainless steel cleats were weld-ed behind liner to maintain a uniform gap between theliner and the shell throughout the periphery. This wasdone to ensure no further contact between the linerand the shell in the future to avoid damage to the pas-sivation layer and to avoid stagnation of the solution.

• Some of the welding of end plates of omega trays,which was found to be broken, were rewelded.

• All the corroded areas of the shell were repaired byfilling material with welding. All the repair weldswere ground finish and DP tested. The 18 in. (450mm) width liner was rewelded hi position.

• The cracks on both necklace to liner joints werealso repaired and DP tested.

Conclusion

The failures presented in the article were caused bya number of different factors including design defi-ciencies, defects introduced during manufacturing orfabrication, service related deterioration, upsets duringplant operation, and so on.

The cases presented do not indicate that a particularsystem or design is more prone to failures than others.Instead, these examples must be carefully analyzed toprevent their occurance hi other plants.

The awareness of the conditions which produce fail-ures helps the plant personnel to reduce the potentialfor failures. This also helps in purchasing the mostsuitable equipment for a given operation and ensuringproper design and fabrication of the equipment.


Documents

1998: Case Study of CO2 Removal System ... - IFFCO : KANDLA