MATHURA REFINERY

Mathura Refinery

January 20, 2010

Report on Suitability of metallurgy for high Sulfur & Nitrogen VGO feed in DHDS.Ref: MR/IPN/67Revision - 1By:MATHURA REFINERYInspection Section

Executive Summary1. The Design Parameters of the unit for original and VGO case as below: Sl. No.Feed rate and impurities levelOriginal DesignDiesel CaseVGO Case

1Feed rate (m3/hr)161.278.4

2Sulphur (Wt% max)1.452.8

3Nitrogen (ppm)120800

4Stripper Inlet Temp. 270290

5Hydrogen in C-02 feed24701.61ppm vol.32423.13 ppm vol.

2. The revamp of the unit was carried out in Jul2007 to process VGO as feed on need basis. However, VGO process may be required on sustainable basis after FCCU revamp.3. Unit operation with VGO as a feed has been carried out nine times so far. After revamp in Nov2007 trail run for 05 days was conducted successfully.

4. Significant corrosion product in the form of Sulphide scale was found in Stripper Bottom Pump during 2nd time VGO processing. 5. Need was felt to find out the probable source of corrosion product and suitability of the existing metallurgy for the proposed case to process VGO on a sustainable basis with minimal corrosion product/ Problem to avoid any unwanted failure. 6. The main areas affected due to high Sulphur and Nitrogen are as follows.a. Reactor feed upstream of H2 injection (02-V-01,P-01 and connected Piping)b. Reactor feed downstream of H2 injection (02-E-01A-E,E02,F01,R01,R02 and connected Piping)c. Reactor effluent circuit and REAC. (02E-02,E01E-A,V32,AC01,E05,V03 and connected Piping)d. Stripper Feed, Bottom and stripper column (02-E-04A-C,E03,C02,AC03 and connected Piping)e. Stripper over head system (02-AC-02,E08 and connected Piping)7. The requirement of metallurgy up gradation based on the study is as follows- 02-C-02: Part shell with SS410 lining, 02-E-04C: T/B up gradation to A.S., 02-E-08: T/B up gradation to Duplex SS. - Piping: Stripper feed & Bottom ckt. from E03 to C02 with SS321 & C02 to P05A/B to E4C with A.S. - Up-gradation of 02-C02 column top 10 trays with SS316L material.

Detail report is enclosed which may be suitably converted into action plan after wetting by process Licenser of the Unit M/s Axens. Proposed modifications are also shown in PFD enclosed as an Annexure-I.Detail report is put up for kind perusalINTRODUCTIONDiesel Hydrodesulphurization unit (DHDS) at Mathura Refinery was commissioned in Aug1999 with design capacity of 1.1 MMTPA (137.5 T/hr) with single reactor configuration, licensed by M/s Axens, France. The unit was originally designed to produce diesel with sulfur content of 2000 ppm. However, in Nov 2000, the second reactor was added for producing diesel with S content of 200 ppm. Originally unit was designed to process 161.2m3/hr Diesel. The material selection of the equipment / piping was based on the design impurity level in the feedstock originally specified as 1.45 wt% Sulphur and 120 ppm wt. Nitrogen. With the commissioning of DHDT in May05, a part of DHDS capacity was underutilized. Accordingly, for effective utilization of available surplus DHDS facility towards Refinery margin improvement by processing more of cheaper high sulfur crude, a low cost retrofit for sequential processing of Vacuum Gas Oil was carried out in Jul2007 under the license of M/s Axens, France. The new unit designed feed stock parameters are 78.4m3/hr of VGO feed rate with impurity level 2.8 wt% Sulphur and 800 ppm wt. Nitrogen.The detail in-house Engineering for the new equipment and piping was carried out with reference to the technical specification of M/s Axens.The first trial run in VGO mode was taken from 14th Nov to 18th Nov2007 satisfactorily. Thereafter VGO processing was carried out on following period as given below

2nd VGO run: 06.09.2008 to 10.09.2008. 3rd VGO run: 20.12.2008 to 23.12.2008. 4th VGO run: 07.08.2009 to 10.08.2009. 5th VGO run: 19.08.2009 to 10.09.2009. 6th VGO run: 15.09.2009 to 21.09.2009 7th VGO run: 16.11.2009 to 19.11.2009

8th VGO run: 13.12.2009 to 15.12.2009

9th VGO run: 07.01.2010 to 09.01.2010

After the second run of VGO operation and after changeover to Diesel operation, corrosive material in the form of iron flakes were observed in the stripper column bottom pump, 02-P-05A/B suction strainer. Frequency of choking was 4 to 6 hrs and took about one week to clear the corrosion product.An exercise was carried out to identify the cause of corrosion product in stripper bottom pump and to check the suitability of the existing equipment / piping metallurgy in the unit and identify the areas needing metallurgy / hardware upgrades. This report addresses the respective problems and suitable suggestions considering the change in the feedstock specifications as above.1. TECHNICAL DISCUSSION: Following technical articles and standard were referred with respect to the corrosion due to high Sulphur and nitrogen. API 571: Sulfidation - Corrosion of carbon steel and other alloys resulting from their reaction with sulfur compounds in high temperature environments. The presence of hydrogen accelerates corrosion. Sulfidation of iron-based alloys usually begins at metal temperatures above 500oF (260oC).

Modified McConomy curves showing typical effect of temperature on high temperature Sulfidation of steels and stainless steels.API 571: High Temp H2/H2S Corrosion The presence of hydrogen in H2S streams increases the severity of high temperature sulfide corrosion at temperatures above about 500oF (260oC). This form of sulfidation usually results in a uniform loss in thickness associated with hot circuits in hydro processing units.Critical Factor:a) The major factors affecting high temperature sulfidation are the temperature, the presence of hydrogen, the concentration of H2S and the alloy composition.b) When hydrogen is present in significant quantities, corrosion rates are higher than those associated with high temperature sulfidation in the absence of hydrogen.c) Sulfidation rates increase with increasing H2S content and especially increasing temperature as illustrated in Figure below.d) Higher corrosion rates are found more in gas oil desulfurizers and hydrocrackers than naphtha desulfurizers by a factor of almost 2.f) Increasing chromium content of the alloy improves resistance. However, there is little improvement with increasing chromium content until about 7-9Cr.

Corrosion rate of carbon steel in H2/H2S service in a naphtha desulfurizer from the Modified Couper-Gorman curves.API 581 High Temperature Sulfidation Module by API Spring Conference - 2005H2S/H2a) Consideration for general thinning in Gas Oil or Naphtha serviceb) Based on Couper and Gorman curvesc) Key operating temperature range from 400 1,000 OFd) Currently does not consider velocity or localized elevated temperatures (maximum temperature) that might locally increase corrosion ratesInfluence of Sulphur On High Temperature Degradation Of Steel Structures in the Refinery Industry - BY Joanna Huciska, Gdask University, PolandThe main forms of damage caused by Sulphur to the steel structures include weight loss corrosion and sulphide stress cracking in low temperature aqueous environments, and high temperature sulphide corrosion in non aqueous environments at 200 500CSulphide corrosion without hydrogen present:The modified McConomy curves suitable for hydrocarbon fractions containing 0.6 wt % of Sulphur and correction factors for the fractions with various total Sulphur content are presented. Beneficial effects of alloying steels with chromium may be seen. Corrosion rates are roughly tenfold reduced when ferritic 9Cr steel instead of carbon steel is applied. Lowest corrosion rates are noted for austenitic steel.In certain circumstances these modified McConomy curves have been proven unreliable, particularly in hot distillation section of hydrocracker units. In some conditions they under predict the observed corrosion rates, and very low Sulphur levels (< 30 wppm total Sulphur) are beyond the parameters of the curves. Further data are needed to be collected in order to review and assess the existing Sulphide corrosion prediction curves used by the refinery industry

Sulphide corrosion with hydrogen presentThe presence of hydrogen in some refinery operations, for example hydrotreating, hydrocracking and catalytic reforming, increases the severity of sulphide corrosion. In this case the corrosion is detrimental not only because of metal loss but also because of volume of sulphide scale formed Figure showing the effect of temperature and hydrogen sulphide concentration on corrosion rates in H2-H2S environment in carbon steel (gas oil), 1.5 REFINING OF KUWAIT'S HEAVY CRUDE OIL: MATERIALS CHALLENAGES by H.M. ShalabySulfur at a level of 0.2% and above is known to be corrosive to carbon and low alloy steels at temperature 232oC to 455oC. At high temperature conditions, the presence of Naphthenic acids was found to increase the severity of sulfidic corrosion. Presumably, the presence of these organic acids disrupt the sulfide film thereby promoting sulfidic corrosion on alloys that would normally be expected to resist this form of attack (i.e., 12% Cr and higher alloys). When sulfur is the only contaminant, McConomy curves, with other factors, are used to predict the relative corrosivity of crude oils and their various fractions. Important elements include:a. The increased severity of corrosion with sulfur concentration and service temperature between 250oC and 400oC, andb. The benefit of increased Cr content in steels to reduce the corrosion rates. c. The McConomy curves are useful in estimating the corrosion rate that will be expected based solely on sulfur content. 1.6 ENGINEERING STANDARD FOR CORROSION CONSIDERATION IN DESIGN by IMP

Effect of temperature and hydrogen sulfide content on high-temperature H2S/H2 corrosion of carbon steel (gas oil desulfurizers) 1 mil/yr = 0.025 mm/yr2.0

OPERATIONAL HISTORYThe following are the important parameter before and after change over to VGO feed from material and corrosion point of view.Sl No.Feed rate and impurities level

Original DesignDiesel

VGO

1Feed rate (m3/hr)161.278.4

2Sulphur (Wt% max)1.452.8

3Nitrogen (ppm)120800

4Stripper Inlet Temperature 270290

5Hydrogen in stripper feed24701.61 ppm vol.% 32423.13 ppm vol.%

Chemical analysis results of the stripper bottom pump corrosion scale:S.NO.TEST

RESULTS UNIT1. Moisture content

4.37

%

@ 100C2. Loss on ignition 12.42

%3. Fe as Fe2O3

68.82

%4. Silica as SiO2

12.24

%5. Sulphide 2.67

%3.0 CORROSION BEHAVIOUR AND MATERIAL SELECTIONThe composition of Reactor Feed, Reactor effluent streams and Amine column feed will change due to increase in S & N2 content of the feedstock. As a result, this is expected to affect the corrosion behavior as discussed below,3.1 Reactor Feed System3.1.1Up-stream of the Hydrogen Injection Point:The feed circuit upstream of the Hydrogen injection point is susceptible to corrosion due to presence of Sulfur (>2.8 wt %) / dissolved H2S in the feed. The corrosion phenomena normally occur above 240 deg C in case of high temperature Sulfur corrosion & Naphthenic Acid corrosion. High temperature Sulfidation begins at metal temperature above 260 deg C (Ref. API 571, 4.4.2.3) to Carbon Steel metallurgy necessitating up gradation. The corrosion rate largely depends on the amount of these impurities present in the feed, temperature and turbulence.Equipment and piping of the Circuit:SL. No. EquipmentTemperatureMaterialRemarks

1.02-V-0145(In case of VGO Temp is 800C)CSSatisfactory

2.Piping: 02V01 to P01.45(In case of VGO Temp is 800C)CSSatisfactory

3.1.2 Down-stream of the Hydrogen Injection Point (Up to Reactor):After the Hydrogen injection point, susceptibility to Hydrogen attack and high temperature H2-H2S corrosion also becomes prevalent as the temperature of the feed is increased. The threshold temperature for H2-H2S corrosion in Carbon Steel depends on the amount of H2S introduced with the recycle gas, but mostly it is 246 deg C. Hydrogen attack becomes a material consideration in the Reactor feed system above 232 deg C (H2 partial pressure > 50 psia : Ref API 941). However, As per API 571 H2&H2S corrosion in CS material is very much prominent at 260 deg C. as shown in the Modified Couper-Gorman curve above under Ref. of API 571.The curve indicates higher corrosion rates are found more in gas oil desulfurizers and hydrocrackers than naphtha desulfurizers by a factor of almost 2.Based on above considerations, the existing metallurgy of equipment / piping, Increase in Sulphur content to a level of 2.8 wt % in the feedstock would not result into any significant corrosion attack in the Reactor feed circuit up to the I-stage Reactor.Equipment and piping of the Circuit:SL. No. EquipmentTemperatureMaterialRemarks

1.02-E-01A (Shell)80-100CS, NACESatisfactory

2.02-E-01B106 - 130CS, NACESatisfactory

02-E-01C150-200CSSatisfactory

02-E-01D200-236AS(P11)Satisfactory

02-E-01E236-270.6 (289 at EOR)AS (P11)Minor corrosion in high Sulphur service

02-E-02270.6-316AS+SS321 CLADSatisfactory

02-F-01305- 357SS321HSatisfactory

02-R-01374AS+SS347Satisfactory

02-R-02374AS+SS347Satisfactory

Piping:E01A to E1BE1B to E1CE1C to E1DE1D to E1EE1E to E02E02 to F01F01 to R01R01 to R02106150200236316SSSSSSCSCSCSCSAS (P11)SS321SS321SS321

Satisfactory

3.2 REACTOR EFFLUENT SYSTEMThe material selection for Reactor Effluent System from 1ST Reactor to 2nd and 2ND Reactor bottom to Reactor effluent exchanger 02-E-02 & 02-E-03 is based on the high temperature (> 246 Deg C) H2-H2S corrosion and High temperature (232 deg C) H2 attack. However, the corrosion rate largely depends upon the temperature and the partial pressures of H2S / H2. In case of increase in S content in the feed VGO from the designed value, the H2S partial pressure in the Reactor effluent would increase. The following are the material and temperature configuration. Acceptable limit for corrosion rate in CS metallurgy is 10 mpy (0.25 mm/yr) as per M/s Chevrons and metallurgy upgradation required as per the following limiting criteria mentioned below 1.1 Due to high temperature H2-H2S corrosion.a) 246 deg C for H2S partial pressure of 100 psia (7 Kg/cm2)b) 252 deg C for H2S partial pressure of 10 psia (0.7 Kg/cm2)c) 274 deg C for H2S partial pressure of 0.1 psia (0.07 Kg/cm2)d) 382 deg C for H2S partial pressure of 0.01 psia (0.007 Kg/cm2)1.2 Due to high temperature H2S corrosion.a) 288 deg C for H2S concentration greater than 2500 ppmwb) 299 deg C for H2S concentration of 2500 ppmwc) 311 deg C for H2S concentration of 800 ppmwd) 318 deg C for H2S concentration of 150-200 ppmwe) 321 deg C for H2S concentration of 30-100 ppmwCriteria 1.1 b) is applicable at reactor outlet circuits and 02-E-02 & E-03 heat exchanger.Equipment and piping of the unit:SL. No. EquipmentTemperatureMaterialRemarks

02-E-02 (T/S)371-300Tube: SS321Satisfactory

02-E-03(T/S)371-272Tube: SS321Satisfactory

02-E-01E(T/S)299-275Tube: SS321Satisfactory

02-E-01D(T/S)275-245Tube: SS321Satisfactory

02-E-01C(T/S)245-211AS (T11)Satisfactory

02-E-01B(T/S)211-168CSSatisfactory

02-E-01A(T/S)168-135CSSatisfactory

02-V-32141CSSatisfactory

02-AC-0196-65CSSatisfactory

02-E-05(S/S)65-50Shell: CST/B: SS316LSatisfactory

02-V-0350CS, NACESatisfactory

Piping:R01 to R02R02 to E02E02 to E03E03 to E1EE1E to E1DE1D to E1CE1C to E01BE01B to E01AE01A to V32V32 to AC01AC01 to E05E05 to V03.357371371299275245211168141966550SSSSSSSSASASCSCSCSCSCSCSSatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactorySatisfactory

This temperature is lesser of the threshold temperatures of H2-H2S corrosion (246 deg C) and H2 attack (232 deg C) in CS material.Hence metallurgy is adequate for handling Reactor Effluent stream up to the inlet of Reactor Effluent Air Cooler.Naphthenic acid-resistant materials are not needed beyond the I-stage Reactor, because the acids are destroyed quickly upon contact with the catalyst.3.3 Reactor Effluent Air Coolers (REAC) and Outlet pipingThe Reactor Effluent stream entering the REAC contains both Ammonia and Hydrogen Sulfide, which react to form Ammonium Bisulfide. At a temperatures less than 100 deg C, the Ammonium Bisulfide crystallizes out of the vapour phase. This may quickly plug up the REAC tubes and cause severe erosion-corrosion. To prevent plugging of the REAC tubes, continuous wash water injection is given at the inlet of REAC. The resultant Ammonium Bisulfide solution is highly corrosive to Carbon Steel. The presence of small quantities of cyanides and Ammonium Chloride in the process fluid tends to further accelerate corrosion.Detailed study of REAC corrosion by specialists has led to a general understanding of the following important factors;a) Corrosion rate increases with increase in concentrations of Ammonia and Hydrogen Sulfide in the process stream.b) Severe corrosion-erosion of the tube / tube ends, particularly Carbon Steel metallurgy is likely at process fluid velocities in excess of 20 ft/sec.c) Increased rates of water injection ahead of the REAC tend to reduce corrosion. Conversely, water injection at less-than-recommended rates can lead to accelerated corrosion. The presence of Oxygen and high level of dissolved iron in wash water leads to rapid corrosion and fouling. Hence, the injection water must be free of Oxygen (< 15 ppb).d) Good flow distribution of vapour, liquid hydrocarbon and water phases is essential to prevent corrosion. This is accomplished by using a balanced inlet as well as outlet piping for REAC and by keeping fluid velocities high enough to minimize phase separation. The phase separation problem places a lower limit on the velocities (>10 fps) in the REAC, while 20 fps corrosion-erosion limit places a maximum on the permissible velocity range.e) Injection of Sod Polysulfide ahead of REAC helps to reduce corrosion. The Polysulfide is typically added to the injection water.To sum up the above, the major factors that affect REAC corrosion are given below:

The Kp factor for the Diesel and VGO cases are as follows:Diesel EOR: H2S: 2.459836 & NH3: 0.027305Kp Factor for Diesel Case: (mol% H2S X mol% NH3) = 0.067165 (Limit 0.2. The Process licenser needs to be consulted for any requirement in increase in wash water injection rate or metallurgy up gradation. The sour water concentration in 02-V-03 and REAC inlet velocity needs to be checked. Metallurgy up gradation of the Reactor Effluent Air Cooler (REAC) together with the outlet piping shall be required from carbon steel to Duplex 2205 in case of any of the following process parameters being exceeded: a) Kp (mol %NH3 x mol % H2S at inlet to the REAC) > 0.2b) % NH4HS in separator sour water > 8 wt% (measured at 02-V-03)c) Velocity at inlet and outlet piping exceeds 20 fps5.6 Metallurgy upgradation of the Stripper O/H cooler tube bundles in 02-E-08 is required from Admiral Brass to Duplex 2205 in view of higher H2S and NH3 concentration. The Diesel case does not contains NH3. The VGO case contains: H2S 25413 ppm vol. & NH3 - 163.1654 ppm vol. 5.7 The diesel stripper column was inspected during the Jul2009 shutdown and severe corrosion of the top 10 trays of material SS410 observed. The trays were found to be perforated and removed in pieces. Considering the sever corrosion of the SS410 trays the top ten tray needs to be upgraded to SS316L material of austenitic steel. The above metallurgy adequacy check has been done based on data provided from as built documents of the Equipment. The above proposed recommendations need to be vetted by the Licensor (M/s Axens) prior to initiating any action in this regard.Submitted for kind perusal,Sudarshan Kumar

Dattatray B. Walekar

DMIP

SPSEIPM

- DGM (TS) Thru CIPM- GM (TS)

Annexure-I

Column Feed line from E03 to C02 with SS321.

Column bottom up to & including E4C (T/B) with AS

Stripper Column Shell from Tray no. 13 to bottom portion with SS410 Lining & Tray no. 1 to 10 with SS316L

Stripper O/H Cooler T/B Duplex SS

EMBED AutoCAD.Drawing.15

Annexure-I

Column Feed line from E03 to C02 with SS321.

Column bottom up to & including E4C (T/B) with AS

Stripper Column Shell from Tray no. 13 to bottom portion with SS410 Lining

Stripper O/H Cooler T/B Duplex SS

EMBED AutoCAD.Drawing.15

Report on suitability of metallurgy for high sulfur and nitrogen feed in DHDS

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