Paper No. 577 EXPERLENCE WITH NAPHTHENIC ACID CORROSION IN LOW TAN CRUDES M. J. Nugent Tosco Refining Company Bayway Refinery 1400 Park Ave. Linden, NJ 07036 J. D. Dobis KLAD Inc. 212A South Bridge St., Suite 202 Elkton, MD 21921 ABSTRACT Over the past few years, it has become evident that naphthenic acid corrosion can occur at much lower TAN levels than the previously reported crude TAN level of 0.5. Experience with naphthenic acid corrosion at low TAN levels is most often associated with sweet crudes (less than 0.5% Sulfur). This paper details the corrosion damage caused by sweet, low TAN crudes in a Crude/Vacuum unit designed for sour crude service. The crudes were primarily from West Africa. The various metallurgical upgrades used to improve plant reliability including furnace repairs, clad vacuum furnace headers and transfer lines, and vacuum tower cladding and internals work are described. Keywords: naphthenic acid corrosion, TAN, sour crude, vacuum tower, crude unit, vacuum unit, reliability, transfer line, cladding, clad pipe. INTRODUCTION Naphthenic acid corrosion (NAC) is a non-aqueous attack by organic acids present in some crude oils. The presence and the quantity of these acids in crude oils has been generally reported by the Total Acid Number (TAN) or Neutralization (Neut) number, expressed as milligrams of potassium hydroxide required to neutralize a gram of oil, as per ASTM D664, although recent work is ongoing to develop a more accurate measurement of the naphthenic acid content. For many years, conventional wisdom held Copyright 01998 by NACE International. Requests for permission to pubkh this manuscript in any form, in part or in whole must be made in writing to NACE International, Conferences Dwlsion, P.O. Box 218340, Houston, Texas 77218-8340. The mate1‘Ial oresented and the views exoreskd in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
Transcript
Paper No.
577
EXPERLENCE WITH NAPHTHENIC ACID CORROSION IN LOW TAN CRUDES
M. J. Nugent Tosco Refining Company
Bayway Refinery 1400 Park Ave.
Linden, NJ 07036
J. D. Dobis KLAD Inc.
212A South Bridge St., Suite 202 Elkton, MD 21921
ABSTRACT
Over the past few years, it has become evident that naphthenic acid corrosion can occur at much lower TAN levels than the previously reported crude TAN level of 0.5. Experience with naphthenic acid corrosion at low TAN levels is most often associated with sweet crudes (less than 0.5% Sulfur). This paper details the corrosion damage caused by sweet, low TAN crudes in a Crude/Vacuum unit designed for sour crude service. The crudes were primarily from West Africa. The various metallurgical upgrades used to improve plant reliability including furnace repairs, clad vacuum furnace headers and transfer lines, and vacuum tower cladding and internals work are described.
Keywords: naphthenic acid corrosion, TAN, sour crude, vacuum tower, crude unit, vacuum unit, reliability, transfer line, cladding, clad pipe.
INTRODUCTION
Naphthenic acid corrosion (NAC) is a non-aqueous attack by organic acids present in some crude oils. The presence and the quantity of these acids in crude oils has been generally reported by the Total Acid Number (TAN) or Neutralization (Neut) number, expressed as milligrams of potassium hydroxide required to neutralize a gram of oil, as per ASTM D664, although recent work is ongoing to develop a more accurate measurement of the naphthenic acid content. For many years, conventional wisdom held
Copyright 01998 by NACE International. Requests for permission to pubkh this manuscript in any form, in part or in whole must be made in writing to NACE International, Conferences Dwlsion, P.O. Box 218340, Houston, Texas 77218-8340. The mate1 ‘Ial oresented and the views exoreskd in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
that naphthenic acid corrosion generally did not occur in crudes with a TAN less than about 0.5 mg per gram (‘)
Where NAC is found, corrosion rates are affected by the activity of the particular naphthenic acids present, as well as by their concentration. The acids are most active under boiling/condensing conditions, which are affected by the oil temperature and pressure as well as velocity.
Naphthenic acid attack occurs primarily in crude units and vacuum units. NAC in Fluid Catalytic Cracking Units and in units that handle cracked products is negligible since these acids decompose between 750’ F and 900” F (400” C and 480” C). Catalysts also decompose the acids @IDS, FCC’s, etc.) Problems with naphthenic acid corrosion can occur in the feed preheat sections when the oil starts to vaporize, and in the lower and sidestream equipment of naphthenic acid containing streams.
As previously mentioned, the industry benchmark for considering a crude to be naphthenic is a TAN of at least 0.5. There has been some discussion that a crude with a TAN of less than 0.5 could still cause significant corrosion problems depending on the specific acids found in that crude and the sulfur content of that crude. The former British Petroleum Marcus Hook, PA (now Tosco Trainer, PA) refinery had a history ,of NAC incidents with crude slate TAN’s less than 0.5. A summary of the operating history, recent failures, metallurgical upgrades and corrosion monitoring results will be presented.
BACKGROUND
The two crude and three vacuum units were designed and built in the 1950’s for sour crude operation, Materials of construction for services above about 500’ F (260” C) consisted of carbon steel (CS) and 5 Cr piping, and 405/41OSS tower internals and cladding. These units performed relatively reliably until the late 1980’s and early 1990’s when a series of failures and onstream leaks occurred. The refinery had been processing increasing amounts of sweet low TAN crudes for several years prior to these failures.
In 199 1, an onstream leak at a 5 Cr vacuum furnace outlet elbow prompted an incident investigation, A series of scattered but similar failures among the three units led to the conclusion that naphthenic acid corrosion was the primary cause. The conclusion that low TAN, low sulfur crudes caused the failures was initially questioned by plant personnel. Subsequent communications with nearby refineries processing similar crudes revealed similar problems. These crudes were primarily from West African countries including Nigeria and Angola.
Supporting evidence was uncovered from sister European refineries. Among their findings was a velocity limit of approximately 154 to 180 fps (47 to 55 m/s) for a specific Nigerian crude, above which NAC would severely erode transfer piping made from CS, 5 Cr and 12 Cr.
NAC in these crudes appears to be influenced by operating characteristics, especially crude and vacuum heater outlet temperatures. Units with a high crude outlet temperature tend to vaporize some of the more aggressive, high boiling point acids in the crude transfer line as discussed by Piehl (*) Under these conditions, high velocity, 2-phase NAC can occur in the & transfer line as experienced by a nearby refinery. The crude furnace outlet at the refinery discussed in this paper historically ran in the 625-650” F (330-345” C) range and experienced problems only in the vacuum units. It is believed that the more aggressive, higher boiling point acids remained in the reduced crude that was fed to these units (3 - 4,
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CORROSION FAILURES
As previously mentioned, a series of incidents occurred in the three vacuum units which is characteristic of NAC problems associated with these crudes, as follows:
Localized, severe loss in thickness of 5 Cr vacuum furnace outlet elbows under high velocity flow and partial vaporization,
Corrosion in elbows and straight sections of 410 clad vacuum transfer lines.
Severe corrosion of 405/41OSS cladding on shells of vacuum towers at transfer line inlet areas.
Uniform corrosion of 405141OSS shell cladding, tower packing and internals in HVGO, Wash Oil and recirculating spray header sections at temperatures above 450” F (232” C) and velocities much less than 50 fps (15 m/s).
Erosion corrosion of 12 Cr thermowells in heater outlet and transfer line applications,
Corrosion of CS HVGO piping circuits. Note: The Trainer refinery did not experience this problem as confirmed by extensive UT thickness monitoring and profile radiography. However, a nearby refinery running similar crudes experienced high corrosion rates (‘)
Corrosion of 304LSS crude transfer lines running at high crude furnace outlet temperatures (Q
CORROSION MONITORING
A total of seven locations in two vacuum towers on two crude units running similar feedstocks were monitored over a six-year period. Each location had a retractable ER probe, with 12 coupons affixed to the end with a coupon holder. The coupons tested included 316LSS and 317LSS with varying MO content to determine the minimum Moly required for corrosion resistance. In addition, ER probes with measuring elements of CS, 410SS and 316LSS were also used initially, to determine the best resistance element material for long term evaluation of crude corrosivity.
The probe/coupon racks were installed in known “active” locations in the towers, including areas in structured packing beds. All locations (Figure 1) were in and around the HVGO, wash oil and LVGO draws, packing and spray headers. An additional coupon rack was installed on a bubble cap tray for one run.
After the first year of monitoring, 410SS was chosen as the preferred ER probe measuring element for long term monitoring. The 410SS alloy was selected because it is susceptible to NAC yet corrodes extremely uniformly under vapor/liquid exchange conditions in the tower; its chromium content provides good resistance to sulfidic corrosion so that changes in corrosion rate due to NAC (vs. sulfidic) are more clearly delineated than with CS. The CS corrosion rates were so high that probes needed to be changed frequently; and the corrosion rate of 3 16L was too low to detect changes in crude corrosivity.
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The long term results of corrosion coupon weight loss testing over a six year period are summarized in Table 1, Corrosion rates are based on exposures to a mix of sweet, low TAN crudes as described later. Correlation of ER probe corrosion rates with coupon loss measurements was very good. Monitoring at a high velocity location at the outlet of the vacuum furnace was recently initiated so the results are not available.
TABLE 1 CORROSION RATES IN SWEET, LOW TAN CRUDES (MPY) *
m i Wash Oil j HVGO Section i Comments Section i i _.._..__. P j j . . . . . . . . . . . . . . . . . . ................................................
UNS NO6625 : co.1 I < 0.1 Note: * For 544 Vacuum Tower Only
Crude Slate Characteristics
The crude slate during the period in question can be described as sweet, low TAN crude with typical crude Sulfur and TAN levels of (<0.25% S) and CO.5 TAN, respectively. Typical TAN and sulfur levels for the crudes which make up the major portion of the crude slate are shown in Table 2. This slate is typical for the six year period for the corrosion data presented in Table 1.
TABLE 2 TYPICAL TAN AND SULFUR LEVELS OF PROCESSED CRUDES
i Reduced I % of crude Crude i % Sulfur,.!,,Crude TAN,,.f.,.Crude TAN...i...HVG 0 TAN i .; in 1991 .............. -. ............ . ..- - _______m - ... . ..................... -. .................
Readers expecting a detailed accounting of corrosion rates for specific crudes may be disappointed that a detailed correlation could not be made. This was primarily the result of continuing changes in crude
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blend and crude blend ratios of various mixes of about 20 crudes, primarily Nigerian crudes with a mix of others including ANS and various North Sea crudes.
During a more recent run, corrosion probes and coupons were installed in the vacuum towers in 1995. The crude slate for the IO-month exposure period is shown in Table 3, This is a typical crude diet for this refinery. Of the non reported crudes, none were run in a significant volume or had a TAN greater than 0.1.
TABLE 3 TYPICAL TAN AND SULFUR LEVELS OF CRUDES IN 1995
Crude j TAN : Sulfur (wt %) i . f j_ .................. Total % of all Crude in 1995 .............. Bonny Light :
The volume average TAN and sulfur were 0.24 and 0.24 wt % respectively for all the crude run during this period. The corrosion rates were calculated from weight loss upon removal of the coupons. The following is a summary (Table 4) of the rates for some of the materials at specific locations.
TABLE 4 CORROSION RATES OF COUPONS IN 1995 (MPY)
Location Material Corrosion Rate ................................................................................... 542...Va.c..T.o.w.e r..
.;. ................................................................................ i ............................................................................................. ........................................... i UNSNOrh62.S.. ........................ ...................... . .......................................... O..c) 2 ........................................
..Wash.Qil.S.e.ctio n ....................................... j .................................. 3.Q4L .................................. i Q...l.......................................... ............................................
..Gas..Qil.S.ectio n ........................................... i .................................. 3.l.6L .................................. i .......................................... U.2 ........................................
The significance of these findings is that there is notable corrosion (>lO MPY) of the carbon steel and 410 coupons due to NAC. The 5 Cr, 9 Cr and 304L had mixed experience and the 3 16L generally performed well although there was evidence of active, measurable corrosion in the gas oil section. The Ahoy NO6625 coupons showed the best performance of all the alloys tested in all locations. All coupons were all located in the vapor space (two phase conditions) of two vacuum towers.
A great uncertainty affecting these results was the apparent increase in TAN over time for some of these crudes. Crude assays showed an upward trend in TAN over time as shown in Table 5. In addition, cargo to cargo variations in TAN were significant. Not every cargo was sampled for TAN and Sulfur. This may be due in part to the difficulties and inconsistencies between different labs measuring crude TAN, or that these crudes are well specific which has been previously reported.
TABLE 5 INCREASE IN TAN OF BONNY LIGHT OVER TIME
II 6187 i j Late ‘87 i ........................................................................ ..Cm.d e n l-l? n no
j 12/90 n r)o ................................................................................... j u..u 2 ................... ................... i ................... u.,.w ................... u o, .......................
j. ......................... a.71 ........................ 34 j 32
in year indicated
CONCLUSIONS AND RECOMMENDATIONS
l Naphthenic acid corrosion of crude and vacuum tower units occurs in sweet crudes with TAN ~0.5. Ahoy performance is strongly dependent upon operating conditions, especially crude and vacuum heater outlet temperatures, as well as specific locations within the unit.
l Molybdenum containing stainless steel and/or nickel base alloys are required for resistance to NAC. Nickel base Ahoy 625 (UNS N06625) has proven successful in this application. Sultidation has not
been observed and is not expected at temperatures experienced in crude/vacuum units (’ md ‘)
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l The following materials were upgraded to resist corrosion in Nigerian and other West African crudes. It should be noted that 3 16L stainless steel showed active, measurable corrosion losses at low velocity locations inside the vacuum tower. Although emergency replacements of furnace tubes and two transfer lines utilized 3 16L, the long term effects of high velocity NAC are not known.
Vacuum Heaters - Outlet tubes and/or high velocity piping 3 16LSS (min Moly requirement unknown) or 3 17L stainless steel.
Vacuum Transfer Line - Solid 3 16LSS or 3 17LSS clad piping
Vacuum Tower Cladding - 3 17LSS or better at inlet area, and above the HVGO sections where corrosion rates are highest.
Vacuum Tower Packing - 3 17LSS packing and internals operating above about 400” F (205” C), except tower bottom.
Crude TL, Wash Oil and HVGO piping - Evaluate to determine need to upgraded to 3 16L or 3 17LSS solid or clad piping depending on unit operating characteristics and crude slate.
Diesel and AGO Piping - No known problems with NAC of CS but should be monitored if crude outlet temperature exceeds 650” F - 675” F (345” C - 358” C) for sultidic corrosion.
REFERENCES
1. Kaley, L. et. al.; “Corrosion in the Oil Refining Industry”, NACE Conference, Sept. 26 to 27, 1996
2. Piehl, R.L.; “Naphthenic Acid Corrosion in Crude Units”, NACE Conference, CORROSION/S7, Paper No. 196, (Houston, TX, NACE International, 1987).
3. Craig, H. L.; “Naphthenic Acid Corrosion in the Refinery”, NACE Conference CORROSION/95, Paper No. 333, (Houston, TX, NACE International, 1995).
4. Craig, H. L.; “Temperature and Velocity Effects of Naphthenic Acid Corrosion”, NACE Conference, CORROSION/96, Paper No. 603, (Houston, TX, NACE International, 1996).
5. Babaian-Kibala, E. et. al.; “Naphthenic Acid Corrosion in a Refinery Setting”, NACE Conference, Corrosion/93, Paper No. 63 1, (Houston, TX, NACE International, 1993).
6. Personal communication with nearby refinery processing similar crudes.
7. Smith, G. S.; “Corrosion Resistance of Nickel-Containing Alloys in Petrochemical Environments”, NACE Conference, CORROSION/97, Paper No. 524, (Houston, TX, NACE International, 1997).
8. Dobis, J.D. et. al.; “Clad Piping Components for Refinery Applications”, Materials Performance, Vol. 36, No. 7, pp. 29 - 35, July 1997. NACE International, Houston , TX.
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I I I
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SCHEMATIC OF 542 VAC TOWER
SCHEMATIC OF 544 VAC TOWER
Figure 1. Schematic of 542 and 544 Vacuum Towers with Corrosion Probe Locations
