CORROSION UNDER INSULATION Donna Fruge Principal Production Engineer Westlake Chemical Corporation

Transcription

1 CORROSION UNDER INSULATION Donna Fruge Principal Production Engineer Westlake Chemical Corporation Karl Bishop Area Reliability Engineer Westlake Chemical Corporation Corrosion Under Insulation (CUI) is one of the predominant mechanical integrity issues affecting the ethylene industry. Occurrence can be erratic and sometimes undetectable based on visual examination. Traditional methods of addressing this issue involve selective removal of insulation for visual inspection in carbon steel services that operate from freezing to 300F. In addition to this recognized range, it is also important to look for areas that are susceptible to CUI due to swing conditions or non-flow areas, even though the design and observed operating condition of the line are outside of this range. This presentation will outline experiences with CUI resulting in leaks in lines listed as operating below 0 F. 53

2 Introduction Corrosion under insulation (CUI) has become one of the most important mechanical integrity issues within the ethylene industry. Traditional methods of addressing this issue include removal of insulation for visual inspection for operating temperatures from 25 ºF to 300 ºF. However, this does not address piping that was designed for cold service but was not identified as intermittent flow and/or a deadleg and remains at ambient conditions for most of its operating life. Background Thursday, October 11, 2007, a Shift Supervisor was investigating the operation of the pressure control valve off of the ethylene splitter to the flare when he discovered a pinhole leak in a 1 ½ inch impact tested carbon steel line, upstream of the pressure control valve. Maintenance stripped the insulation in the immediate area of the pinhole leak. The piping in the area was severely corroded, Figure 1. Due to the condition of the pipe upstream of the pressure control valve, maintenance stripped the rest of the insulation back to a 14 inch branch. Severe corrosion also existed at the branch connection, Figures 2 and 3. The installation of the impact tested carbon steel line was designed based on a design temperature of -50 F, pressure of 370 psig and an operating temperature of -12 F, per the original line list. The impact tested carbon steel piping was original installation (1991) and has not been modified. Based on the parameters listed on the original line list, this line was never identified to be inspected for corrosion under insulation. Westlake s corrosion under insulation inspection strategy inspects lines that have operating temperatures between 0 F 300 F, which goes beyond the recommended temperature range set by API standards of 25 F 250 F. The corrosion under insulation was caused by the line being at ambient conditions a majority of the time versus the -12 ºF designation on the line list and water ingression through the insulation. This line has many insulation transition and termination places, any one of which could have formed a breach where moisture entered between the pipe and the foam insulation. Based on the insulators comments, the initial stripped area at the leak location appeared to have been insulated correctly, with the foam insulation and the vapor barrier. However the through wall failure was located in an area that was susceptible to trapping moisture. 54

3 A t-clamp was installed at the 14in to 1 ½ inch branch to enclose the corrosion area until replacement during the next turnaround. The corroded portion of the 1 ½ inch impact tested carbon steel line was isolated and replaced with 304 stainless steel. After this event, the Reliability department began working with Operations to identify and inspect all stagnant, ambient pieces of pipe in the cold section of the unit. Additionally, due to the quantity of pipe and timing of the next major turnaround, an outside engineering firm was also enlisted for assistance. Two more areas of corrosion have since been discovered and replaced. 120 feet of 1 ½ inch impact tested carbon steel was replaced with 304 stainless steel. This is an ethylene refrigeration make-up line that is used once per week for approximately 3 hours at a time. When in service, and according to the original line list, the design pressure is 370 psig and the operating temperature is -11 F. However, it is typically at ambient conditions. Finally, a minor leak was discovered in a portion of carbon steel line to a moisture analyzer from the ethylene guard dryer, Figure 10. This piping was also isolated and replaced. This line is always in service; however the operating temperature is 33 F. The corrosion under insulation for this particular piece of pipe was initiated by visual inspection which found a breach in insulation, coating failure and insulation holding water. The areas of corrosion have been either isolated and replaced or clamped and pumped with no safety or environmental issues. Although the corrosion under insulation discussion has been centered around cold service piping that is either stagnant or a dead leg, piping in the process gas dryer and DeMethanizer bottoms areas are being inspected for metallurgy upgrades, specifically vents and bleeders. In addition, condensate and steam piping issues are being addressed. Corrosion Mechanism Corrosion under insulation of carbon steel is essentially an electrochemical reaction that consists of an oxidation reaction and a reduction reaction and is the combined result. Most metals and alloys prefer the ionic state rather than remain in an elemental state. An oxidation reaction is where the metal atoms give up electrons and enter an ionic state. The site at which an oxidation reaction occurs is the anode. The two common iron oxidation reactions are: Fe = Fe e - and Fe = Fe e - 55

4 The electrons are then transferred and become apart of another chemical species as part of a reduction reaction. When the steel surface is in contact with water containing dissolved oxygen and the presence of the free electrons this results in the reduction reaction: O 2 + H 2 O + 4e - = 4OH - The site at which the reduction reaction occurs is the cathode. The OH- reacts with the Fe2+ and Fe3+ to form Fe(OH) 2 and Fe(OH) 3. The final reaction is the reformation of the H2O and the precipitation of the Fe 2 O 3 oxide. The total chemical reaction is 4Fe + 6H 2 O +3O 2 = 4Fe(OH) 3 = 6H 2 O + 2Fe 2 O 3 (precipitation). Carbon steel that is insulated corrodes due to being in contact with aerated water. The role of insulation provides a crevice that retains the water and corrosive media, the material may wick and absorb water, and the material may contribute contaminants that increase or accelerate the corrosion rate. The primary water sources are infiltration from external sources and condensation. Contaminants in water can increase the conductivity of the water environment. Standard CUI Identification (25 F 250 F) Industry standards that are derived from NACE and API identify the piping systems that operate between 25 F to 250 F as having the greatest risk for developing corrosion under insulation (CUI). CUI can be broken into two categories, the first being corrosion of carbon steel due to contact with aerated water and forming corrosion cells. Carbon steel piping operating at temperatures greater than 250 F is warm enough that the piping surface stays free of moisture. When operating below 25 F any water that is present at the surface is frozen and does not provide a wet environment for a corrosion cell to develop. The second main category deals with stainless steels and their susceptibility to external stress corrosion cracking and pitting; however this paper will discuss experiences with the corrosion of carbon steel piping. Currently all piping that is identified as operating from 0 F to 300 F and insulated are part of a CUI inspection strategy that involves identifying breaches in insulation and removing insulation in suspect areas. Systems that have the greatest potential for issues with CUI have been the steam utility stations, low pressure steam and condensate piping, and regeneration piping that are insulated for heat conservation and personal protection purposes. Since the external corrosion rates are relatively the same for small bore and large bore piping, the smaller nominal wall thicknesses of line sizes 1-1/2 inch and smaller are more prone to developing through wall failures. 56

5 Steam utility stations have shown the highest potential for CUI. These piping systems are constructed of carbon steel, insulated for heat conservation, and for the most part are dead legs that stay at ambient conditions, as these sections of piping are not equipped with a steam trap and are usually 20 feet from the header. The typical orientation of the piping is a vertical leg that drops down to grade level from a main header. The piping is insulated to help prevent heat lose and condensate formation. The typical design of the steam utility station is to put a u-bolt support and valve near grade level, however, the main issue with this orientation is that it leaves a high potential for water ingression due to the number of insulation penetrations. Although properly sealed at installation, which is caulking, over time the caulk has the potential to break the seal and allow moisture ingression and eventual coating failure and corrosion cells to form. Here the areas that pose the greatest potential to develop a leak have been at the u-bolt to pipe interface and on the topside of the valve, Figure 6. Inspection for CUI starts with a visual inspection of the insulation for defects that could allow moisture to enter the system. Based on the orientation of the piping, areas of insulation are selected for removal to examine the base metal. The above case of the ethylene guard drier moisture analyzer was caught on a CUI inspection. The initial insulation inspection showed that there were several breaches in the insulation and that the insulation appeared to holding water. After removing the insulation around the valve assemble and support, a very small leak was found in the form of bubbles coming from underneath the corrosion scale at the u-bolt support location, Figure 10. The section of u-bolt in direct contact with the pipe was completely corroded away. The insulation was stripped further back to the main header to where the frost rings were present. This was approximately an 8 foot deadleg section of piping. The section of piping that was still frozen near the header showed no significant signs of corrosion and the coating was still in good condition. During a maintenance unit outage, an operator was in the process of purging the process gas dryers, when the valve he was attempting to open snapped off at the 3/4 inch nipple between the valve and header. The valve was located on the dryer effluent filter bypass line. The system operates at 60 F and is insulated. After investigating the process gas dryer system, a majority of the bleed valves were subject to CUI. The valves and nipples were replaced with stainless steel to prevent future instances of CUI at these locations. This is an example of piping that continuously operates at or near ambient conditions and is insulated to minimize ambient temperature swings, Figures 12, 13 and

6 Unexpected CUI Identification The cold section of the unit operates at varying temperatures below freezing, depending on the stage of the process. Impact tested carbon steel piping was utilized for the majority of the piping that had a design temperature greater than -50 F. The original construction specifications did not require any coating for piping designed to continuously operate below 20 F. It was found that this criteria is acceptable, provided that the line is continuously operated below freezing. This is based on visual inspection of lines that were frozen, as they did not exhibit any significant signs of corrosion. The unexpected piping that was found with corrosion problems was not correctly identified based on operating temperatures specified. The original line list identified the operating temperature for the flowing case and did not consider normal operating temperatures based on stagnate flow. The cases presented below should have been originally identified as having a CUI potential. However based on the listed operating conditions, these piping systems were not identified to have a CUI potential and were not included in the inspection strategy. The first two cases represent intermittent flow conditions while the third case represents a deadleg condition. In the below cases, none of the piping was originally coated due to being identified as normally operating below 20 F. The first case was identified in the background section which resulted in a through wall failure of an ethylene vapor line. The original specifications of the plant identified the line as operating at 12 F. At this temperature, the line was not flagged to be included in the CUI inspection strategy. After investigation, it was found that the operating temperature was correct, when the pressure control valve was open and flowing. The normal operation of the valve was to be in the closed position, creating a stagnate leg with no flow. Under these conditions the typical temperature of the line was only slightly below ambient. After removing the insulation at the location of the leak, it was found that the corrosion extended beyond the area of the leak and traveled further down the pipe back to the 14 inch line. The insulation was removed to the 14 inch line, where a severe area of corrosion was found on the branch connection, Figures 2 and 3. The 14 inch line was also identified as having an operating temperature of 12 F. The 14 inch line was the supply line to the system relief devices and under normal conditions was completely stagnate, Figure 4. It is only under a pressure relieving event that the actual operating temperature reaches the specified 12 F. The insulation on the entire length of the 14 inch line was removed for inspection. It was found that the first signs of frost rings, indicating that the temperature was below freezing did not occur until within 7 feet of the 24 inch main header. The leak location was approximately 20 feet from the where the piping was normally operating at or below freezing conditions. Based on the nominal wall thicknesses of the piping, the corrosion rates are estimated to be in the range of 0.004in/yr to 0.011in/yr. The corrosion rates are roughly 58

7 the same for the 14 inch line and the 1-1/2 inch line. With the 1-1/2 inch line requiring a smaller wall thickness, it was more susceptible to developing a through wall failure. The second case of CUI deals with a 1-1/2 inch carbon steel makeup line to the ethylene refrigeration system. The line branches off of the suction to the ethylene product pumps and runs to the ethylene refrigeration accumulator. This line was originally identified as operating at -11 F. This line is in operation once per week, for approximately 3 hours, it is stagnate the remainder of the time. The piping orientation is shown in Figure 9. The original specification for this line was to utilize impact carbon steel to a manual globe valve where a specification break to stainless steel occurs. The intent was to minimize the carbon steel piping while keeping the globe valve within sight of the accumulator; however due to the location of the vessel, this required approximately 140 feet of carbon steel piping before the specification break to stainless. The initial visual inspection of this line found several areas of damaged/missing insulation. After removing most of the insulation, the piping was assessed by profile radiography to determine the remaining wall thickness without having to disturb the scale, Figures 7 and 8. There were several areas that were identified as having less than 1/32 inch remaining wall thickness. The worst section of piping was located the furthest from the main header and within approximately 30 feet of the specification break. The line was found to be frozen and free of corrosion within 20 feet of the main header. The third case of CUI deals with a ¾ inch carbon steel bleeder off of a 12 inch acetylene converter feed main header. The bleeder piping and valve were located within 1 foot of the main header. The main header was originally identified as operating at 21 F and normally is at this temperature. The CUI was caught on a visual inspection of the line, were the stem of the bleed valve that protruded through the insulation showed noticeable corrosion and was observed to be sweating. After removal of the insulation, it was found that the main header was frozen and free of corrosion. The ¾ inch piping was frozen next to the main header and showed signs of sweating back to the valve. The piping was assessed by profile radiography, where it was determined that the remaining wall thickness was approximately 1/16 inch localized in areas, Figure 11. It was determined that the piping was acceptable to be in service up to the next scheduled outage. This line was hand cleaned and coated to arrest the corrosion and is scheduled for replacement with stainless steel. 59

8 Prevention Proper prevention of CUI on existing equipment is a very intensive task. The inspection strategy has been modified to include piping that was originally designed for temperatures outside the normal CUI range, less than 0 F, but actually has intermittent flow conditions and/or deadlegs that could be operating within the CUI range. As corrosion is found, it is addressed either through reapplication of coating or replacement. The Reliability department is currently working with Operations to inspect all stagnant, ambient pieces of pipe in the cold section of the unit. Additionally, an outside engineering firm is working with Reliability to review the entire unit so piping that needs to be replaced can be identified for the next turnaround. Since original construction, the plant coating specifications have been revised so that all insulated pipe is coated prior to being put in service. The listed operating temperature now only determines the type and application of the coating system to be used. A proper coating along with a CUI inspection strategy will provide greater protection against developing corrosion cells. Finally, all carbon and impact tested carbon steel piping is being evaluated not only for operating, but ambient conditions to better access and rank potential corrosion issues. References 1. NACE Standard RP , The Control of Corrosion Under Thermal Insulation, and Fireproofing A Systems Approach, NACE International, Houston TX 2. API Publication 570, Piping Inspection Code Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems, American Petroleum Institute, Washington D.C. 3. API Publication RP571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, American Petroleum Institute, Washington D.C. 4. API Publication Guide for Inspection of Refinery Equipment, Chapter II Conditions Causing Deterioration or Failures, American Petroleum Institute, Washington D.C. 5. William D. Callister, Jr., Materials Science and Engineering An Introduction, 4 th edition 1997, John Wiley & Sons, Inc. 60

9 Acknowledgements The authors would like to thank the owners and management of Westlake Chemical Corporation for allowing the publishing of this paper and participation in the Ethylene Producers Subcommittee. 61

10 Figures Leak Location Figure 1 Location of the Ethylene leak on the vent line Figure 2 Corrosion of vent line at 14 inch Branch Connection Figure 3 Corrosion of vent line at 14 inch Branch Connection 62

11 Figure 4 Piping layout of the vent line failure Leak Location Figure 5 Cross section of the vent line failure Figure 6 Steam Utility Station 63

12 Localized Corrosion Area Localized Corrosion Area Figure 7 Profile X-Ray of ethylene makeup line Figure 8 Profile X-Ray of ethylene makeup line Figure 9 Piping layout of makeup line 64

13 Leak Location Corroded Areas Figure 10 Moisture Analyzer Line Figure 11 Bleed Valve Corrosion Figure 12 Drier Bleed Valve Failure Location 65

14 Figure 13 Close up of Failed Drier Bleed Valve Figure 14 Corroded Drier Bleed Valve 66