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Failure analysis of syngas bypass line rupture in an industrial ammonia plant
Engineering Failure Analysis 84 (2018) 59–69
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Failure analysis of syngas bypass line rupture in an industrial ammonia plant
MARK
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P. Darvishia, , F. Zareie-kordshoulib, A. Lashanizadehgana a b
Department of Chemical Engineering, School of Engineering, Yasouj University, Yasouj, Iran Department of Process Engineering, Shiraz Petrochemical Complex, Shiraz, Iran
AR TI CLE I NF O
AB S T R A CT
Keywords: Methanator Bypass line Low alloy seamless steel Benfield solution Corrosion-erosion synergism
In the ammonia plant, the transmission pipeline downstream of CO2 removal unit is suffering from severe corrosion problems worldwide. The safe operation of a transmission piping system depends on various factors that influence each other. The present work has been conducted to investigate the causes of rupturing the 10-inch synthesis gas bypass line downstream of CO2 removal unit in the second ammonia plant of Shiraz petrochemical complex (SPC). The line has been used to control the inlet temperature of methanator catalyst bed. The damage resulted in a large explosion, and the plant was unexpectedly shutdown. A detailed investigation was carried out from a metallurgical and process point of view to reveal the factors that play a major role in the failure of bypass line. The process evaluation was focused on operating variables and the detailed metallurgical investigation was based on microstructural assessment, chemical and reduced thickness analysis, micro hardness measurements, and metallography of transmission pipeline. The findings demonstrated that the failure of bypass line was attributed to the synergistic effect of erosion and corrosion, leading to the wall thinning of the upper part of the line from 9.2 to less than 2 mm and its subsequent rupture.
1. Introduction In the manufacture of ammonia, carbon dioxide is a strong poison for the catalyst of synthesis reactor [1–2]. Accordingly, the removal of CO2 is a crucial step in all ammonia plants using natural gas as the raw material. Despite the disadvantages of CO2, it is an important feedstock for urea production, and therefore, urea plants are integrated with ammonia manufacturing plants [3–4]. A number of separation technologies available for CO2 capture such as absorption, adsorption, gas separation, membrane, and cryogenic separation [5]. Chemical absorption is the most economical separation method which is widely applied for removal of CO2 in ammonia plants [6]. Among the absorbents, amine promoted-hot potassium carbonate provides an efficient and economic way for removing large quantities of CO2 from synthesis gas and thereby offers advantages of large capacity for CO2 absorption and ease of regeneration [7]. Since hot potassium carbonate (Benfield) solutions are corrosive to carbon steel, inhibitors are required to limit the attack. Soluble vanadium compounds are effective inhibitors which operate by forming a film on the metal surface [8–9]. The desired passivation layer is formed by controlling the conditions in two phases called static and dynamic passivation [10]. The vanadate film is formed by circulating the Benfield solution containing the vanadium compound for several days until all surfaces have been coated. Before and during this period, it is essential to exclude the acid gas from the plant to ensure a proper vanadation. Once the vanadation process is completed, the plant may be put on stream [11]. The hot potassium carbonate inhibited with vanadium can be safely
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Corresponding author. E-mail address: [email protected] (P. Darvishi).
https://doi.org/10.1016/j.engfailanal.2017.11.004 Received 12 May 2016; Received in revised form 27 October 2017; Accepted 6 November 2017 Available online 07 November 2017 1350-6307/ © 2017 Elsevier Ltd. All rights reserved.
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operated, but it is very sensitive to corrosion. To maintain the film during operation, the solution must contain sufficient vanadium (At least 0.5 wt% V2O5) [12]. In general, the hot potassium carbonate plants are known to be subjected to a number of operational difficulties, among which corrosion of process equipment is of particular importance. Dissolved CO2 is the main contributor to such corrosion. Pure carbonate solutions without CO2 are not aggressive towards carbon steel [13]. Beinstock et al. found that a 40 wt% potassium carbonate solution saturated with CO2 corroded carbon steel at the rate of 340 mils/y and the corrosion rate was considerably reduced in the presence of H2S [14]. It was also reported that solutions of potassium carbonate produce intergranular stress corrosion on carbon steel [12–14]. Parkins et al. studied the stress corrosion cracking in potassium carbonate systems. Their results from slow strain rate tests on carbon steel in a solution containing 300 g/l K2CO3 with CO2 purging showed that stress corrosion cracking readily occurred in this system. It suggested that the stress corrosion cracking of carbon steel in carbonate solutions occurred by dissolution of metal at the crack tips [15–17]. Hamada et al. studied the corrosion behavior of carbon steel in Benfield solution [18]. Many industrial catastrophic incidences resulting from corrosion failure had been historically recorded [19]. It is also reported that the synergistic effects of erosion and corrosion can be significantly higher than the sum of the effects acting separately [16,17]. A summary of ammonia plants experiencing corrosion failures of carbon steel in hot potassium carbonate solution has been reported by Veawab et al. [5]. CO2 absorbers are more susceptible to pitting, stress corrosion cracking, erosion and intergranular cracking. Corrosion in hot potassium carbonate solution can be reduced through proper equipment design, using corrosion resistant materials such as stainless steel instead of carbon steel, the removal of solid contaminants from solution, and finally the use of corrosion inhibitors [17]. In most of the published works relate to the problems and failures of Benfield corrosion, authors have been dealt and focused on CO2 removal units. However, the study of failures that occur in downstream of the unit is still scarce. The present study is aimed to demonstrate that how the Benfield solution carry-over from the CO2 absorber of an ammonia plant and an isolation block valve leakage can be prone to a severely damaged failure. The problem was carefully analyzed, the suspected causes were found and the solution offered with recommendations. 1.1. Process description Shiraz petrochemical complex has two ammonia plants. The first plant with a nominal capacity of 111 MTPD is on stream since 1962. The second plant has been designed for a capacity of 1200 MTPD since 1985. Due to safety and environmental considerations, the ammonia synthesis section of the first plant has been stopped since 2003, and its produced synthesis gas has been injected into the treated syngas of the second plant. The second plant converts natural gas to hydrogen through the catalytic steam reforming reactions. Besides, CO2 is removed by the Benfield process which utilizes a small percentage of DEA as promotor and ammonium metavanadate as the corrosion inhibitor. As it is shown in Fig. 1, the outlet make gas (containing 18 mol% CO2 on a dry basis) flows from the low temperature CO converter into the inlet heat exchangers of the absorption unit. After cooling and condensation of surplus steam, the gas stream with conditions of 115 °C and 28.5 bar is introduced into the process condensate knock-out (KO) drum and the liquid is separated from the gas. The saturated gas enters the bottom of the absorber countercurrent to the stream of potassium carbonate solution. The absorber contains stainless steel packings distributed in four beds. A single/split flow variation of the activated hot potassium carbonate process has been utilized. The circulating lean solution splits into two portions. The larger stream is fed to the middle of absorber at a temperature near 128 °C. The remaining part is cooled to 70 °C before entering the top of absorber. The potassium carbonate reacts with CO2 and is converted to potassium bicarbonate. Since the reaction rate of CO2 and potassium carbonate is slow, DEA is added to the solution to act as a promoter at the gas/liquid interface. In the lower zone of absorber, the majority of carbon dioxide is absorbed. In the upper zone, the stream of cold solution reduces the CO2 content of the product gas to the desired low level. The operating conditions of the absorber are given in Table 1. At the exit gas from the absorber, the CO2 concentration is reduced to 0.2 mol%. There are two washing stainless steel bubble cap trays at the top of absorber to remove any Benfield solution which otherwise would be carried over with the treated synthesis gas. The absorber and stripper columns are randomly packed with Pall rings made of 304 stainless steel. In the stripper, the CO2 recovered from the rich solution is made available for the urea plant or vented. The stripper consists of three beds, and at the top of each bed a liquid distributor is used to evenly spread the solution through the random packing. To complete the cycle, the regenerated solution from the stripper is pumped back to the absorber column. After leaving the wash trays and demister of the absorber, the treated synthesis gas at a temperature of 70 °C is mixed with the received synthesis gas from the first ammonia plant. The temperature of mixture reaches 65.6 °C and then is heated to 280 °C in the tube side of methanator heat exchanger. In the methanator preheater, it is heated to the reaction temperature and passes through a final purification stage (catalytic methanation), where any remaining carbon oxide is converted back to methane and water by reaction with hydrogen. The final synthesis gas is cooled to ambient temperature and introduced into the KO drum. After separation of condensate, the final syngas is fed to the ammonia synthesis section. 1.2. Failure of bypass line Since the residual carbon oxides in the treated synthesis gas from the absorber act as a catalyst poison in the ammonia converter, their concentration are further reduced to about 5 ppmv by methanation. As a result, in the most ammonia plants, a simple adiabatic reactor is used downstream of the conventional carbon dioxide removal unit. The convenient methanation reaction to remove traces 60
Fig. 1. A schematic diagram of CO2 removal unit in ammonia plant.
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Table 1 The operating conditions of CO2 absorber. CO2 absorber Syngas Component
H2 N2 CO2 CO CH4 Ar H2O T (°C) P (bar) Flow (kmole/h)
Benfield solution Composition (mol%)
Component
Inlet
Outlet
57.51 18.59 17.16 0.38 0.20 0.22 5.95 115 28.5 8458
73.90 23.87 0.20 0.48 0.24 0.29 1.02 68 28 6577.8
K2CO3 KHCO3 Vtot (as KVO3) V+ 5 (as KVO3) V+ 4 (as KVO3) DEA H2O T (°C) P (bar) Flow (kg/h)
Composition (wt%)
Hot Cold
Inlet
Outlet
20.23 8.91 0.75 0.14 0.61 2.80 67.31 126/70 35 1,168,965 389,655
7.13 26.10 0.74 0.13 0.61 2.67 63.36 128 28.5 1,632,762
of carbon oxides from the process gas is achieved by passing the heated gas over the active catalyst where reactions (1) and (2) occur:
CO + 3H2 ↔ CH4 + H2 O
(1)
CO2 + 4H2 ↔ CH4 + 2H2 O
(2)
These reactions are strongly exothermic and even though the inlet concentrations of CO and CO2 are low, there is a substantial temperature rise across the catalyst bed. The temperature rise for typical methanator gas compositions is about 74 and 60 °C for 1 mol % of carbon monoxide and carbon dioxide converted, respectively. Consequently, at higher temperatures, the intrinsic rates of both reactions can become sufficiently fast and a sudden temperature rise occurs. To control the bed temperature, a hand indicator control valve (HICV) is considered to bypass partially the tubes of methanator exchanger. The treated syngas flows into the tube side, if necessary. A 10-inch schedule 40 bypass line made from low alloy steel (1.25% Cr, 0.5% Mo) is used to easily repair the valve during operation. Fig. 2(a) and (b) shows a schematic diagram of methanator heat exchange, bypass valve and the 10-inch bypass line with their isolation block valves. The front end of 10-inch bypass line is located before the entering syngas line into the exchanger and the back end connected to
Fig. 2. Methanator heat exchange, bypass valve and 10-inch bypass line with their isolation block valves (a) schematic diagram (b) site installation.
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Fig. 3. The ruptured area of bypass line.
the exit syngas line from the exchanger. The second ammonia plant has been on stream after the last planned overhaul in 2005. During maintenance and repairs, the syngas bypass line and its isolation block valve were not inspected. Over the years, the bypass valve and its two isolation block valves as well as the isolation block valve of the 10-inch bypass line were in closed position. On March 2010, the 10-inch bypass line at the location downstream of its block valve near the tee connection suddenly ruptured (Fig. 3), which resulted in an unexpected plant shutdown. After the incident, a severe internal corrosion was observed in the upper part of the line where the thickness of the line was decreased in the position 9 to 3 o'clock. In addition, some mineral deposits were found in the area. The isolation block valve of 10-inch bypass line was tested and its leakage was evidenced. The damaged bypass line and the isolation block valves were replaced. After two weeks, the plant was ready to go back into operation. 2. Experimental study The failure analysis includes both metallurgical parameters and process variables. The aim of the metallurgical analysis was mainly focused on chemical analysis, penetration test, thickness and micro hardness measurements, and metallography. The investigated process variables were temperature, pressure, Benfield solution carry-over with leaving treated synthesis gas from the absorber, deposit analysis and condensation of water vapor. 2.1. Specimen selection The first step in the metallographic and laboratory analysis is to select a sample representing the material to be evaluated. This step is critical for the success of any subsequent study. The second step is to correctly prepare a metallographic specimen [19]. Thereby, as shown in Fig. 4, four specimens of the damaged bypass line prepared and marked as BL1 to BL4. The first specimen was removed from the damaged area of the pipe. The second specimen removed near the left side of the damage, the third removed near the right side of the damage and the forth was taken far from the right side of the damage. 2.2. Chemical analysis The materials of construction for transport of syngas must be selected in accordance with ASTM A335 grade P11 (1.25% Cr-0.5% Mo). The seamless ferritic low alloy-steel (SMLS) is used for high pressure and temperature services in the power and petrochemical industry [20,21]. A335 is often called chrome moly pipe, because of the chemical make up from molybdenum and chromium. Molybdenum increases the strength of steel, its elastic limit, resistance to wear, impact qualities and hardenability [22,23]. Besides, it increases the resistance to softening, restrains grain growth and makes chromium steel less susceptible to embrittlement. It is the most effective single additive that increases the high temperature creep strength [19,21,23]. It also enhances the corrosion resistance of
Fig. 4. Locations of the selected specimens for metallography.
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steel and inhibits pitting. Chromium is the essential constituent of stainless steel that improves its tensile yield and hardness at room temperature [20]. It is virtually irreplaceable in resisting oxidation at elevated temperatures [24–26]. The alloy is used to increase resistance against hydrogen attack [25–28]. The chemical analysis was carried out to identify the elemental composition of specimens by employing X-ray fluorescence spectroscopy (XRF) using the thermo scientific Niton XLt analyzer. 2.3. Micro hardness measurements Micro hardness measurements were performed on four selected metallographic specimens. Micro hardness tester Wolpert Instruments 402 MVD was used at a load of 400 g on Vickers scale. 2.4. Nondestructive tests (NDT) To examine the crack-like macrostructural surface defects in the line caused by stress corrosion cracking (SCC) and hydrogen cracking, dye penetrant inspection, ultrasonic, and eddy current techniques were performed on all suspected areas near the damaged surface of bypass line. 2.5. Metallography The physical and mechanical properties of the materials are strongly affected by their microstructures. Quantifying and documenting a material microstructure can provide very useful information for failure analysis applications [28]. The microstructure consists of the phases present, grain size, grain boundary, impurities, imperfections and dislocations. The microstructure analysis of a material determinines whether the material has been processed correctly. Therefore, it is a critical step for determining product reliability and describing why a material fails. Microscopic examination of the fracture surface helps to identify the operating micromechanism of the fracture. Metallographic examination of the failed and new components is one of the most important tools available to the failure analyst. It is usually carried out using devices such as scanning electron microscope (SEM) and transmission electron microscopy (TEM). To examine the existence of micro cracks caused by intergranular corrosion or transgranular corrosion, full metallographic analysis were carried out on the taken specimens of the damaged area. Specimen preparation included cutting, putting in resin, grinding, polishing with diamond paste of 1 and 3 μm diameters, and etching with a mixture of HCl and H2O2. Examination of metallographic specimens was carried out on an Optical Metallographic Microscope, Nickon at magnifications 50–1000 ×. The metallographic results were verified using a JEOL JSM-5000 scanning electron microscope. 2.6. Process evaluation In the case of anomalous wear or failure, the origin of the problem must be identified according to the aspects of the process, mechanical design and fabrication. These aspects include defects, mistakes or wrong procedures during design, construction, lack of maintenance, operational upsets, inept operation and environmental conditions that may cause serious economic losses in the plant. To perform an adequate process analysis of the failure, the operating conditions, actual field data, Benfield carry-over, gas mixing temperature, the precipitate analysis, the isolation block valve of 10-inch bypass line and the design limits of the equipment were explored. 2.6.1. Operational conditions Benfield solution (with and without promotor) is strongly corrosive at temperatures more than 130 °C. It is very important to monitor and control the key process variables such as temperature, flow rate and concentration of constituents. This will lead to corrective actions in order to meet conditions within the design limits and ensure efficient and reliable operation. Besides, it is highly desirable that an accurate log of activities and incidents in the plant and also actual operating data at all stages of plant start-up, operation, and shut down is provided. In particular, it is essential that the instruments used to take these data are in good working order. 2.6.2. Benfield carry-over According to design specification, the entrainment of potassium ions with the leaving gas from the absorber should not exceed 10 ppm. The visual examination of 10-inch bypass line showed the presence of some concentrated solution and deposit (Fig. 5(a) and (b)) near the damaged area. The malfunction of wash trays or demister of the absorber is the cause of Benfield solution carry-over into the leaving synthesis gas from the absorber. The Benfield solution was carried over into the area where the carbonate solution leaked from the isolation block valve. Afterwards, it was exposed to the heated surface that made it concentrated after evaporation takes place. 2.6.3. The isolation block valve Over the years, the control valve of the bypass line, its isolation block valves and the isolation block valve of control valve bypass line were in closed position. The temperature of gas after the first exchanger and near the bypass line is 215 °C. 64
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Fig. 5. The formation of (a) deposit and (b) concentrated solution in the line.
3. Results and discussion 3.1. Chemical analysis The information describing the chemical analysis of four specimens and the limits specified by ASTM A335 grade P11 are presented in Tables 2 and 3, respectively. As it is seen, the composition of components is within the limits specified by ASTM A335 and the material has been selected properly.
3.2. Micro hardness measurements The results of micro hardness measurements are shown in Table 3. The hardness values for two specimens BL1 and BL2 were below the minimum value of 245 HV obtained for the virgin of A335 grade P11. However, the hardness values for specimens BL3 and BL4 were near the minimum.
3.3. Thickness measurement The thickness measurements in Fig. 6 were carried out near the ruptured area to ascertain the extent of thinning in the line. The results showed that the thickness in the upper part of the line decreased from 9.2 to less than 2 mm in the position 9 to 3 o'clock. The minimum thickness required for operation is 3.5 mm.
3.4. Nondestructive tests (NDT) The results obtained from NDT (Fig. 7) show that there is no macro surface crack or other defects in the tested area of failed parts.
3.5. Metallography The metallographic results were verified with SEM analysis that conducted for specimen samples BL1 to BL4 to identify the origin of damage. Fig. 8 demonstrates the characteristic micrograph of sample BL1. No micro surface crack by intergranular or transgranular corrosion, SCC, hydrogen attack or other defects is observed in the area. Similar results were obtained for other samples. Table 2 Chemical analysis (wt%) of four specimens from the ruptured bypass line. Specim.
%Ni
%Cr
%C
Si%
%Al
Mn%
%Mo
%S
%P
%Fe
Hardness Vickers (HV)
BL1 BL2 BL3 BL4
– – – –
1.101 1.194 1.345 1.213
0.034 0.073 0.110 0.085
0.242 0.671 0.710 0.708
– – – –
0.195 0.741 0.705 0.812
0.122 0.419 0.431 0.435
0.002 0.001 0.000 0.001
0.002 0.001 0.005 0.003
Balanced Balanced Balanced Balanced
20 90 205 218
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Table 3 Chemical composition of alloy steel ASTM A335 Grade P11. Element mass fraction
Mechanical properties
C
Si
Mn
Mo
P
S
Cr
Tensile strength (MPa)
Yield strength (MPa)
Hardness (HV)
0.05–0.15
0.5–1.0
0.30–0.80
0.44–0.65
0.025 max.
0.025 max.
1–1.5
415 min
205 min
245
Fig. 6. Thickness measurements near the ruptured area.
Fig. 7. The dye penetration test for bypass line.
3.6. Process evaluation 3.6.1. Operational parameters The average operating temperature and pressure of 10-inch bypass line plus their design values are given in Table 4. The pressure and flow recorder charts were checked in the period 2006–2010 and no deviations from normal range were observed. 3.6.2. Benfield carry-over The concentration of potassium ions measured monthly in the period 2006 to 2010 are presented in Table 5 as annual average values. Potassium ion concentrations greater than 22 ppm were detected in the samples of product gas leaving the top of the absorber. It is likely that in operation upsets of the CO2 removal unit, more Benfiled solution has been carried over by the product gas stream. Besides, chemical analysis in the form of energy-dispersive spectrometry (EDS) was performed on three taken samples of the deposits and concentrated solutions to determine the elemental composition. The results given in Table 6 reveal the presence of typical elements such as K, C, O and V in the Benfield solution. Elements such as Fe, Cr and Ni were also detected, probably in the form of oxides from the metal surface or corrosion products. The mainly identified elements were C, O, Fe and K which emphasize the presence of Benfield solution contaminants in the damaged region. 3.6.3. Gas mixing temperature The received synthesis gas from the first ammonia plant at the conditions of 35 °C and 38 bar is injected into the treated synthesis 66
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250 µm Fig. 8. Microstructure of specimen BL1.
Table 4 The design and operating temperatures and pressures of 10-inch bypass line in the period 2006–2010.
Design Operating
Temperature (°C)
Pressure (bar)
Fluid
320 138 ± 2
34.3 28 ± 0.1
Syngas Syngas
Table 5 The average concentration of potassium ions in the carrier synthesis gas from the absorber. Samples
2006
2007
2008
2009
2010
K+ (ppm)
22
23
23
25
28
Table 6 Chemical analysis (wt%) of three samples taken from the precipitate and concentrated solution. Deposit Component
%K
%O
%Fe
%Cr
%C
%Al
Mn%
Mn%
25.100 24.977 27.445 6.078 15–30
9.001 8.998 8.564 1.005 35–45
42.100 41.800 43.785 35.120 0
0.002 0.001 0.000 0 0
2.245 2.245 2076 4.010 2.5–3
0.000 0.000 0.000 0 0
0.001 0.001 0.000 0 0
0.001 0.001 0.000 0 0
Sample 1 2 3 Concentrated solution Potassium carbonate solution
gas of the second plan at 70 °C. After complete mixing of two streams, the equilibrium temperature of mixed gas decreases to 65.6 °C. The fall in temperature of mixed gas condenses a portion of water vapor in the synthesis gas leaves the absorber. Therefore, the mixed gas contains condensate that can be appeared as water mist in the carrier synthesis gas. In addition, missing, improper, damaged, walked on and broken insulation can lead to insulation malfunctions. Insulation malfunctions caused further decrease in the synthesis gas temperature and led to more condensate formation. The condensation of water vapor and the abnormal carry-over of Benfield solution resulted in the contamination of condensate with potassium ions. 3.6.4. The isolation block valve After failure of 10-inch bypass line, its isolation block valve was checked and the valve leakage was ascertained. The leakage of isolation block valve allows a small amount of gas to pass and raises its velocity in the line. The contaminated condensate in the carrier synthesis gas was exposed to the hot surface near the outlet line of methanator heat exchanger and evaporation occurs. The 67
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evaporation resulted in the collapse of bubbles that leads to pitting and concentrating of the contaminated solution. The abnormal high velocity of fluid also erodes the inner surface of the line. The synergistic effects of erosion and corrosion caused the loss of metal in the area that leads to wall thinning in the upper part and its subsequent rupture. The remaining wall thickness reached less than the minimum thickness required for operation and was not able to withstand the subjected internal pressure of the flowing synthesis gas through the line. Low alloy steel at the conditions of 265 °C and such low partial pressure of hydrogen will not fail. The low hardness values obtained in Table 4 might be resulted from the synergistic effects of erosion and corrosion in the areas examined. 4. Conclusion Lack of attention to inspect the syngas bypass line downstream of the CO2 removal unit in the second ammonia plant of SPC resulted in a large explosion. A detailed investigation was carried out to reveal the factors that play a major role in the failure of bypass line. The material of construction for the line was the low alloy steel ASTM A335 Grade P11 and the chemical analysis of the taken specimens from the line were within the limits specified by ASTM A335. The detailed analysis of failure showed that the suspected process causes were leakage from the isolation block valve of bypass line, decreasing of the synthesis gas temperature due to mixing with a lower temperature stream, further temperature reduction due to insulation loss, and carry-over of Benfield solution over the design value. The results of metallography and SEM showed no micro-cracks and intergranular corrosion in the samples. The analysis of the deposits formed in the 10-inch bypass line proved the presence of potassium carbonate/bicarbonate and corrosion products in the taken samples from the damaged area. The evaporation of contaminated condensate collapse the bubbles that leads to pitting and concentrating of the solution. Besides, the leakage of isolation block valve abnormally increases the velocity of fluid which erodes the inner surface of the line. The synergistic effects of erosion and corrosion caused the wall thinning in the upper part of the line and its subsequent rupture. These failures can lead to serious financial and employee losses. To minimize the risk and prevent the reoccur of such failures, the following recommendations are offered:
• Improving the insulation of synthesis gas transmission pipeline from absorber to the entrance of methanator heat exchanger. • Locating a heat exchanger for heating the received synthesis gas from the first ammonia plant to prevent any condensate formation during mixing. • Including a knock-out drum before the methanator heat exchanger to remove any condensate and contaminated chemicals from the mixed synthesis gas. • During the scheduled overhauls of plant, the main isolation block valves of the line must be hydrostatically tested for leakage detection. • Preparation of a scheduled program to inspect the demister and wash trays of the absorber. Acknowledgment The authors gratefully acknowledge the assistance of Mr. Etminan (deputy of technical services of SPC) and Mr. Liravizadeh (head of process engineering department) who made valuable suggestions for the preparation of the manuscript. References [1] B. Scott, J.R. Daniels, I. Chao, Corrosion History of a Hot Pot CO2 Absorber, Ammonia Plants and Related Facilities Symposia Technical Manual, (1987), pp. 127–133. [2] S.K. Furukawa, R.K. Bartoo, Improved Benfield process for ammonia plants, http://www.uop.com, (2003). [3] N.N. Patel, M.M. Pandya, G.H. Thanki, M.H. Mehta, Evaluation of carbon steel corrosion in the CO2 removal system of an ammonia plant, Corros. Prev. Control 41 (1996) 38–41. [4] J.R. Widring, D.H. Timbres, Fitness-for-service of CO2 absorbers in ammonia plants: ammonia technical manual, American Institute of Chemical Engineers (AIChE), Ammonia Safety Symposium, 2009, pp. 211–222. [5] A. Veawab, CO2 Capture by Absorption With Potassium Carbonate Fourth Quarterly Report, Department of Chemical Engineering, the University of Texas at Austin, Austin, TX, USA, January 26, (2005). [6] R. Stevens, G. Kongsvoll, Carbamate production in ammonia plant: ammonia technical manual, American Institute of Chemical Engineers (AIChE) Ammonia Safety Symposium, 2009, pp. 283–290. [7] R.W. Revie, S.A. Shirazi, B.S. Mclaury, J.R. Shadley, Oil and Gas Pipelines: Integrity and Safety Handbook, Erosion–Corrosion in Oil and Gas Pipelines, (2015). [8] R.N. Parkins, E. Belhimer, W.K. Blanchard, Stress corrosion cracking characteristics of a range of pipeline steels in carbonate–bicarbonate solution, Corrosion 49 (1993) 951–966. [9] S.J. Harjac, A. Atrens, C.J. Moss, Six sigma review of root causes of corrosion incidents in hot potassium carbonate acid gas removal plant, Eng. Fail. Anal. 15 (2008) 480–496. [10] H.M. Elbassyouni, Caustic Stress Corrosion Cracking in Contaminated Steam System in CO2 Removal Unit in AlexFert Egypt, Proc. 4th. Uhde Fertilizer Symposium, Dortmund, Germany, (May 2010). [11] J.M. Sutcliffe, R.R. Fessler, W.K. Boyd, R.N. Parkins, Stress corrosion cracking of carbon steel in carbonate solutions, Corrosion 28 (1972) 313–320. [12] D. Renowicz, M. Ciesla, Crack initiation in steel parts working in boilers and steam pipelines, J. Achiev. Mater. Manuf. Eng. 21 (2007) 49–52. [13] J. Dobrzaski, M. Sroka, A. Zieliski, Methodology of classification of internal damage the steels during creep service, J. Achiev. Mater. Manuf. Eng. 18 (2006) 263–266. [14] J. Cross, Electrostatic Hazards From Pumping Insulating Liquids in Glass Pipes, Proc. 3rd. Int. Conf. on static electricity, Grenoble, (1972). [15] A. Zieliński, J. Dobrzański, H. Krztoń, Structural changes in low alloy cast steel Cr-Mo-V after long time creep service, J. Achiev. Mater. Manuf. Eng. 25 (1) (2007) 33–36. [16] J. Daniel, J. Benac, P. McAndrew, Reducing the risk of high temperature hydrogen attack (HTHA) failures, J. Fail. Anal. Prev. 12 (2012) 624–627. [17] D.J. Benac, Elevated temperature life assessment for turbine components, piping and tubing, Failure Analysis and Prevention, ASMI Handbook, 11 2002, pp.
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289–311. [18] W.P. Banks, Corrosion in hot potassium carbonate system, Mater. Prot. 6 (1967) 37–41. [19] J. Korkhaus, D.R. Feser, Failure Mechanisms and Material Degradations at High Temperatures in Ammonia Plants, Ammonia Technical Manual, (2007). [20] S.J. Harjac, A. Atrens, C.J. Moss, V.J. Linton, Influence of solution chemistry and surface condition on the critical inhibitor concentration for solutions typical of hot potassium carbonate CO2 removal plant, Mater. Sci. 42 (2007) 7762–7771. [21] R.B. Nielsen, K.R. Lewis, J.G. McCullough, D.A. Hansen, Corrosion in Refinery Amine Systems, Proc. Int. Conf. NACE Corrosion, New Orleans, LO, USA, (May 1995), p. 571. [22] A. Neville, T. Hodgkiess, J.T. Dallas, A study of the erosion-corrosion behavior of engineering steels for marine pumping applications, Wear 186–187 (1995) 497–507. [23] M.F. Hamada, T.M. Zewail, H.A. Farag, Study of corrosion behavior of A106 carbon steel absorber for CO2 removal in amine promoted hot potassium carbonate solution (Benfield solution), Corros. Eng. Sci. Technol. 49 (3) (2014) 209–218. [24] A.G. Wikjord, T.E. Rummery, F.E. Doern, D.G. Owen, Corrosion and deposition during the exposure of carbon steel to H2O-H2S solutions at elevated pressures, Corros. Sci. 20 (1980) 651–671. [25] L.V. Frolova, M.N. Fokin, V.E. Zorina, Corrosion-electrochemical behavior of carbon steels in carbonate-bicarbonate solutions, Prot. Met. 33 (1997) 249–252. [26] F.H. Meyer, O.L. Riggs, R.L. McGlasson, J.D. Sudbury, Corrosion products of mild steel in hydrogen sulfide environment, Corrosion 14 (1958) 69–75. [27] H. Ma, X. Cheng, G. Li, S. Chen, Z. Quan, S. Zhao, L. Niu, The influence of hydrogen sulfide on corrosion of iron under different conditions, Corros. Sci. 42 (2000) 1669–1683. [28] E. Mahdi, A. Rauf, S. Ghani, A. El-Noamany, A. Pakari, Erosion-corrosion behavior and failure analysis of offshore steel tubular joint, Int. J. Electrochem. Sci. 8 (2013) 7187–7210.
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Failure analysis of syngas bypass line rupture in an industrial ammonia plant
MARK
⁎
P. Darvishia, , F. Zareie-kordshoulib, A. Lashanizadehgana a b
Department of Chemical Engineering, School of Engineering, Yasouj University, Yasouj, Iran Department of Process Engineering, Shiraz Petrochemical Complex, Shiraz, Iran
AR TI CLE I NF O
AB S T R A CT
Keywords: Methanator Bypass line Low alloy seamless steel Benfield solution Corrosion-erosion synergism
In the ammonia plant, the transmission pipeline downstream of CO2 removal unit is suffering from severe corrosion problems worldwide. The safe operation of a transmission piping system depends on various factors that influence each other. The present work has been conducted to investigate the causes of rupturing the 10-inch synthesis gas bypass line downstream of CO2 removal unit in the second ammonia plant of Shiraz petrochemical complex (SPC). The line has been used to control the inlet temperature of methanator catalyst bed. The damage resulted in a large explosion, and the plant was unexpectedly shutdown. A detailed investigation was carried out from a metallurgical and process point of view to reveal the factors that play a major role in the failure of bypass line. The process evaluation was focused on operating variables and the detailed metallurgical investigation was based on microstructural assessment, chemical and reduced thickness analysis, micro hardness measurements, and metallography of transmission pipeline. The findings demonstrated that the failure of bypass line was attributed to the synergistic effect of erosion and corrosion, leading to the wall thinning of the upper part of the line from 9.2 to less than 2 mm and its subsequent rupture.
1. Introduction In the manufacture of ammonia, carbon dioxide is a strong poison for the catalyst of synthesis reactor [1–2]. Accordingly, the removal of CO2 is a crucial step in all ammonia plants using natural gas as the raw material. Despite the disadvantages of CO2, it is an important feedstock for urea production, and therefore, urea plants are integrated with ammonia manufacturing plants [3–4]. A number of separation technologies available for CO2 capture such as absorption, adsorption, gas separation, membrane, and cryogenic separation [5]. Chemical absorption is the most economical separation method which is widely applied for removal of CO2 in ammonia plants [6]. Among the absorbents, amine promoted-hot potassium carbonate provides an efficient and economic way for removing large quantities of CO2 from synthesis gas and thereby offers advantages of large capacity for CO2 absorption and ease of regeneration [7]. Since hot potassium carbonate (Benfield) solutions are corrosive to carbon steel, inhibitors are required to limit the attack. Soluble vanadium compounds are effective inhibitors which operate by forming a film on the metal surface [8–9]. The desired passivation layer is formed by controlling the conditions in two phases called static and dynamic passivation [10]. The vanadate film is formed by circulating the Benfield solution containing the vanadium compound for several days until all surfaces have been coated. Before and during this period, it is essential to exclude the acid gas from the plant to ensure a proper vanadation. Once the vanadation process is completed, the plant may be put on stream [11]. The hot potassium carbonate inhibited with vanadium can be safely
⁎
Corresponding author. E-mail address: [email protected] (P. Darvishi).
https://doi.org/10.1016/j.engfailanal.2017.11.004 Received 12 May 2016; Received in revised form 27 October 2017; Accepted 6 November 2017 Available online 07 November 2017 1350-6307/ © 2017 Elsevier Ltd. All rights reserved.
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operated, but it is very sensitive to corrosion. To maintain the film during operation, the solution must contain sufficient vanadium (At least 0.5 wt% V2O5) [12]. In general, the hot potassium carbonate plants are known to be subjected to a number of operational difficulties, among which corrosion of process equipment is of particular importance. Dissolved CO2 is the main contributor to such corrosion. Pure carbonate solutions without CO2 are not aggressive towards carbon steel [13]. Beinstock et al. found that a 40 wt% potassium carbonate solution saturated with CO2 corroded carbon steel at the rate of 340 mils/y and the corrosion rate was considerably reduced in the presence of H2S [14]. It was also reported that solutions of potassium carbonate produce intergranular stress corrosion on carbon steel [12–14]. Parkins et al. studied the stress corrosion cracking in potassium carbonate systems. Their results from slow strain rate tests on carbon steel in a solution containing 300 g/l K2CO3 with CO2 purging showed that stress corrosion cracking readily occurred in this system. It suggested that the stress corrosion cracking of carbon steel in carbonate solutions occurred by dissolution of metal at the crack tips [15–17]. Hamada et al. studied the corrosion behavior of carbon steel in Benfield solution [18]. Many industrial catastrophic incidences resulting from corrosion failure had been historically recorded [19]. It is also reported that the synergistic effects of erosion and corrosion can be significantly higher than the sum of the effects acting separately [16,17]. A summary of ammonia plants experiencing corrosion failures of carbon steel in hot potassium carbonate solution has been reported by Veawab et al. [5]. CO2 absorbers are more susceptible to pitting, stress corrosion cracking, erosion and intergranular cracking. Corrosion in hot potassium carbonate solution can be reduced through proper equipment design, using corrosion resistant materials such as stainless steel instead of carbon steel, the removal of solid contaminants from solution, and finally the use of corrosion inhibitors [17]. In most of the published works relate to the problems and failures of Benfield corrosion, authors have been dealt and focused on CO2 removal units. However, the study of failures that occur in downstream of the unit is still scarce. The present study is aimed to demonstrate that how the Benfield solution carry-over from the CO2 absorber of an ammonia plant and an isolation block valve leakage can be prone to a severely damaged failure. The problem was carefully analyzed, the suspected causes were found and the solution offered with recommendations. 1.1. Process description Shiraz petrochemical complex has two ammonia plants. The first plant with a nominal capacity of 111 MTPD is on stream since 1962. The second plant has been designed for a capacity of 1200 MTPD since 1985. Due to safety and environmental considerations, the ammonia synthesis section of the first plant has been stopped since 2003, and its produced synthesis gas has been injected into the treated syngas of the second plant. The second plant converts natural gas to hydrogen through the catalytic steam reforming reactions. Besides, CO2 is removed by the Benfield process which utilizes a small percentage of DEA as promotor and ammonium metavanadate as the corrosion inhibitor. As it is shown in Fig. 1, the outlet make gas (containing 18 mol% CO2 on a dry basis) flows from the low temperature CO converter into the inlet heat exchangers of the absorption unit. After cooling and condensation of surplus steam, the gas stream with conditions of 115 °C and 28.5 bar is introduced into the process condensate knock-out (KO) drum and the liquid is separated from the gas. The saturated gas enters the bottom of the absorber countercurrent to the stream of potassium carbonate solution. The absorber contains stainless steel packings distributed in four beds. A single/split flow variation of the activated hot potassium carbonate process has been utilized. The circulating lean solution splits into two portions. The larger stream is fed to the middle of absorber at a temperature near 128 °C. The remaining part is cooled to 70 °C before entering the top of absorber. The potassium carbonate reacts with CO2 and is converted to potassium bicarbonate. Since the reaction rate of CO2 and potassium carbonate is slow, DEA is added to the solution to act as a promoter at the gas/liquid interface. In the lower zone of absorber, the majority of carbon dioxide is absorbed. In the upper zone, the stream of cold solution reduces the CO2 content of the product gas to the desired low level. The operating conditions of the absorber are given in Table 1. At the exit gas from the absorber, the CO2 concentration is reduced to 0.2 mol%. There are two washing stainless steel bubble cap trays at the top of absorber to remove any Benfield solution which otherwise would be carried over with the treated synthesis gas. The absorber and stripper columns are randomly packed with Pall rings made of 304 stainless steel. In the stripper, the CO2 recovered from the rich solution is made available for the urea plant or vented. The stripper consists of three beds, and at the top of each bed a liquid distributor is used to evenly spread the solution through the random packing. To complete the cycle, the regenerated solution from the stripper is pumped back to the absorber column. After leaving the wash trays and demister of the absorber, the treated synthesis gas at a temperature of 70 °C is mixed with the received synthesis gas from the first ammonia plant. The temperature of mixture reaches 65.6 °C and then is heated to 280 °C in the tube side of methanator heat exchanger. In the methanator preheater, it is heated to the reaction temperature and passes through a final purification stage (catalytic methanation), where any remaining carbon oxide is converted back to methane and water by reaction with hydrogen. The final synthesis gas is cooled to ambient temperature and introduced into the KO drum. After separation of condensate, the final syngas is fed to the ammonia synthesis section. 1.2. Failure of bypass line Since the residual carbon oxides in the treated synthesis gas from the absorber act as a catalyst poison in the ammonia converter, their concentration are further reduced to about 5 ppmv by methanation. As a result, in the most ammonia plants, a simple adiabatic reactor is used downstream of the conventional carbon dioxide removal unit. The convenient methanation reaction to remove traces 60
Fig. 1. A schematic diagram of CO2 removal unit in ammonia plant.
P. Darvishi et al.
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Table 1 The operating conditions of CO2 absorber. CO2 absorber Syngas Component
H2 N2 CO2 CO CH4 Ar H2O T (°C) P (bar) Flow (kmole/h)
Benfield solution Composition (mol%)
Component
Inlet
Outlet
57.51 18.59 17.16 0.38 0.20 0.22 5.95 115 28.5 8458
73.90 23.87 0.20 0.48 0.24 0.29 1.02 68 28 6577.8
K2CO3 KHCO3 Vtot (as KVO3) V+ 5 (as KVO3) V+ 4 (as KVO3) DEA H2O T (°C) P (bar) Flow (kg/h)
Composition (wt%)
Hot Cold
Inlet
Outlet
20.23 8.91 0.75 0.14 0.61 2.80 67.31 126/70 35 1,168,965 389,655
7.13 26.10 0.74 0.13 0.61 2.67 63.36 128 28.5 1,632,762
of carbon oxides from the process gas is achieved by passing the heated gas over the active catalyst where reactions (1) and (2) occur:
CO + 3H2 ↔ CH4 + H2 O
(1)
CO2 + 4H2 ↔ CH4 + 2H2 O
(2)
These reactions are strongly exothermic and even though the inlet concentrations of CO and CO2 are low, there is a substantial temperature rise across the catalyst bed. The temperature rise for typical methanator gas compositions is about 74 and 60 °C for 1 mol % of carbon monoxide and carbon dioxide converted, respectively. Consequently, at higher temperatures, the intrinsic rates of both reactions can become sufficiently fast and a sudden temperature rise occurs. To control the bed temperature, a hand indicator control valve (HICV) is considered to bypass partially the tubes of methanator exchanger. The treated syngas flows into the tube side, if necessary. A 10-inch schedule 40 bypass line made from low alloy steel (1.25% Cr, 0.5% Mo) is used to easily repair the valve during operation. Fig. 2(a) and (b) shows a schematic diagram of methanator heat exchange, bypass valve and the 10-inch bypass line with their isolation block valves. The front end of 10-inch bypass line is located before the entering syngas line into the exchanger and the back end connected to
Fig. 2. Methanator heat exchange, bypass valve and 10-inch bypass line with their isolation block valves (a) schematic diagram (b) site installation.
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Fig. 3. The ruptured area of bypass line.
the exit syngas line from the exchanger. The second ammonia plant has been on stream after the last planned overhaul in 2005. During maintenance and repairs, the syngas bypass line and its isolation block valve were not inspected. Over the years, the bypass valve and its two isolation block valves as well as the isolation block valve of the 10-inch bypass line were in closed position. On March 2010, the 10-inch bypass line at the location downstream of its block valve near the tee connection suddenly ruptured (Fig. 3), which resulted in an unexpected plant shutdown. After the incident, a severe internal corrosion was observed in the upper part of the line where the thickness of the line was decreased in the position 9 to 3 o'clock. In addition, some mineral deposits were found in the area. The isolation block valve of 10-inch bypass line was tested and its leakage was evidenced. The damaged bypass line and the isolation block valves were replaced. After two weeks, the plant was ready to go back into operation. 2. Experimental study The failure analysis includes both metallurgical parameters and process variables. The aim of the metallurgical analysis was mainly focused on chemical analysis, penetration test, thickness and micro hardness measurements, and metallography. The investigated process variables were temperature, pressure, Benfield solution carry-over with leaving treated synthesis gas from the absorber, deposit analysis and condensation of water vapor. 2.1. Specimen selection The first step in the metallographic and laboratory analysis is to select a sample representing the material to be evaluated. This step is critical for the success of any subsequent study. The second step is to correctly prepare a metallographic specimen [19]. Thereby, as shown in Fig. 4, four specimens of the damaged bypass line prepared and marked as BL1 to BL4. The first specimen was removed from the damaged area of the pipe. The second specimen removed near the left side of the damage, the third removed near the right side of the damage and the forth was taken far from the right side of the damage. 2.2. Chemical analysis The materials of construction for transport of syngas must be selected in accordance with ASTM A335 grade P11 (1.25% Cr-0.5% Mo). The seamless ferritic low alloy-steel (SMLS) is used for high pressure and temperature services in the power and petrochemical industry [20,21]. A335 is often called chrome moly pipe, because of the chemical make up from molybdenum and chromium. Molybdenum increases the strength of steel, its elastic limit, resistance to wear, impact qualities and hardenability [22,23]. Besides, it increases the resistance to softening, restrains grain growth and makes chromium steel less susceptible to embrittlement. It is the most effective single additive that increases the high temperature creep strength [19,21,23]. It also enhances the corrosion resistance of
Fig. 4. Locations of the selected specimens for metallography.
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steel and inhibits pitting. Chromium is the essential constituent of stainless steel that improves its tensile yield and hardness at room temperature [20]. It is virtually irreplaceable in resisting oxidation at elevated temperatures [24–26]. The alloy is used to increase resistance against hydrogen attack [25–28]. The chemical analysis was carried out to identify the elemental composition of specimens by employing X-ray fluorescence spectroscopy (XRF) using the thermo scientific Niton XLt analyzer. 2.3. Micro hardness measurements Micro hardness measurements were performed on four selected metallographic specimens. Micro hardness tester Wolpert Instruments 402 MVD was used at a load of 400 g on Vickers scale. 2.4. Nondestructive tests (NDT) To examine the crack-like macrostructural surface defects in the line caused by stress corrosion cracking (SCC) and hydrogen cracking, dye penetrant inspection, ultrasonic, and eddy current techniques were performed on all suspected areas near the damaged surface of bypass line. 2.5. Metallography The physical and mechanical properties of the materials are strongly affected by their microstructures. Quantifying and documenting a material microstructure can provide very useful information for failure analysis applications [28]. The microstructure consists of the phases present, grain size, grain boundary, impurities, imperfections and dislocations. The microstructure analysis of a material determinines whether the material has been processed correctly. Therefore, it is a critical step for determining product reliability and describing why a material fails. Microscopic examination of the fracture surface helps to identify the operating micromechanism of the fracture. Metallographic examination of the failed and new components is one of the most important tools available to the failure analyst. It is usually carried out using devices such as scanning electron microscope (SEM) and transmission electron microscopy (TEM). To examine the existence of micro cracks caused by intergranular corrosion or transgranular corrosion, full metallographic analysis were carried out on the taken specimens of the damaged area. Specimen preparation included cutting, putting in resin, grinding, polishing with diamond paste of 1 and 3 μm diameters, and etching with a mixture of HCl and H2O2. Examination of metallographic specimens was carried out on an Optical Metallographic Microscope, Nickon at magnifications 50–1000 ×. The metallographic results were verified using a JEOL JSM-5000 scanning electron microscope. 2.6. Process evaluation In the case of anomalous wear or failure, the origin of the problem must be identified according to the aspects of the process, mechanical design and fabrication. These aspects include defects, mistakes or wrong procedures during design, construction, lack of maintenance, operational upsets, inept operation and environmental conditions that may cause serious economic losses in the plant. To perform an adequate process analysis of the failure, the operating conditions, actual field data, Benfield carry-over, gas mixing temperature, the precipitate analysis, the isolation block valve of 10-inch bypass line and the design limits of the equipment were explored. 2.6.1. Operational conditions Benfield solution (with and without promotor) is strongly corrosive at temperatures more than 130 °C. It is very important to monitor and control the key process variables such as temperature, flow rate and concentration of constituents. This will lead to corrective actions in order to meet conditions within the design limits and ensure efficient and reliable operation. Besides, it is highly desirable that an accurate log of activities and incidents in the plant and also actual operating data at all stages of plant start-up, operation, and shut down is provided. In particular, it is essential that the instruments used to take these data are in good working order. 2.6.2. Benfield carry-over According to design specification, the entrainment of potassium ions with the leaving gas from the absorber should not exceed 10 ppm. The visual examination of 10-inch bypass line showed the presence of some concentrated solution and deposit (Fig. 5(a) and (b)) near the damaged area. The malfunction of wash trays or demister of the absorber is the cause of Benfield solution carry-over into the leaving synthesis gas from the absorber. The Benfield solution was carried over into the area where the carbonate solution leaked from the isolation block valve. Afterwards, it was exposed to the heated surface that made it concentrated after evaporation takes place. 2.6.3. The isolation block valve Over the years, the control valve of the bypass line, its isolation block valves and the isolation block valve of control valve bypass line were in closed position. The temperature of gas after the first exchanger and near the bypass line is 215 °C. 64
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Fig. 5. The formation of (a) deposit and (b) concentrated solution in the line.
3. Results and discussion 3.1. Chemical analysis The information describing the chemical analysis of four specimens and the limits specified by ASTM A335 grade P11 are presented in Tables 2 and 3, respectively. As it is seen, the composition of components is within the limits specified by ASTM A335 and the material has been selected properly.
3.2. Micro hardness measurements The results of micro hardness measurements are shown in Table 3. The hardness values for two specimens BL1 and BL2 were below the minimum value of 245 HV obtained for the virgin of A335 grade P11. However, the hardness values for specimens BL3 and BL4 were near the minimum.
3.3. Thickness measurement The thickness measurements in Fig. 6 were carried out near the ruptured area to ascertain the extent of thinning in the line. The results showed that the thickness in the upper part of the line decreased from 9.2 to less than 2 mm in the position 9 to 3 o'clock. The minimum thickness required for operation is 3.5 mm.
3.4. Nondestructive tests (NDT) The results obtained from NDT (Fig. 7) show that there is no macro surface crack or other defects in the tested area of failed parts.
3.5. Metallography The metallographic results were verified with SEM analysis that conducted for specimen samples BL1 to BL4 to identify the origin of damage. Fig. 8 demonstrates the characteristic micrograph of sample BL1. No micro surface crack by intergranular or transgranular corrosion, SCC, hydrogen attack or other defects is observed in the area. Similar results were obtained for other samples. Table 2 Chemical analysis (wt%) of four specimens from the ruptured bypass line. Specim.
%Ni
%Cr
%C
Si%
%Al
Mn%
%Mo
%S
%P
%Fe
Hardness Vickers (HV)
BL1 BL2 BL3 BL4
– – – –
1.101 1.194 1.345 1.213
0.034 0.073 0.110 0.085
0.242 0.671 0.710 0.708
– – – –
0.195 0.741 0.705 0.812
0.122 0.419 0.431 0.435
0.002 0.001 0.000 0.001
0.002 0.001 0.005 0.003
Balanced Balanced Balanced Balanced
20 90 205 218
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Table 3 Chemical composition of alloy steel ASTM A335 Grade P11. Element mass fraction
Mechanical properties
C
Si
Mn
Mo
P
S
Cr
Tensile strength (MPa)
Yield strength (MPa)
Hardness (HV)
0.05–0.15
0.5–1.0
0.30–0.80
0.44–0.65
0.025 max.
0.025 max.
1–1.5
415 min
205 min
245
Fig. 6. Thickness measurements near the ruptured area.
Fig. 7. The dye penetration test for bypass line.
3.6. Process evaluation 3.6.1. Operational parameters The average operating temperature and pressure of 10-inch bypass line plus their design values are given in Table 4. The pressure and flow recorder charts were checked in the period 2006–2010 and no deviations from normal range were observed. 3.6.2. Benfield carry-over The concentration of potassium ions measured monthly in the period 2006 to 2010 are presented in Table 5 as annual average values. Potassium ion concentrations greater than 22 ppm were detected in the samples of product gas leaving the top of the absorber. It is likely that in operation upsets of the CO2 removal unit, more Benfiled solution has been carried over by the product gas stream. Besides, chemical analysis in the form of energy-dispersive spectrometry (EDS) was performed on three taken samples of the deposits and concentrated solutions to determine the elemental composition. The results given in Table 6 reveal the presence of typical elements such as K, C, O and V in the Benfield solution. Elements such as Fe, Cr and Ni were also detected, probably in the form of oxides from the metal surface or corrosion products. The mainly identified elements were C, O, Fe and K which emphasize the presence of Benfield solution contaminants in the damaged region. 3.6.3. Gas mixing temperature The received synthesis gas from the first ammonia plant at the conditions of 35 °C and 38 bar is injected into the treated synthesis 66
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250 µm Fig. 8. Microstructure of specimen BL1.
Table 4 The design and operating temperatures and pressures of 10-inch bypass line in the period 2006–2010.
Design Operating
Temperature (°C)
Pressure (bar)
Fluid
320 138 ± 2
34.3 28 ± 0.1
Syngas Syngas
Table 5 The average concentration of potassium ions in the carrier synthesis gas from the absorber. Samples
2006
2007
2008
2009
2010
K+ (ppm)
22
23
23
25
28
Table 6 Chemical analysis (wt%) of three samples taken from the precipitate and concentrated solution. Deposit Component
%K
%O
%Fe
%Cr
%C
%Al
Mn%
Mn%
25.100 24.977 27.445 6.078 15–30
9.001 8.998 8.564 1.005 35–45
42.100 41.800 43.785 35.120 0
0.002 0.001 0.000 0 0
2.245 2.245 2076 4.010 2.5–3
0.000 0.000 0.000 0 0
0.001 0.001 0.000 0 0
0.001 0.001 0.000 0 0
Sample 1 2 3 Concentrated solution Potassium carbonate solution
gas of the second plan at 70 °C. After complete mixing of two streams, the equilibrium temperature of mixed gas decreases to 65.6 °C. The fall in temperature of mixed gas condenses a portion of water vapor in the synthesis gas leaves the absorber. Therefore, the mixed gas contains condensate that can be appeared as water mist in the carrier synthesis gas. In addition, missing, improper, damaged, walked on and broken insulation can lead to insulation malfunctions. Insulation malfunctions caused further decrease in the synthesis gas temperature and led to more condensate formation. The condensation of water vapor and the abnormal carry-over of Benfield solution resulted in the contamination of condensate with potassium ions. 3.6.4. The isolation block valve After failure of 10-inch bypass line, its isolation block valve was checked and the valve leakage was ascertained. The leakage of isolation block valve allows a small amount of gas to pass and raises its velocity in the line. The contaminated condensate in the carrier synthesis gas was exposed to the hot surface near the outlet line of methanator heat exchanger and evaporation occurs. The 67
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evaporation resulted in the collapse of bubbles that leads to pitting and concentrating of the contaminated solution. The abnormal high velocity of fluid also erodes the inner surface of the line. The synergistic effects of erosion and corrosion caused the loss of metal in the area that leads to wall thinning in the upper part and its subsequent rupture. The remaining wall thickness reached less than the minimum thickness required for operation and was not able to withstand the subjected internal pressure of the flowing synthesis gas through the line. Low alloy steel at the conditions of 265 °C and such low partial pressure of hydrogen will not fail. The low hardness values obtained in Table 4 might be resulted from the synergistic effects of erosion and corrosion in the areas examined. 4. Conclusion Lack of attention to inspect the syngas bypass line downstream of the CO2 removal unit in the second ammonia plant of SPC resulted in a large explosion. A detailed investigation was carried out to reveal the factors that play a major role in the failure of bypass line. The material of construction for the line was the low alloy steel ASTM A335 Grade P11 and the chemical analysis of the taken specimens from the line were within the limits specified by ASTM A335. The detailed analysis of failure showed that the suspected process causes were leakage from the isolation block valve of bypass line, decreasing of the synthesis gas temperature due to mixing with a lower temperature stream, further temperature reduction due to insulation loss, and carry-over of Benfield solution over the design value. The results of metallography and SEM showed no micro-cracks and intergranular corrosion in the samples. The analysis of the deposits formed in the 10-inch bypass line proved the presence of potassium carbonate/bicarbonate and corrosion products in the taken samples from the damaged area. The evaporation of contaminated condensate collapse the bubbles that leads to pitting and concentrating of the solution. Besides, the leakage of isolation block valve abnormally increases the velocity of fluid which erodes the inner surface of the line. The synergistic effects of erosion and corrosion caused the wall thinning in the upper part of the line and its subsequent rupture. These failures can lead to serious financial and employee losses. To minimize the risk and prevent the reoccur of such failures, the following recommendations are offered:
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