Introduction to the corrosion prevention issues of air coolers in hydrocracking units

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Introduction to the corrosion prevention issues of air coolers in hydrocracking units: Air coolers used to cool the products of isomerization or hydrocracking reactions may suffer from corrosion quite quickly, and there are many such cases documented in industry history. Due to corrosion, the lifespan of the tube is less than one year; this corrosion is caused by an ammonium sulfide solution. We explain here that this type of corrosion is not limited to heterogenization and hydroprocessing processes; it can occur in any hydrogenation unit where the reaction products contain water, ammonia, and H2S. This corrosion is also not confined to air coolers – in some comparative examples, corrosion occurs as long as such units are used in final product coolers. Corrosion can also occur in the pipelines downstream of the final product coolers. The purpose of this material is to provide users of CHEVRON’s refineries or processes involving isomerization and hydroprocessing with CHEVRON patents with guidelines on the causes of corrosion in reaction product coolers and on controlling corrosion caused by ammonium sulfide. Chapter 1 of this document summarizes the causes and nature of corrosion in the reaction product cooler. Chapter 2 discusses the important aspects related to the design of effluent coolers. Chapter 3 discusses the operational and maintenance precautions that we must follow in order to achieve a long service life. Causes of corrosion: Ammonium hydrosulfide: The corrosion of the coolers resulting from the reaction products of isomerization and hydrogenation is caused by aqueous solutions of NH4HS; the two main factors contributing to this corrosion are the concentration of NH4HS and the effects of flow rate/turbulence. The reaction products of hetero cracking or hydroprocessing usually contain hydrogen sulfide and ammonia, which are formed in the reactor from sulfur or nitrogen compounds present in the feedstock to yield H2S and NH4. When the reaction products are cooled, H2S reacts with NH4 to produce NH4HS, which is a solid that is highly soluble in water. In the absence of water, NH4HS will condense from the vapor and remain as a precipitate in the solid crystalline form; typically, this solid forms at the temperature conditions of the final reaction product cooler (usually an air cooler). To prevent solid precipitation, water is injected upstream of the air cooler. Due to the addition of water, an NH4HS aqueous solution is formed. For the sake of discussion, we classify the corrosive effect of NH4HS based on solution concentration; in terms of corrosion principles, diluted solutions are those of NH4HS with a concentration of less than 15% (by weight). The water from separators usually falls into this category. A concentrated solution is one in which the NH4HS concentration exceeds 35%; the reason for this difference will be clarified in subsequent discussions. When carbon steel is exposed to a diluted NH4HS solution, a film of iron sulfide corrosion product is formed quite rapidly. Since this film, once intact, can prevent further corrosion, it is unfortunate that this corrosion product film adheres only moderately to the metal substrate. It is eroded on the spot by the rapidly flowing logistics, and the exposed layer of metal that remains is further corroded. For this reason, the corrosion caused by NH4HS in diluted solutions is quite sensitive to the flow rate and turbulence; the damage observed is that erosion-corrosion occurs rapidly in areas with high flow rates or turbulence, such as at the inlet end of the exchanger tubes. This erosion-corrosion rate is related to the concentration of NH4HS, which determines the critical velocity required for erosion-corrosion to occur. Compared to the diluted solution, the concentrated NH4HS solution exists in a different form. Laboratory tests (2) showed that in solutions with concentrations above 35%, NH4HS is corrosive to carbon steel, even under static conditions. High speeds or turbulence are likely to accelerate corrosion, but they do not promote it in diluted solutions. Within the range of 15%-35%, we have some practically useful data to show the characteristics of corrosion. Corrosion occurs from a stationary state, and it is only when the concentration exceeds 35% that changes occur; it seems safe to conclude that within this intermediate range, both speed and turbulence are required to induce corrosion, although the critical speed will be lower. As we have just described, the nature of NH4HS corrosion leads to two distinct forms of corrosion in the reactor product coolant. In earlier heterogenously cracked and hydrogenated units, rapid corrosion occurred at the pipe ends and in other areas with high flow velocities and turbulent flow; generally, such corrosion occurred only when the flow velocity exceeded 20 feet per second. Such corrosion is a typical characteristic of dilute sulfide solutions. To avoid this, some effluent coolers are designed to operate at very low flow rates (some below 10 feet per second), and these coolers also suffer from corrosion in some cases. Damage to the pipe occurs not only due to erosion and corrosion at the pipe ends, but also in the local depressions and grooves along the pipe base. Such corrosion often occurs in heavily fouled pipes (it is recommended to use pipes with very low flow rates and minimal stagnation). This example illustrates that this form of corrosion occurs in pipes with high sulfide concentrations (>35%), where insufficient water is available to dilute the sulfides. To minimize corrosion, it is necessary to supply an adequate amount of water to keep the concentration of sulfides at a diluted level, rather than in a concentrated range. Furthermore, the maximum flow rate should be kept at a sufficiently low level to avoid erosion-corrosion caused by the dilution of sulfides. Specific flow rate parameters will be provided in summary in the “Sulfur Effluent Cooler Design”. Early studies showed that the severity of corrosion is related to the chemical composition of the process stream. High concentrations of ammonia and H2S accelerate corrosion, and the severity of corrosion can be related to the value of the coefficient Kp, which is the product of the molecular percentages of ammonia and H2S in the total process stream. Therefore, the stream containing 1% H2S and 0.5 mol% ammonia will have a value of 0.2 Kp. Assuming water is present here, the types of corrosion envisioned can only occur in a liquid phase where water exists. As KP increases, the process stream becomes more corrosive, and the maximum flow rate, which is the rate allowed without erosion or corrosion, should be reduced. Experience has shown that areas with a Kp value below 0.05 and a speed of 30 feet per second are acceptable. In areas where KP exceeds 0.05, this maximum flow velocity should be limited to 20 feet per second. When the Kp value is above 0.4, this flow rate must not exceed 20 feet per second, and stainless steel end caps should be used to prevent erosion and corrosion at the pipe ends. Also, as KP increases, it becomes increasingly important to avoid very low flow rates in order to improve phase separation, prevent scaling, and reduce the resulting formation of sulfide concentrations in situ. Therefore, as Kp increases, the maximum allowable flow rate decreases, while the minimum allowable flow rate increases. The approved flow rate range gradually becomes narrower as Kp increases. In areas where Kp is close to or exceeds 1, which is caused by improper design and operation, the exhaust cooler becomes extremely sensitive to corrosion; in such cases, the reasonable service life of carbon steel pipes can only be achieved when the exhaust cooler system is designed and operated with great care and utmost caution. The summary data from the operation device figures 1-3 show the combined effect of flow rate and Kp on the corrosion of the effluent cooler. Kp is a measure of the inherent corrosivity of the process stream in a process, and it is used as a guide for the design of reaction product coolers. For low Kp values, carbon steel pipes can be suitable for a wide and satisfactory range of fluid flow velocities; however, they are sensitive to imperfect design and occasional operational errors. However, when the Kp value is high, the acceptable flow rate range is narrow; in such cases, a pipe end sleeve is required at the inlet end of the pipe, because the reaction product cooler is quite sensitive to corrosion due to both its well-designed structure and potential misoperations. The operation of the reaction product cooler will be discussed in the final chapter of this document. Cyanides and other compounds such as H2S also have corrosive effects. In many plants, cyanide is present in the reaction product stream at levels of a few ppm; high nitrogen content in the plant’s feed materials makes it particularly easy for a moderate amount of cyanide to be formed. If even a trace of cyanide is present, the corrosion rate tends to increase. Cyanide is likely to have an impact on corrosion, even at the low level of 1PPm as determined by chemical analysis. It may be possible to resist cyanide corrosion by injecting sodium polysulfide and ammonium polysulfide into the reaction product stream upstream of the reaction product cooler. Polysulfides react with cyanides to form thiocyanate salts; furthermore, polysulfides tend to inhibit the corrosion of sulfur steels through ammonium polysulfide. Obviously, this is achieved by changing the adhesion and composition of the corrosion products of iron sulfide. Therefore, the injection of polysulfides can reduce corrosion, even in the absence of cyanides. Typically, polysulfides are injected into the washing water and then added upstream of the reaction product cooler to be introduced into the system. In reaction product cooler systems, the use of polysulfides as preservatives is a patented technology developed by CHEVRON Research Company. Oxygen in the reaction product air cooler system can also **accelerate corrosion and scaling; such corrosion is most severe when the Kp value is high.** Although we believe that oxygen can cause the previously formed iron sulfide scale to flake off (to become unadhered), we are still not clear about the corrosion mechanism that occurs in the presence of trace amounts of oxygen. This is merely a deduction, that is, oxygen reacts with H2S to form polysulfides that prevent corrosion. As we know, for example: oxygen is injected into the acidic stream in FCC units to prevent hydrogen bubbling. In this way, polysulfides may form in place. However, in heterogenous cracking and hydroprocessing units, it is beyond doubt that oxygen promotes corrosion and scaling. Oxygen can also decompose polysulfide preservatives, producing elemental sulfur and perhaps other products of corrosive reactions. As noted, the water has been contaminated with oxygen; meanwhile, if polysulfides have been added to the injection fluid, sulfur precipitation and rapid corrosion are likely to occur in the water injection pipelines and the reaction product coolers. Chlorides, which are salt forms of chlorine and mostly exist as ammonium chloride, are another common contaminant in the cooling systems for reaction products. Chlorine can originate from the feed to the facility or from the hydrogen used in catalytic reforming. If its concentration exceeds a few ppm, chlorine can have several adverse effects; it may cause scaling upstream of the reaction product coolers as well as at the water injection points. Chlorine can also lead to stress corrosion cracking in stainless steel. If the cooling water distribution within the reaction product coolers is inadequate, water may not reach certain tubes at all, resulting in the accumulation of ammonium chloride in those coolers. This situation leads to rapid corrosion beneath the salt deposits. For these reasons, high concentrations of chlorine can cause corrosion, but a few ppm of chlorine does not significantly increase the degree of corrosion in properly designed and operated coolant systems. Water also has a significant impact on corrosion, as the corrosion of reaction product coolers is a form of water-induced corrosion. Without water, corrosion would not occur. However, in a completely dry system, the accumulation of ammonium hydrosulfide crystals causes the coolers to scale up rapidly. To prevent ammonia hydrosulfide scaling, water must be injected into the process stream, upstream of the effluent cooler. Due to the high water solubility of ammonium hydrosulfide, an adequate amount of water can prevent scaling. Unfortunately, this results in an aqueous solution of ammonium hydrosulfide, which is highly corrosive. When the concentration of ammonium hydrosulfide is high, it erodes steel; whereas diluted solutions are less corrosive. For this reason, from a corrosion perspective, it is desirable to use as much water as possible in the reactor product cooler, in order to dilute the ammonium hydrosulfide and reduce corrosion. The minimum allowable injection volume is the amount of water required to prevent scaling caused by ammonia hydrosulfide; this means that the minimum injection volume must be greater than the amount needed to saturate the gas under the conditions at the inlet of the reaction product cooler. However, it is necessary to remove hydrogen sulfide and ammonia vapor from the acidic water in the downstream processing units. As a result, excess acidic water leads to increased costs associated with acid water stripping and wastewater treatment facilities. Therefore, the optimal injection volume represents a compromise between minimizing corrosion and minimizing the amount of acidic water that needs to be treated later on. Design of reaction product coolers: The carbon steel reaction product coolers are designed to achieve a controlled flow velocity within the tubes as well as an optimal distribution of the gas, water, and liquid hydrocarbon phases; therefore, the following design guidelines must be followed: Guideline: (1) The maximum fluid velocity flowing through the tubes should be 20 feet per second (6.1 meters per second). This is a good guideline for most reaction product coolers, but where the chemical equilibrium constant Kp is below 0.05, the maximum allowable speed is 30 feet per second. (2) Avoid low flow velocities inside the pipes: Low flow velocities promote three-phase separation, with some parts of the pipe containing mainly gas, while the remaining parts contain liquid hydrocarbons and water. This results in a lack of dilution water in some pipes, severe differences in flow rates, and scaling deposits in the pipes with lower flow rates. Due to the accumulation of these scaling deposits, the total flow rate in those pipes with low flow rates decreases until no flow is left. As a result of approaching a state of stagnation, corrosion may occur in the pipes. (3) If the chemical equilibrium constant Kp exceeds 0.4, install a pipe end sleeve at the inlet end of the tube. At a maximum flow rate of 20 feet per second, tube end caps are not required on well-designed and properly operated reaction product coolers; however, unexpected accidents can occur, such as the intrusion of oxygen or insufficient washing water, which can lead to erosion-corrosion at the tube ends even at flow rates below 20 feet per second. This effect is more severe in areas where the chemical equilibrium value K is high, and the installation of end sleeves provides a guarantee to prevent such situations from occurring. The pipe end sleeve should be made of 300 series stainless steel such as 304 or 316. (4) Avoid using tube end sleeves with obtuse angles; the tube end sleeves must have a minimum taper of 3-1, with a more uniform taper being preferable. The tube end sleeve shown in Figure 10 is considered ideal. Since vortices at the downstream end can cause rapid damage to the pipe, it is necessary to prevent the pipe ends from having sharp angles. (5) Tubular shells should be used at both ends; U-type heat exchangers or coiled tubes with elbows should not be employed. Even when the flow velocity is below 20 feet per second, turbulence at the elbows can cause corrosion. In the design, tubular shells or other designs that do not allow for pipeline cleaning should be avoided. (6) Consider the velocity inside the tube sheet. Erosion-corrosion in the tube sheet is not common, but it can occur if the flow velocity is too high. The maximum flow velocity inside the tube sheet should be the same as the maximum allowable flow velocity inside the tubes; however, low flow velocities promote undesirable three-phase separation. Therefore, the speed should be close to the maximum allowable value. Note that two nozzles rather than one should be used in each tube bank; the speed of the tube bank should therefore be halved. (7) Use symmetric inlet manifolds. Even flow distribution among multiple cooler units is important, and this becomes even more crucial as the chemical equilibrium constant Kp increases. To achieve a good distribution among multiple air-cooled heat exchangers, balanced or symmetric inlet manifolds should be used. As shown in Figure 8: equilibrium at the inlet of the tube bank can be achieved when the number of Pingping units is equal to 2n (2, 4, 8). (8) Multiple water injection points – Each outlet cooler series should have its own separate water injection point, as shown in Figure 8. Since the water injection nozzles can sometimes become clogged and require maintenance, the water injection system should be equipped with devices to measure and control the amount of water supplied to each injection point. In systems with a high chemical equilibrium constant Kp, as well as in those with asymmetric inlet pipelines, it is likely impossible to achieve good corrosion control by using a single water injection point. (9) The piping design downstream of the reaction product cooler should be designed for minimum turbulence, with the maximum flow velocity limited to the same value as that used in the reaction product cooler. Corrosion also occurs in the carbon steel pipes downstream of the reaction product cooler; the causes of this corrosion are the same as those for the cooler’s corrosion, and it occurs under many identical conditions. When corrosion does occur in pipes, the typical locations are at bends, tees, elbows, or other areas where turbulence exists. The above guidelines are based on the use of carbon steel pipes and tube boxes. However, there are times when it is justified to use stainless steel; some examples are as follows: the lifespan of steel pipes in existing installations is too short, mainly due to poor design or inadequate operation of the reaction product cooling system. New devices designed with a high Kp (approximately greater than 1), in which additional costs are considered justified to ensure maximum reliability. Where alloy steel is used, the recommended type is heat-resistant nickel-chromium-iron alloy steel 800; by 1978, the first devices made from this heat-resistant nickel-chromium-iron alloy 800 had already been in use for 9 years. No accident reports have been found regarding the use of heat-resistant nickel-chromium alloy 800 tubes in reaction product coolers. When using heat-resistant nickel-chromium alloy 800, the tube box should also be 800; spending money on such expensive alloy steel tubes is not a good way to save costs, and it poses a risk of corrosion of the tube box. The design requirements for the heat-resistant nickel-chromium alloy 800 are not as stringent as those for carbon steel, which may result in higher costs for this alloy. Partial recovery is achieved; for example, the maximum fluid velocity can be increased to 30 feet per second, and it is no longer necessary to use sleeves. From the perspective of preventing scaling and maintaining the performance of the heat exchanger, having balanced inlet manifolds and multiple water injection points is sufficient, although they are not essential for preventing corrosion. Heat-resistant nickel-chromium alloy 800 tubes also offer certain advantages in terms of operation; they maintain a higher level of cleanliness compared to steel tubes. They are highly resistant to operational failures such as insufficient water supply or oxygen intrusion. However, it should be noted that while the alloy coolers themselves remain unaffected, the carbon steel tubes downstream of the reaction product coolers can be severely damaged. Monel tubes have been used in a few devices and have performed well, but all of these devices operate at low Kp levels; at higher Kp values, Monel tubes may corrode. Chromium steels with 12–17% chromium, such as types 410 and 430, have been used in many applications; however, the results in most cases have been very poor. These alloys offer resistance to high-speed erosion-corrosion on their surfaces, but they are highly susceptible to corrosion in areas with low flow rates or stagnant flow. Austenitic stainless steels, such as type 304, have not yet been used in reaction product coolers, yet they possess fairly good corrosion resistance. This theory is based on the fact that stainless steel linings have been in use for many years without showing significant signs of corrosion. The main concern regarding austenitic stainless steels is the potential for chloride-induced stress corrosion cracking. Although the likelihood of chloride-induced corrosion cracks is relatively low in most devices, industrial production has consistently avoided using these stainless steels in favor of approved alloys such as the heat-resistant nickel-chromium alloy 800. Figure 4 provides an overview of the industrial experience with alloy steel pipes in effluent coolers. If the operation of the reaction product cooler is not handled properly, even a well-designed one can suffer from corrosion. On the basis of designing a fairly good system, it is also necessary to pay due attention to the inherent corrosivity of the process fluids in order to prevent corrosion. The key points for operating the reaction product cooler include maintaining an injection flow rate of sufficient quality water, avoiding oxygen (air) in the injected water, keeping the cooling tubes clean, and injecting polysulfide corrosion inhibitors. Water injection volume: The minimum water injection volume to be used should be 1 gallon per minute, for 1000 barrels of feed per day. Furthermore, it is necessary to verify that at the inlet conditions of the reaction product air cooler, at least 25% of the water injection volume remains unvaporized. The complete vaporization of the injected water will lead to scaling and uncontrolled corrosion. 25% of the unvaporized water volume is the absolute minimum value without including a safety factor. The aforementioned water injection rate enables good corrosion control in most devices. But sometimes a higher water injection rate is required, for example when Kp is very high or when the design of the reaction product cooler system fails to ensure proper water distribution. Experience has clearly shown that increasing the injection water flow rate can reduce corrosion, and in many cases even eliminate it. The concentration of ammonium hydrosulfide in the water from the high-pressure separator may be used to guide corrosion control. Although this is a useful guide, it is not an absolute method. Corrosion is caused by the presence of ammonium hydrosulfide in the water, but the corrosion rate inside the pipes is determined by the concentration of ammonium hydrosulfide within those pipes, rather than by its concentration in the water of the separator. The concentration inside the tube is related to the distribution of water in the reaction product air cooler. Poor water distribution can lead to high concentrations of ammonium hydrosulfide; therefore, more water must be injected into the pipes with poor distribution in order to reduce the ammonium hydrosulfide concentration to an acceptable level. For these reasons, in a single device, establishing a correlation between corrosion and ammonium hydrosulfide concentration is truly effective. Summarizing operational experience in the unit can provide guidance on things such as the allowable concentration of ammonium hydrosulfide. Figure 5 shows a summary of the operational experience with the device. Two points are shown in Figure 5. The first point is that experience with some units shows no corrosion even when the ammonium hydrosulfide content in the separator water is as high as 1/2% (by weight). It should be noted that all devices using reaction product coolers designed in accordance with the aforementioned guidelines were not subjected to corrosion at such high ammonium hydrosulfide concentrations. The second point is an approximate “worst-case” correlation. Without the addition of polysulfides, mild corrosion begins at 1% NH4SH, moderate corrosion starts at 2%, and severe corrosion occurs at 3% or higher. This shows that even for those poorly designed reaction product cooling system, adding an adequate amount of water is generally sufficient to reduce corrosion to an acceptable level. Data show and operational experience confirms that increasing the water flow rate to achieve an ammonium hydrosulfide content of 2% in the separator water reduces corrosion in the reaction product cooler, thereby enabling the attainment of the allowable service life of the tubes. However, it should be recognized that diluting to 2% is the “worst-case scenario,” and corrosion control is not required in all devices. Figure 6 shows the comprehensive effect of changing the injection flow rate. Properties of the water to be used: The water injected upstream of the reaction product cooler must meet the following specifications regarding its chemical composition: H2S – maximum 1000 ppm (by weight); NH3 – maximum 1000 ppm (by weight); Cl– – maximum 50 ppm (by weight); Ca – maximum 3 ppm (by weight); O2 – maximum 50 ppb (by weight). If polysulfides are added to the water, its pH value must be ≥7.5. A pH value below 7.5 causes polysulfides to decompose. Among the above requirements, oxygen content is the most important. Oxygen has various harmful effects: it **significantly accelerates corrosion and shortens the lifespan of cooling tubes, causing severe scaling in the reaction product coolers and downstream equipment. Oxygen can decompose polysulfide preservatives and further increase corrosion. If the injection water contains oxygen and polysulfides are used, corrosion and blockage of the injection pipelines will occur due to the formation of elemental sulfur. Most refineries find that the oxygen content in the make-up water should be maintained within the range of 5–15 ppb. Stirred acid water is given priority over steam-condensed water or deoxygenated water for injection. The most important thing is that the water after stripping is almost absolutely free of oxygen. Condensate water (especially that from surface condensers) often contains dissolved oxygen. Deoxygenated water often fails to be fully deoxygenated. Furthermore, the advantage of stripped water is that it is slightly alkaline, whereas condensed water is slightly acidic due to the dissolved carbon dioxide. Therefore, a low pH value will inevitably decompose polysulfides, which is quite dangerous. Control of oxygen ingress: If oxygen has the possibility of entering the system, it is difficult to prevent corrosion when the system becomes contaminated by oxygen. For this reason, preventing the entry of oxygen is of the utmost importance. The only way for oxygen to enter the reaction product cooler system is through water injection. There can be multiple entry points for oxygen, and it is not easy to determine its source. Typically, some sources include the following aspects: (1) Using boiler feedwater that has not been fully deoxygenated as injection water. (2) Use the condensate water from surface condensers through which air leaks into the vacuum system, thereby dissolving oxygen. (3) A “buffer tank” is commonly used to eliminate the possibility of process fluids from high-pressure systems entering the water supply system. These buffer tanks should be sealed rather than open, and must be filled with an inert gas. Use oxygen as the shielding gas. Many of the so-called inert gases used in refineries are only inert to the extent that they do not contain enough oxygen to cause combustion. The cover gas should be oxygen-free. Gases with a high carbon dioxide content cannot be used as shielding gases either, as they lower the pH value of water, which in turn leads to the decomposition of polysulfides later on. (4) Air leaks in from the packing or mechanical seal of the water supply pump. (5) The injection pump can also draw in air due to the extremely low pressure at the suction inlet. From a worst-case perspective, it is necessary to seal the suction side of the pump with a lightweight metal box, while maintaining an oxygen supply to inside the box. The entry of oxygen is not regular, and it is difficult to detect through occasional water analysis. Periodic water sampling is required, and the location of sampling is important. If polysulfides are not used, take a water sample at the outlet of the injection pump. When polysulfides are used, the water sampling point is located upstream of the polysulfide injection point, as polysulfides interfere with oxygen analysis. Water samples taken upstream of the polysulfide injection point cannot detect oxygen that has leaked in from the injection pump; other signs must be used to determine this (such as sulfur deposition within the injection pipeline). When taking water samples for oxygen content analysis, it is necessary to be extremely careful to prevent air from contaminating the samples. Whenever corrosion or scale buildup occurs, unless there are other obvious reasons, oxygen ingress should be suspected. Absolute evidence of oxygen ingress can be obtained by using X-ray fluoroscopy on the corrosion products taken out of the reaction product cooler. Experience has shown that ammonium ferric sulfate NH4(FeSO4)2·12H2O is a characteristic corrosion product found in oxidized systems; this product does not form in the absence of oxygen. The X-ray fluoroscopy images of this product can be found using the following parameter data: Sample taken at site No. 7–5 by the Joint Committee on High-Intensity Fluoroscopy Standards of the American **Standard Bureau should show the same sampling intervals along the pipeline as specified in those reference materials, although the intensity of the fluoroscopy will vary. The elemental sulfur corrosion products in the reaction product air cooler are an indication of the presence of oxygen, but not absolute evidence. Iron oxide in the corrosion products does not necessarily prove the presence of oxygen. The formation of normal iron sulfide corrosion products in the reaction product cooler is the result of natural oxidation upon contact with air. Therefore, iron sulfide samples taken on-site almost always show some iron oxide, which is formed as a result of exposure to air between sampling and analysis. Polysulfide corrosion inhibitors are typically sodium polysulfide or ammonium polysulfide, added to the injection water, to control corrosion in the reaction product coolers and the pipelines downstream of them. Sodium polysulfide is generally used due to its low cost and good stability. However, the use of ammonium polysulfide can minimize the sodium content in the acidic wastewater. The recommended polysulfide injection rate is the maximum of 10 ppm (by weight) in the injection water or five times the stoichiometric amount required to react with the cyanide present, whichever is higher. In most installations, the concentration of cyanide is very low; in most cases, 10 ppm of polysulfide, based on the amount of water injected, should be sufficient. Accurately analyzing the cyanide concentration in the process streams can clearly serve as a guide for determining the injection rate of polysulfide. However, it is difficult to accurately measure low concentrations of cyanide. Appendix-1 lists the improved analysis methods developed by CHEVRON Research Company. As mentioned earlier, polysulfides decompose not only due to the presence of O2 in the injection water but also when the pH level of the injection water is low. The decomposition of polysulfides leads to sulfur clogging of the pipelines, corrosion of the injection lines, and accelerated corrosion of the coolers for the reaction products. If these problems occur, the best approach is to eliminate the causes of polysulfide decomposition. If it is not possible to stabilize the conditions and prevent decomposition, it may be necessary to stop injecting polysulfides temporarily or permanently; this decision should be made carefully. Oxygen contamination is far more severe than low water injection pH. In systems contaminated by oxygen, corrosion cannot be controlled whether polysulfides are injected or not; therefore, it is necessary to identify the source of oxygen and address it. When the water injection pH is low and polysulfides decompose along with the cessation of injection, corrosion will not accelerate (except when the polysulfide corrosion inhibitor becomes ineffective). Devices designed in accordance with the aforementioned guidelines, without the injection of polysulfide, often exhibit relatively little corrosion; however, if the injection of polysulfide is stopped for an extended period of time, it is necessary to carefully monitor for signs of corrosion and buildup in the reactor coolant. The polysulfide solution should be kept away from air before injection; the polysulfide tank should be covered with an inert gas or a layer of oil on its surface to prevent contact with air. Changes in plant operating conditions: When there are changes in the plant’s operating conditions or in the raw materials used, it is necessary to adjust the corrosion control methods accordingly. Operations can be adjusted based on the following influencing factors. 1. By comparing the HS~ concentration and Kp in the water of the separator under old and new conditions, a smaller increase in HS~ concentration (10–20%) has no significant effect on corrosion, while a larger increase (over 50%) can significantly accelerate corrosion. 2. Determine the tube bundle linear velocity under new conditions and compare it with the previously specified values. 3. Calculate the vaporization rate of the injected water under air-cooled inlet conditions; if the estimated vaporization rate of the injected water is above 75%, the amount of water injected should be increased. 4. To change the high Kp and HS~ concentration of water in the separator, the water injection volume can be increased. If no polysulfide corrosion inhibitor is injected, it can be injected as a compensation; however, it is necessary to take into account that increasing the water injection rate will raise the tube velocity in the air coolers. Yet, the benefit of increased water injection for corrosion prevention outweighs the negative effects of increased tube velocity on corrosion prevention, and it is absolutely not permissible to reduce the corrosion rate by decreasing the water injection rate in order to lower the tube velocity. 5. The volume of circulating air can be adjusted appropriately to keep the wind-cooling tube velocity within the allowable range. Of course, the impact on the process should be taken into account. 6. Installing an internal tube turbulence sleeve at the inlet end of the air-cooled tube bundle can compensate for the corrosion caused by line speeds exceeding the 20 feet/s limit in air cooling systems. 7. The inspection of the air cooler should be conducted more frequently and thoroughly than before the changes, until the corrosion rate under the new conditions becomes reasonable. Scale formation on air coolers: In addition to reducing heat transfer, scale formation on air coolers has other effects as well; uneven scaling affects the distribution of the washing water, and it also causes differences in flow velocity between the tube bundles. Both situations increase the corrosion rate. The most common effect of scale accumulation is pitting inside the tubes, which is caused by insufficient water injection and very low tube velocities. Additionally, scale at certain tube velocities can result in higher linear velocities in other sections of the tube bundle, leading to erosion at the inlet end. For the above reasons, the air cooler tube bundles must be kept clean. The air cooler can be descaled using mechanical or chemical methods; the use of hydrochloric acid with corrosion inhibitors to remove scale and accumulated corrosion products has yielded good results. Appendix II shows the chemically cleaning procedures successfully employed by CHEVRON. A clogged tube bundle will result in abnormal cooling effects as the unit continues to operate. Therefore, the degree of blockage is determined by analyzing the temperature distribution curve. Some refineries have adopted infrared technology to measure temperature irregularities and scale buildup, in order to identify the clogged tube bundles. Causes of air cooler blockage: 1. Oxygen interference can lead to sudden and severe corrosion acceleration. 2. Tube bundle corrosion (under any circumstances) generates corrosion products (iron sulfide) that cause blockages; even in small amounts, such corrosion products can lead to fouling and blockages over time. 3. Dissolved metals in the make-up water precipitate as sulfides when they come into contact with process streams containing H2S. A make-up water flow rate of 50 gallons per minute with 1 ppm of iron will result in the formation of more than 300 pounds of FeS per year. 4. Organic fouling (which has occurred before) is very rare; it results from process-related factors that lead to the formation of organic deposits in the operating equipment. Chevron can provide information on the causes of such fouling as well as methods for removing it. Air cooler inspection: Regular inspections of air coolers are necessary to prevent accidents and to provide early warnings so that anti-corrosion measures can be improved. The following inspection techniques can be used; for most of these methods, the air cooler must be thoroughly cleaned before inspection. 1. Visual inspection: Open the thread plug of the tube box and visually inspect the erosion-corrosion condition of the tube ends and tube sheet. Inspect the corrosion on the side of the plug that is exposed to the fluid; since the process fluid comes out of the pipe and comes into direct contact with the plug head, the degree of corrosion can be assessed by examining the metal loss on the plug head. 2. X-rays: The erosion-corrosion condition at the tube ends of the air cooler can be determined using X-rays. The X-ray source is placed right behind the tube sheet, and if there are a few inches of finless tube bundles behind the tube sheet where the reaction products are cooled, it is easy to carry out such detection. 3. Pipe inspection camera: Although this method is slow and cumbersome, it is still necessary for detecting separated points of contact. Because irregular pitting is caused by scale accumulation and low flow rates. Therefore, during inspection, those pipes prone to scaling should be checked. If the inlet pipe is not symmetrical, the outer air cooler tends to accumulate scale and suffer pitting. 4. Electronic detectors: There are several patented detectors (similar to eddy current detectors) that can be used to inspect tube bundles, though the reasons for detection differ. By 1978, such instruments were not yet available; if you wanted to use one to inspect your equipment, it was necessary to enter into a contract with the agent appointed to supply the detection equipment. An instrument called “Ferrolog” has been used with considerable success in refineries in the United States. 5. Infrared detection: Use infrared technology to regularly inspect the operating air coolers. It can determine whether the depth distribution is uniform and can identify blocked pipelines; if an entire air cooler is blocked, it indicates that the water injection nozzle is blocked. Accident analysis and measures to be taken: If the tube bundle is corroded, it is necessary to identify the cause in order to take appropriate remedial actions; the most common causes of corrosion are shown in Figure 7. Certain forms of corrosion damage stem directly from an inadequate air-cooling design for the reaction products. For example: a higher linear speed, the use of elbow fittings, and pipe end caps on steep slopes – whether these can reduce corrosion depends on the extent of the design flaws. All forms of corrosion illustrated in Figure-7 are exacerbated by oxygen entering the system or insufficient washing water; regardless of the cause of the corrosion, it can be alleviated by increasing the water injection volume and removing oxygen (reducing it to a concentration that will not exacerbate corrosion). Polysulfide additives can provide corrosion inhibition, but this does not apply to pitting that occurs in blocked pipes; polysulfides cannot stop pitting inside such pipes, yet they do help reduce scale formation. When the system remains clean, the injection of polysulfides can minimize blockages and corrosion. The differences in corrosion and fouling among the generally parallel air coolers indicate a poor flow distribution, which can be caused by unbalanced (asymmetric) inlet piping, the use of only one water injection point instead of multiple ones, or unstable flow due to fouling. Depending on the severity of the blockages and corrosion, the problems can be resolved in their entirety or partially through the following methods: cleaning the air cooler, installing additional water injection points, removing the clogged water injection nozzles, and reorganizing the symmetric inlet piping. Erosion and corrosion at the inlet pipe end can be addressed by installing a stainless steel pipe end sleeve; this sleeve must be thin at the outlet end and slightly thicker at the inlet end, with a gradual transition, to prevent eddies. Both TYPE304 and 306 steels are commonly used materials, and the pipe end fittings must be thin-walled to further prevent eddy currents. Erosion-corrosion at the outlet end of the air cooler tubes can also be addressed by using tube end sleeves, but most corrosion at the outlet ends is caused by oxygen contamination. Therefore, removing oxygen is much more economical than installing pipe ends, and the use of pipe end sleeves at the outlet end is relatively uncommon. As mentioned earlier, elbow fittings and U-tubes must never be used in the air-cooled reactors for carbon steel. For air coolers that are already designed in this way, corrosion at the elbow joints can be prevented by installing corrosion-resistant elbow joints. Austenitic stainless steel elbow fittings have been successfully used. Low-carbon or solution-treated grades such as AISI TYPE 304L, 316L, 321, and 347 can be selected to avoid the possibility of intergranular corrosion at the welds. Incolog800 has quite good resistance to corrosion, and it can also effectively resist chloride-induced corrosion cracking. If the design is poor, the reaction product air cooler will corrode rapidly from the day it is put into use. To address these design shortcomings, the following measures should be taken: 1. Increase the water injection volume; 2. Inject polysulfides; 3. Clean it regularly; 4. Eliminate oxygen interference. If the results are not satisfactory, the following design modifications can be considered: 1. Install end caps on the tube ends. 2. Replace it with an alloy elbow. 3. Install multi-point water injection; do not use single-point water injection. 4. Replace the unbalanced inlet piping with a balanced and symmetrical one. 5. All reaction product coolers have been replaced with alloy ones (Incoloy 800). If corrosion did not occur before but unexpected corrosion or scaling appears now, anti-corrosion control measures can be taken to remedy the situation. The common causes of corrosion are: 1. The intrusion of oxygen, which can lead to severe scaling along with corrosion; this results in the accumulation of corrosion products such as iron sulfide and sulfur, as well as corrosion of the water injection lines (if polysulfides are used). 2、Scaling on the pipes: Over time, the accumulation of scale can cause flow imbalances, leading to localized corrosion. 3. One or more water injection nozzles may become clogged; these nozzles should be inspected and cleaned every time there is a shutdown. If possible, an independent flow meter should be installed at each water injection point. 4. Insufficient water injection volume. 5. Insufficient amount of polysulfides. 6. The concentration of corrosive substances in the process fluid increases. (Ingredient S·N content) 7. An increase in the feed or circulation rate may cause the flow velocity to exceed the 20 feet/second limit, leading to erosion and corrosion at the pipe ends. To determine the causes of corrosion at its root and identify the most effective remedial measures, patent holders of Chevron’s hydrocracking and hydrotreating technologies can contact Chevron Research directly, while those from Chevron’s manufacturing facilities can reach out to the Materials Department in the Engineering Division (San Francisco), the Materials Laboratory in the Engineering Division (Richmond), and the Engineering Division for Research and Processing Technologies at Chevron (Richmond). Additional note: Regular analysis parameters for the acidic water from hydrocracking cold fractionation: 8.5≤pH≤9.5, Cl-≤480mg/L, Fe2+3+≤8.0mg/L ； This indicator monitors Fe2+3+; if its level is too high, it indicates that the air-cooled thinning is occurring too rapidly, and this should be given due attention.