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An Integrated Approach to Optimizing Corrosion Control for Refinery Process and Boiler Systems

Gregg Robinson GE Water and Process Technologies

4636 Somerton Road Trevose, PA 19053

USA

Trevor Dale Ph. D. GE Water and Process Technologies


USA

Mark Hoel GE Water and Process Technologies


USA

ABSTRACT

Treating steam condensate systems with neutralizing and filming amines has been commonplace in industry for several decades. Refinery steam and condensate systems are often considered “tough to treat” due to their complex configuration and uses of the steam – direct injection in furnaces and distillation towers, flash-steam reboilers, high alkalinity make-up water sources, multiple opportunities to introduce hydrocarbon contaminants, and several other factors – requiring extra attention to maintain good system protection while minimizing impact on the process. Specifically, improper selection and application of steam neutralizing amines can contribute to salt-induced fouling and corrosion in crude overhead systems. In response, technology development in the areas of amine performance modeling, neutralizing amine selection and the use of volatile filming corrosion inhibitors facilitates steam system protection and avoids process system salting. This paper will discuss the design, application, and benefits of utilizing an integrated approach to develop programs to both protect the steam system and avoid negative impact to the refinery process. Several short case studies are included. Key words: Corrosion, Reboiler, Condensate, Boiler Water Treatment, Polyamine, Low-Salt Amines

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Paper No.

9377

©2017 by NACE International.Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing toNACE International, Publications Division, 15835 Park Ten Place, Houston, Texas 77084.The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

INTRODUCTION Balancing reliability and efficiency in the steam plant and refinery operation has been a long-standing goal in the chemical treatment services provider and refinery partnership. However, that relationship has received greater attention in recent years as refiners look to further optimize operations to capture profitability. A prime example and focus of this discussion is when the refiner strives to maximize distillate production. This operational adjustment involves lowering the atmospheric distillation tower top temperature thereby moving dew point and amine-chloride salt points further upstream and potentially into the tower or pump arounds. If amine-chloride salts form, severe corrosion can occur and cause major reliability and economic implications in the form of unplanned shutdown and maintenance costs. The condensate treatment can directly impact this corrosion potential by introducing unwanted or “tramp” amines by way of the stripping steam used in the tower to help improve fractionation. Fortunately, the water and water/process modeling and chemistry capabilities have expanded to accommodate the refiners’ optimization and maintenance goals. Although neutralizing amines and filmers have been used for decades, technology improvements in the treatment chemistry and application have allowed for increased reliability of the process and water systems. In short, by using neutralizing amines in the steam treatment that are less likely to form amine-chloride salts, the process reliability is enhanced. Furthermore, by incorporating polyamine, a volatile film forming chemistry, into the treatment, steam condensate/boiler feedwater protection can improve while minimizing the overall amine loading to the distillation tower. Water Treatment Background The water and steam system of a refinery is often referred to as the lifeblood of their operation. As a result, maintaining the efficiency and reliability of those systems is paramount. To help maintain the integrity of the entire steam system, corrosion protection of the boiler feedwater and condensate system is required. By protecting the critical refinery exchanges and piping, unwanted downtime, system contamination, and losses of the highly valuable steam condensate can be minimized. In addition, by lowering corrosion rates, the metal transport to the boiler/steam generators is also minimized, decreasing the boiler blowdown and internal treatment requirements. Refineries, like most industries, utilize neutralizing amines to protect their steam condensate systems. These organic amines function by neutralizing acidic contaminants and then increase the pH to an appropriate level for minimizing corrosion of the various system metallurgies, often mild steel and copper. Neutralizing amines, each carrying specific properties with respect to neutralization capacity, basicity, volatility, and thermal stability are often fed in some combination to achieve maximum system protection. Unfortunately, some of the best amines for refinery steam system protection are the least compatible with the crude unit processes. Film forming chemistries, such as octadecylamine (ODA), have also been used for many years to help minimize corrosion. One advantage of filmers versus the neutralizing amines, is that they work substoichiometric to the contaminant by forming a hydrophobic barrier that prevents the contaminants (e.g. carbonic acid, oxygen) from reaching the metal surface. Although effective in corrosion prevention, there have been some issues with traditional filming chemistries which probably have limited its use in refining. These problems include their difficulty in formulating and sensitivity to overfeed. Additionally, because these traditional filmers do not readily partition to the steam phase, they must be fed to a steam header in relative proximity to the location in the system requiring protection. As we will discuss, the filming technology presented in this paper carries different properties, particularly with respect to volatility.

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Process Side Background The refinery operation is a dynamic process requiring flexibility in its operation to capture the changing market demands for finished products. Refiners are often looking to buy cheaper crude oil but that can be relatively challenging to process and then optimize the process for maximum yield of the most profitable product depending on market conditions. In many cases, the chemical treatment provider is called upon to help the refiner navigate the reliability aspect of the optimization process. As mentioned earlier, it is often advantageous for a refinery to maximize the distillate production which can require a significant operational change to their atmospheric crude tower temperature profile. In lowering the tower top temperature to capture maximum distillate yield, the potential increases for the dew point and amine chloride salt points to move upstream and into the tower or pump arounds. This can cause unwanted corrosion/fouling limiting the desired yield and/or unplanned downtime. Consequently, it is advantageous to the refiner to limit the unwanted or “tramp” amine presence in the distillation tower or utilize amines that would not tend to form amine chloride salts if present. There are many potential sources of amines entering the atmospheric tower as shown in Figure 1. One of those sources is the stripping steam that is used to help improve fractionation. This steam contains the neutralizing amines required for steam system protection as described earlier. Sometimes, it is these amines in the stripping steam that can ultimately limit the refinery’s ability to operate the atmospheric tower at the desired temperature. Consequently, it is recommended to minimize the amine loading where possible and utilize amines that have less potential for forming amine-chloride salts in water and process treatment.

Figure 1: Crude unit atmospheric distillation tower

Dynamic modeling tools, simulating the impact of tower operation and known amine properties, can be used to predict where problems will occur and what is the limiting factor under a certain set of conditions. Such a modeling tool helped determine what amine(s) would be the most appropriate for use in the steam condensate treatment so as to be more compatible with the crude unit operation.

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AN INTEGRATED APPROACH

It is imperative that coordination exists between the process and water treatment strategies, particularly where the two chemistries can intermingle. For example, the process treatment company is typically using a neutralizing amine for pH control for the tower overhead. This neutralizer will have specific salt point characteristics, i.e. the temperature that amine-chloride salts begin to precipitate from the vapor, which are critical for controlling corrosion and fouling mechanisms in the distillation tower. Consequently, the pH and corrosion control can be directly impacted by the water treatment neutralizing amine(s) entering with the stripping steam. This amine contribution can make corrosion/fouling control very difficult for the process side consultant. For various reasons, the process and water treatment providers are from often different organizations which can make this challenging for all parties, including the refiner. It is not surprising that refiners have been asking for a more holistic approach to refinery corrosion control. As a result, hydrocarbon processing and water technology and engineering teams began the process of developing an integrated solution for refinery steam and process treatment. At the core of the plan was to incorporate amines that can maintain effective steam system protection while also improving process compatibility. Specifically, these neutralizing amines have less tendency to form amine-chloride salts in the atmospheric distillation tower operating at lower tower top temperatures. To develop a steam treatment amine program that provides the desired protection of the boiler and process systems economically, proprietary modeling programs for process and steam system were used. Rigorous evaluation of several amines were completed using ionic modeling to understand the behavior of the amine(s) under varying crude unit conditions. A proprietary utility chemistry modeling program was used to simulate the performance and economics in a refinery steam system to ensure its validity. A comparison of amines used in refining are shown below in Table 1. The low-salt amine blend showed significant improvement and less likely to form salts at higher temperatures.

Table 1: Comparison of Steam Amine Salt Points

These programs allow for a virtual “test-drive” to see the impact of chemistry and contaminants throughout the entire boiler/steam/condensate system and into the crude unit atmospheric tower or other modeled unit operation.

Chloride

Original Amine

Blend

Industry Standard

Amine Blend

Low-Salt Amine

Blend

(ppm)

10 228 212 184

20 244 224 198

40 261 237 212

70 275 247 223

100 284 254 231

130 291 259 237

160 297 263 241

Pressure 8.7 psig

SALT POINT DATA OF AMINE BLENDS IN CRUDE UNIT OVERHEAD, Deg F

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Maximizing steam system protection using polyamine

Although effective, low-salting amines are not necessarily the most economical choice for steam condensate treatment. To maximize protection and economic benefits, a newer technology was incorporated into the steam condensate program. Polyamine, a volatile film forming technology, can provide enhanced protection of the entire boiler/steam system. Unlike traditional filmers, polyamine exhibits considerable ability to partition to the steam phase as shown in Figure 2.1 Consequently, the polyamine can be injected into one location, such as the deaerator storage section, but effectively travel the entire steam condensate system. When applied correctly, the polyamine enables reduced neutralizing amine dosages, lowering the overall treatment cost.

Figure 2: Polyamine distribution as a function of pressure

The polyamine technology is particularly effective in minimizing corrosion in two areas often plaguing refiners –

1. Boiler feedwater protection under conditions where mechanical deaeration is not optimal.

2. Reboiler protection – particularly units using low pressure steam from flashed condensate that is laden with carbon dioxide (CO2).

Boiler Feedwater Protection Several refiners have been plagued at times with deaerators that are not working optimally, leaving potentially problematic levels of dissolved oxygen in the boiler feedwater train. This is not necessarily due to design problems, but can be due to mechanical failures (e.g. nozzles, trays, valves, etc.), operational issues or other various reasons. However, it is often not practical/economical to remove the deaerator from service, as one deaerator provides feedwater for many refinery boilers. Additional “oxygen scavenger” is often applied but many times is not sufficient to remove all of the dissolved oxygen, leaving downstream equipment (e.g. closed feedwater heaters, economizers, boilers, condensate, etc.) at risk of corrosion. Laboratory and field testing have shown that improved feedwater protection can be achieved thru the addition of polyamine. Figure 3 is a photograph of the low carbon steel coupons treated with polyamine in the presence of 100 ppb of oxygen. The polyamine inhibitor adsorbed on the metal surface makes the water droplets “bead”. The surface of the metal behaves hydrophobically and the water does not wet the surface. As presented in the referenced 2011 NACE paper, enhanced protection was achieved

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with polyamine when compared to both untreated deionized water and deionized water treated with oxygen scavenger (down to 12 ppb of O2) exposed to 20 and 100 ppb of dissolved oxygen.2

Figure 3: Water beading on LCS coupons after they had been treated with polyamine for seven days

at 10 ppm of polyamine product, 100 ppb of oxygen and 110 ºC (230 ºF) in deionized water. The average corrosion rate measured for the two coupons was 0.234 mpy (0.00596 mm/y)

In an actual operating boiler system, a comparison was conducted in softened boiler feedwater as this is still a common source of make-up to refinery boiler systems. In this case, the benchmark was a sulfite treatment to take the dissolved oxygen down to <10 ppb. The Polyamine treated feedwater had oxygen ranging from 20-50 ppb. Figure 4 shows the coupons from boiler feedwater during the trial.

Figure 4: Characteristic examples of low carbon steel coupons obtained during the field trial

The overall average corrosion rate for the feedwater coupons for sulfite-based traditional boiler treatment benchmark was 3.07 mpy with a standard deviation of 1.28 mpy. The overall average corrosion rate measured for the polyamine treatment was 0.215 mpy with a standard deviation of 0.02 mpy. There was a considerable reduction (93%) in the carbon steel feedwater corrosion rate when the polyamine treatment was applied versus the sulfite-based benchmark in this deaerated system.2

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Reboiler Protection Reboiler corrosion is another considerable issue in many refinery steam systems. Many low pressure reboilers make use of steam that is flashed from condensate. This low pressure steam will then be used to control the temperature in the process column in a heat exchanger called a reboiler. The reboiler can be vertical or horizontal, with steam on the tube or shell side but steam will usually fully condense within the exchanger. As shown in Figure 5, because of the relative volatility of the CO2 to any neutralizing amine, the steam to the reboiler will often have a very low pH upon condensation. Many of these reboilers maintain a liquid level and do not have proper venting which allows for significant corrosion to occur. The reboiler metallurgy will sometimes be replaced with stainless steel if bundle replacements become too frequent or costly. Polyamine has shown to have a very positive benefit in reboiler protection because of its ability to work substoichiometric to the carbonic acid. More discussion on reboilers will be included in the case study section.

Figure 5: Condensate flash tank providing steam to reboiler

As documented in the earlier referenced NACE paper, considerably better corrosion protection can be obtained in systems treated with polyamine. In an actual operating system, Crovetto reported an 85% reduction in corrosion rate at equal pH in a condensate system with 0.5 to 0.7 ppm of dissolved oxygen.

2 The beading on the surface is direct indicator of hydrophobicity as shown in Figure 6. By not allowing the moisture and contaminants to reach the surface, corrosion protection can be achieved.

Figure 6 – Low carbon steel coupon on right exposed to polyamine.

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Excellent results have been shown in actual operating systems. Several cases will illustrate the added benefit the Polyamine can provide including added reboiler protection and the overall reduction of neutralizing amine requirement which minimizes the overall tramp amine loading to the distillation tower.

FIELD APPLICATIONS

We have historically presented laboratory data as well as results from our in-house, low pressure boiler system in prior NACE papers. However, to help illustrate the actual results that the refineries/chemical plants are experiencing, several case study summaries will be reviewed.

Case #1 A chemical plant in the southeast United States was struggling with high alkalinity make-up producing very high levels of CO2 in their 200 psig steam and returning almost no condensate (no amine recycle). Consequently, it was proving economically challenging to provide enough neutralizing amine to meet the stoichiometric demand and raise the pH to an appropriate level for the mixed metallurgy system. To help meet the desired performance and economic goals, a neutralizing amine/polyamine blended product was introduced to the DA storage, where the neutralizer “only” product was injected prior. As you can see in Figures 7a/7b, the corrosion rate of the coupons in the condensate system greatly improved.3 The dramatic performance difference mirrored the prior case study work of improved condensate protection at equal or even lower pH values, as the neutralizing amine contribution has been further reduced over time. Iron and copper levels remain very low after three years of continuous application.

Figure 7a: Mild steel coupon prior to establishing Polyamine film - Corrosion Rate – 8.9 MPY

Figure 7b: Corrosion Coupons following Polyamine treatment – Mild Steel Corrosion Rate - <0.1 MPY

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Case #2

This particular refinery was struggling with high tramp ammonia/amines in their crude and coker unit operations. Additionally, the make-up to the boiler system was softened water and contributed >20 ppm of CO2 to the steam requiring significant neutralizing amine to achieve the steam condensate pH level of >9.0 in the return condensate. Consequently, the refiner was very interested in minimizing potential issues with tramp amine contribution from their stripping steam and in lowering steam condensate treatment costs. To address both concerns, the traditional refinery neutralizing amine blended product consisting of methoxyproplyamine (MOPA) and cyclohexylamine (cyclo) was replaced with a blend consisting of mostly low-salting amines and polyamine. The specific product formulation was designed by using a combination of process modeling and utility modeling programs. The modeling programs were then used to simulate the impact of the chosen chemistry in the systems before bringing on-site. Prior to the application, an analysis of key system treatment and corrosion data was conducted on both the water and process chemistry to establish a baseline of the current performance. Upon implementation of the program, the amine-chloride salting potential was improved by removing nearly all of the higher salt point amines from the boiler steam treatment. Routine iron and pH testing of the steam condensate was being conducted to ensure corrosion metrics were being met. This included on-site iron testing and off-site using acid digested inductively coupled plasma (ICP) to get a more accurate total iron. After achieving several weeks of good results, the low-salt/polyamine feedrate was decreased, further reducing the overall amine contribution from the stripping steam while directionally improving the economics around the treatment chemistry. Decreasing the product feedrate would naturally lower the system pH and place more of the corrosion protection work on the polyamine. This included carrying a lower pH at some critical, non-vented reboilers in the system. After several more weeks of analysis, the more accurate ICP off-site iron data showed a dramatic improvement as shown in Figure 8. Four of the five samples in the system, including a non-vented reboiler, showed less than detectable iron and copper levels.4

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Figure 8: Continued improvement with the Low-Salt and Polyamine.

Important to note that another reboiler had very low iron (<2 ppb per ICP) and system pH levels were about 1.0-1.5 lower than with standard treatment

Case #3

A European refinery was having an issue with severe corrosion of reboilers/exchangers on a desulfurization unit that was receiving steam with a pH of less than 6. As a result of the corrosion, they were having to replace exchanger bundles about every 18 months. Traditional neutralizing amine treatment would have required very high feedrates and was considered uneconomical to meet the stoichiometric requirement. As a result, a polyamine/neutralizing amine blend was applied at about 10% of the theoretical “neutralizing amine blend only” feedrate. Almost immediately after initiating the chemistry, the measured total iron levels at the reboiler dropped significantly. Table 2 shows the dramatic difference in iron levels after initiating the polyamine chemistry.

Table 2: Iron levels before and after polyamine addition

Reboiler Total Iron prior to Polyamine-Amine

Reboiler Total Iron after Polyamine-Amine

>500 ppb <50 ppb More importantly, during the last scheduled maintenance on one of the reboilers, the refinery was set to replace the bundle per their normal schedule but upon inspection, determined no bundle replacement was needed because of the improved corrosion control.

Case #4

A large refinery utilizing mostly softened water for their refinery utility and waste boilers was looking to optimize their condensate corrosion control. This particular plant had suffered major corrosion issues and subsequent problems in the past as a result of no treatment addition. To help mitigate corrosion, they began feeding a highly efficient neutralizing amine package to achieve a pH of slightly above 7 (neutral pH) but areas of the system were still showing iron levels higher than desired (>0.050 ppm) for the operating pressure of their boiler systems. The complexity and expansive nature of this particular steam condensate system made increasing the pH to proper levels for the mixed metallurgy (8.8-9.2)

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system challenging and costly. In addition, adding more amine to the system could add risk to the operation of the crude atmospheric tower where salting potential would be increased. To help mitigate water and process side corrosion concerns, a low-salting neutralizing amine/polyamine replaced the current neutralizing amine program. Similar to the other cases, the modeling allowed for the appropriate selection and application of the low-salt/polyamine chemistry before utilizing at the refinery. Upon initiation of the chemistry, the refinery condensate iron levels improved considerably. As shown in Figure 9, the iron levels went from an average of 113 ppb to about 21 ppb.

Figure 9: Return condensate iron reduction with polyamine

Figure 10 shows the impact of the change to a low-salting steam amine at the crude unit atmospheric distillation tower. The risk of corrosive amine-chloride salts forming in the tower was dramatically reduced.

Figure 10: Low-salt blend improving salt point in atmospheric tower

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Case #5/#6 As mentioned prior, reboiler protection is of particular concern in many refineries. Reboilers use steam as heat source at the bottom of a distillation tower to improve distillation. Many times this steam can be very high in CO2 because they use low pressure flashed steam from condensate. Although not designed to maintain a liquid level of condensate, the reboiler operation is dictated by process flow and temperature demands and many times does not have adequate control to prevent flooding. Consequently, heavy carbonic acid attack can occur at the liquid level. As a mechanical improvement, the operator will often try to vent the reboiler at the correct location (condensate liquid level) to remove the CO2. Additionally, many will incorporate a satellite amine treatment (neutralizer, filmer or metal passivator) to help provide protection. Correct placement of venting can be challenging depending on exchanger design and operation. Satellite amine treatment can be cumbersome and expensive but often necessary to avoid costly exchanger replacement and unwanted downtime. Cases 5 and 6 illustrate the positive impact of the polyamine on reboiler corrosion control. Case #5 This refiner was using boiler feedwater made up from high alkalinity softened water producing elevated levels of CO2 in the steam. The high CO2 levels would be compounded in a reboiler using low pressure flashed steam. Additionally, issues with steam amine impacting the crude tower were common because of the type of amine being used and amount of neutralizing amine required. This particular refinery was already using older filmer technology in the form of ODA at some locations. As shown below in Figure 11, upon initiation of the low-salt polyamine blend, reboiler corrosion dropped by a factor of three. Additionally, the amount of satellite amines treatments at this refinery has been reduced from five to one. Most importantly, the neutralizing amines with the propensity to form salts, has been nearly eliminated.

Figure 11: Improved reboiler protection

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Case #6 A refinery providing high quality boiler feedwater (multi-stage RO) was looking for added protection in one of the low pressure reboilers. Although the refiner had modified their venting practices, elevated iron still was a concern. After the initiation of the low-salting/Polyamine blend, the iron dropped to non-detectable levels as shown in Figure 12.

Figure 12: Improved reboiler protection

This refiner also had historical issues in their economizer because that had been attributed in part to two-phase FAC. Prior to the change to the low-salting/polyamine treatment, a solid alkali in the form of sodium hydroxide (caustic) had to be added. After initiation of the polyamine treatment, the iron levels dropped from about 10-20 ppb to non-detectable at 0.7 pH units lower without the need for caustic. Once again, by changing to the low-salting neutralizer blend, the profile in the crude unit atmospheric tower improved dramatically. In the normal range of overhead chlorides, the salt point was lowered 30-50 F, keeping the salt point well below the tower top temperature and even the dew point.

CONCLUSION

Refineries must be able to balance day-to-day profitability and long-term reliability in their operation. Advanced technology in chemistry and application models have shown considerable benefits to the refiners in helping make their desired production targets and control their chemical treatment costs while improving the integrity of their process units and their boiler/steam systems. The combination of low-salting amines and polyamine has shown remarkable success in meeting these goals. Several examples were provided where boiler feedwater/condensate protection has been greatly enhanced while minimizing amine-chloride salt deposition in their process through proper application of the technology. Often these systems are able to reduce overall amine usage by using the polyamine filmer to provide corrosion control protection at lower system pH levels. Process and utility modeling has proved essential in applying the new technology and maximizing refinery performance and economics.

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REFERENCES

1. R. Crovetto, A. Rossi, E. Murtagh. “Research Evaluation of Polyamine Chemistry for Boiler Treatment: Phase Distribution and Steam Carry-over,” International Water Conference, paper no. 13 (San Antonio, TX: 2010). 2. R. Crovetto, A. Rossi, E. Murtagh. “Research Evaluation of Polyamine Chemistry for Boiler Treatment: Corrosion Protection,” CORROSION 2011, paper no. 11391 (Houston, TX: NACE, 2011), p. 177 3. Karen Person, “Novel Volatile Filming Inhibitor Treatment Program Provides Improved Corrosion Control in Industrial Boiler Systems,” CORROSION 2015, paper no. 6180 (Dallas, TX: NACE, 2015). 4. A. Rossi, G. Robinson, T. Dale, “Consider New Steam System Protection for Refineries,” Hydrocarbon Processing (March 2014): pp 55-58.

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