Combating naphtha reflux section corrosion mechanism and production losses in a CDU
Corrosion is one of the most important challenges that refineries face (FIG. 1).1
Corrosion is one of the most important challenges that refineries face (FIG. 1).1 Sometimes, corrosion can cause the loss of production. Managing this issue in an optimal manner can mitigate or eliminate production loss due to maintenance shutdowns.
FIG. 1. Corrosion is one of the most important challenges that refineries face.1
In refining process units, especially in the crude distillation unit (CDU), there are different kinds of corrosion. The primary corrosion problem facing the CDU is ammonium chloride and hydrochloric (HCl) acid corrosion, which is discussed in this article. Opportunities are always available to decrease or prevent these types of corrosion, either with additional investment or with operational changes.
The aim of the CDU is to remove salt and water in crude oil from the system, and to separate fuel gas, LPG, light naphtha, heavy naphtha, kerosene, light diesel, heavy diesel and atmospheric bottom fractions by taking advantage of the differences in boiling points. The separated fractions are sent to other process units in the refinery.
Crude oil fed to the unit is processed through four basic processes: preheating and desalting, atmospheric distillation and the reflux system, the naphtha splitter and debutanizer columns.
Charge pumps send the crude oil to the unit, where it is heated with the boiler feedwater to provide the desalter temperature. Then, crude oil passes through the first group of preheating exchangers and is heated with naphtha reflux, kerosene, light diesel, heavy diesel and atmospheric bottoms, respectively, to provide the optimum desalting temperature.
The crude oil mixed with washwater that is supplied to the desalter is then sent to the second group of heat exchangers after the desalting operation. The crude oil is sent from the desalter outlet and enters the second group of heat exchangers, where it is heated with kerosene reflux and atmospheric bottoms. Continuing from two branches, the crude oil enters the furnaces. The furnace outlet is charged to the atmospheric distillation column. Some heat is withdrawn from the column by reflux circulation to balance the heat loading along the column. The naphtha reflux stream heats the crude oil in the first group of heat exchangers and then cools and returns it to the column as reflux.
The main corrosion mechanisms through the naphtha reflux section are ammonium chloride and HCl corrosion (FIG. 2). HCl corrosion occurs with dew-point corrosion if there is water vapor and HCl in the environment. When the water vapor condenses, it forms liquid drops with HCl, causing the material to be exposed to a solution with a very high HCl concentration and low pH. High existing acidity means high corrosion rates. Liquid HCl may form in the heat exchanger under the salts of ammonium chloride or amine hydrochloride.
FIG. 2. The main corrosion mechanisms through the naphtha reflux section are ammonium chloride and HCl corrosion.
Ammonium chloride is an acidic salt formed because of the combination of gaseous HCl and ammonia. In the absence of water in the environment, it does not show corrosive properties; however, excessive accumulation may cause fouling problems. When the dewpoint temperature is lowered, it may form an aqueous acidic solution and cause corrosion at high rates, especially since the pH of the first water drop formed will be very low. The average ambient temperature is kept 20°C–30°C (68°F–86°F) above the condensation temperature.
To minimize the corrosion mechanisms, a corrosion inhibitor is injected into the reflux section. In terms of protection, pH values in the stream should be in the range of 6–8. If pH values are not in that range, then there can be exchanger tube leakage in the preheat train, naphtha reflux/crude oil exchanger.
If there is any tube leakage in the naphtha reflux exchanger, the kerosene product will be off-spec due to crude oil that penetrates the reflux stream. The primary cause of tube leakage is low pH (e.g., 2–3). If there are droplets of water in the naphtha reflux section, this will cause a dramatic decrease in pH and result in leakage. If liquid water droplets can be eliminated from the stream, the pH values will increase, and leakage will not occur or the leakage period will be longer than the previous operational period.
At a Tüpraş refinery, the leakage period was 6 mos–12 mos. The leakage was detected by the color of the kerosene product, with the root cause being a blockage in the exchanger group. This led to increased temperatures in the column’s overhead section, leading to heavier light ends—especially in heavy naphtha—and an increase in offgas flow from the overhead drum.
The most effective way to overcome this challenge is upgrading material. However, this option is costly. A second option is to increase the pH value of the naphtha reflux stream by increasing the column return temperature of the reflux stream.
As shown in FIGS. 3–5, naphtha reflux pH values increased with the increase in naphtha reflux return temperature. To increase the temperature of the naphtha reflux stream, the reflux flowrate was increased from 700 m³/hr to 1,000 m³/hr. After this operation, the trend of pH tends to increase from 4–5 to 7–8. As shown in FIGS. 3–5, temperature is changing pH in an effective way. From the last leakage issue, the authors’ company’s refinery heat exchangers were in operation for nearly 3–4 times longer than the previous period. This means that there were no operational upsets and no maintenance issues. This also means that refining personnel can increase unit reliability with little interventions and overcome corrosion issues with simple adjustments.
FIG. 3. Naphtha reflux flow rate, m3/hr.
FIG. 4. Naphtha reflux return, °C.
FIG. 5. Naphtha reflux pH.
Results and discussion
If the configuration of a crude oil unit has a naphtha reflux section, the primary challenges are ammonium chloride and HCl corrosion. To mitigate or eliminate corrosion-related production losses, operational changes—such as increasing the reflux stream temperature—are ideal. If the stream temperature is 20°C–30°C (68°F–86°F) higher than the condensation temperature, then the corrosion mechanism will be reduced or prevented. In Tüpraş’ case, the naphtha reflux return dewpoint value was 70°C (158°F), and the stream temperature increased by 25°C (77°F). After this operation, the pH tends to increase from 4–5 to 7–8. As a result, the possible exchanger failures were prevented, and the crude oil unit was able to stay in operation for 3–4 times longer vs. the previous operational period. This is an improvement achieved with no investment.
This article demonstrated that there are opportunities to minimize or prevent production losses, upsets, maintenance expenses and to increase operational availability and reliability via operational issues and without investments. HP
LITERATURE CITED
- American Petroleum Institute, “API 571: Corrosion and Materials,” online: https://www.api.org
The Authors
Gezer, N. - Tüpraş, Kırıkkale, Turkey
is a Process Chief for the naphtha hydrotreater, isomerization, CCR reformer, catalyst regeneration and benzene removal units at Tüpraş’ Kırıkkale refinery. She has more than 3 yr of experience in crude and vacuum distillation processing. She earned a degree in chemical engineering from Hacettepe University, Turkey.
Kahraman, K. - Tüpraş, Kırıkkale, Turkey
is a Process Superintendent for the crude/vacuum/LPG and amine treatment/sulfur recovery units at Tüpraş’ Kırıkkale refinery. He has 15 yr of refining experience in both operations and processing for several refining units. He earned a degree in chemical engineering from Middle East Technical University, Turkey.
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