Mitigation of heat exchanger fouling
Detailed analysis of potential contributors identifies the root cause of fouling in naphtha hydrotreater feed-effluent exchangers
BRUCE WRIGHT, Baker Hughes Incorporated
TODD HOCHHEISER, Valero Energy Corporation
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The naphtha hydrotreater (NHT) feed-effluent exchangers at a US refinery were experiencing severe fouling. The heat exchanger fouling was limiting run length. As the preheat exchangers fouled, the heater inlet temperature declined, resulting in an increased potential for two-phase flow in the heater. Unit throughput was reduced to manage the minimum required heater inlet temperature.
A root cause analysis investigation was conducted to develop a clear understanding of the fouling source. This analysis resulted in the development of an antifoulant additive treatment programme that has significantly reduced the rate of fouling. The antifoulant programme has extended cycle length and reduced maintenance costs, resulting in a yearly economic return of over 500%. This article will review the root cause investigation steps, results of the treatment programme and benefits to the refinery.
Fouling in hydrodesulphurisation (HDS) units can impact throughput, energy consumption, and shorten catalyst life. Deposits form in the feed-effluent heat exchangers and on the top of the reactor beds. The economic impact can be severe from the problems caused by fouling. Solutions include operational changes, mechanical upgrades and antifoulant additive treatment to control specific fouling mechanisms.1
Description of unit
This NHT processes straight-run and coker naphthas from a combined crude/coker gas plant. The feed from the gas plant consists of butane through jet boiling range material. The NHT feed is supplemented with purchased naphtha from an intermediate storage tank. All feed streams are mixed in a surge drum and then pumped to the shell side of the feed-effluent exchangers. There are four exchangers in series. Prior to entering the first exchanger, the naphtha feed is mixed with hydrogen. The feed-effluent exchangers are designed to fully vapourise the naphtha to prevent two-phase flow in the fired heater. The vapourised naphtha and hydrogen mixture is heated in the fired heater to the required reactor inlet temperature. Sulphur and nitrogen impurities are converted to hydrogen sulphide and ammonia, respectively, in the fixed-bed catalyst reactor. The reactor effluent vapour is cooled and partially condensed in the tube side of the feed-effluent exchangers and reactor effluent air fin cooler. The liquid and vapour are separated in a product separator. The hydrogen gas from the separator is compressed and recycled to the shell-side inlet of the feed-effluent exchangers. The separator liquid is fractionated in the NHT gas plant into butane, light naphtha, reformer feed and jet fuel. Figure 1 is a schematic diagram of the unit.
Description of problems
A refinery configuration change altered the boiling range of the NHT feed from C5 through jet to C4 through jet. After the configuration change, the fouling rate of the NHT feed-effluent exchangers increased significantly. Figure 2 shows the increased fouling rate after modifying the NHT feed to include butanes and butylenes. The loss of heat transfer resulted in lower furnace inlet temperature. A low furnace inlet temperature is not sustainable due to heater fouling caused by two-phase flow. The reactor outlet temperature was increased to offset the heat transfer coefficient reduction by raising the log mean temperature difference across the feed-effluent exchangers. The reactor temperature increase was an effective method of managing the required minimum furnace inlet temperature, although an energy penalty was incurred for heat lost through the reactor effluent air cooler. As the feed-effluent exchangers continued to foul, the reactor temperature could not be further increased due to sulphur recombination at a higher reactor temperature. Unit throughput was reduced and eventually a shutdown was required to mechanically clean the feed-effluent exchangers.
Root cause analysis steps and results
In order to understand the causes of fouling in the NHT, a root cause analysis approach was employed that consisted of system and operations reviews, deposit analyses, feedstock analyses and laboratory fouling studies. These pieces of information were coupled together to establish the mechanisms responsible for fouling and to develop mitigation options.
System and operations
The NHT is configured so that a combination of straight-run and coker naphthas are fed hot to the unit surge drum. Purchased naphtha supplements the refinery feeds to keep the NHT operating at capacity. The majority of the purchased naphtha is delivered to the plant via barges and is contaminated with oxygen. The purchased naphtha is not oxygen stripped.
Coker fluids commonly contain reactive compounds, including olefins, amines and carbonyls, that can lead to polymer formation. Some of these reactions are auto-catalytic in the presence of oxygen. The best practice for processing coker naphtha through an HDS unit is to ensure that intermediate tankage is not utilised, which would provide time for polymer reactions to commence. As such, the configuration and operation of this unit should help to minimise the formation of polymeric deposits. Straight-run naphtha typically has little impact on HDS fouling unless there is a significant influx of corrosion by-products from the crude unit overhead system.
Feed to this NHT flows through the shell side of the preheat exchangers, while the reactor effluent flows through the tube side. This configuration is commonly employed in hydrotreating units because of the tendency for ammonium chloride salts to form in the reactor effluent at sublimation temperature and pressure. These salts must be removed through online water washing to maintain the heat transfer performance of the exchangers. Online water washing of the tube side of heat exchangers is easier and more effective than washing the shell side.
Visual inspections of the heat exchangers prior to cleaning revealed that the tube side was clean, while the shell side was severely fouled. Since the refinery regularly water washes the tube side of the exchangers to dissolve and remove ammonium chloride salts, the cleanliness of the tube side was expected. The shell-side deposits consisted primarily of hydrocarbon-based materials coupled with lesser quantities of iron sulphide.
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