mitigation of heat exchanger fouling

Mitigation of heat exchanger fouling

The naphtha hydrotreater (NHT) feed-effluent exchangers at a US refin-

ery were experiencing severe fouling. The heat exchanger fouling was limiting run length. As the preheat exchangers fouled, the heater inlet temper-ature 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 investi-gation was conducted to develop a clear understanding of the fouling source. This analysis resulted in the devel-opment of an antifoulant additive treatment programme that has significantly reduced the rate of fouling. The antifou-lant programme has extended cycle length and reduced main-tenance 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 hydrodesulphuri-sation (HDS) units can impact throughput, energy consump-

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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tion, and shorten catalyst life. Deposits form in the feed-efflu-ent heat exchangers and on the top of the reactor beds. The economic impact can be severe from the problems caused by fouling. Solutions include oper-ational changes, mechanical upgrades and antifoulant addi-tive treatment to control specific fouling mechanisms.1

Description of unitThis 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 mate-rial. 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

Crude and coker naphtha

Purchased naphtha

Surgedrum

Hydrogen recycle compressor

ReactorFurnace

Feedeffluent heatexchangers

SeparatorAir cooler

Minimumtemperature requirement

Figure 1 NHT unit diagram

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was required to mechanically clean the feed-effluent exchangers.

Root cause analysis steps and resultsIn 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 infor-mation were coupled together to establish the mechanisms responsible for fouling and to develop mitigation options.

System and operationsThe NHT is configured so that a combination of straight-run and coker naphthas are fed hot to the unit surge drum. Purchased naphtha supple-ments 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-cata-lytic in the presence of oxygen. The best practice for processing coker naphtha through an HDS unit is to ensure that intermedi-ate 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

naphtha to prevent two-phase flow in the fired heater. The vapourised naphtha and hydro-gen mixture is heated in the fired heater to the required reactor inlet temperature. Sulphur and nitrogen impuri-ties are converted to hydrogen sulphide and ammonia, respec-tively, 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-efflu-ent exchangers. The separator liquid is fractionated in the NHT gas plant into butane, light naphtha, reformer feed and jet fuel. Figure 1 is a sche-matic diagram of the unit.

Description of problemsA refinery configuration change altered the boiling range of the NHT feed from C5 through jet to C4 through jet. After the configuration change, the foul-

ing 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 temper-ature was increased to offset the heat transfer coefficient reduction by raising the log mean temperature difference across the feed-effluent exchangers. The reactor temper-ature increase was an effective method of managing the required minimum furnace inlet temperature, although an energy penalty was incurred for heat lost through the reac-tor effluent air cooler. As the feed-effluent exchangers contin-ued 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

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Figure 2 Heat transfer coefficient pre- and post-unit revamp


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 configura-tion 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 exchang-ers. Online water washing of the tube side of heat exchang-ers is easier and more effective than washing the shell side.

Deposit analysesVisual inspections of the heat exchangers prior to cleaning revealed that the tube side was clean, while the shell side was severely fouled. Since the refin-ery regularly water washes the tube side of the exchangers to dissolve and remove ammo-nium chloride salts, the cleanliness of the tube side was expected. The shell-side depos-its consisted primarily of hydrocarbon-based materials coupled with lesser quantities of iron sulphide.

Table 1 shows the results for the deposits obtained during the root cause investigation. The tube side was quite clean and the small amount of material obtained was found to be prima-rily iron sulphide and iron oxide — corrosion by-products that can form due to the reaction of ammonium chloride salts with the heat exchanger tubes. The shell-side deposits were mostly organic but were coupled with


some iron compounds and chlo-ride salts. The organic portion contained substantial amounts of carbon; the hydrogen-to-carbon atomic ratio revealed that the deposit was composed of degraded, partially cyclised polymeric material. There was also a significant amount of nitrogen found in the shell-side deposits. Nitrogen is commonly found in deposits from coker naphtha due to the presence of amines and pyrroles, which can take part in polymer formation.

Feedstock analysesAnalyses of HDS unit feed streams provide insight into the fouling mechanism root cause. Tests that are utilised to identify potential contributors to fouling are shown in Table 2. Several of the analyses look for

components that can take part in various polymerisation reac-tions, while other tests identify inorganic constituents such as iron sulphide that contribute to deposit formation.2

Samples of the NHT feed components were analysed to identify possible fouling precursors. The analyses summarised in Table 3 revealed that the purchased naphtha was relatively free of fouling precursors. Additionally, the handling practices of the purchased naphtha had not changed from prior cycles when minimal fouling was observed. After this review of the purchased naphtha, it was eliminated as a root cause.

The combined crude and coker naphthas contained components that lead to poly-mer formation. Olefins, as measured by the bromine number, and mercaptans are both significant fouling contrib-utors. When these components are present in the feed stream, they will produce free radical polymers. Elevated basic nitro-gen was also detected in the feed. Basic nitrogen in combi-nation with organic acids participates in condensation polymerisation.2 The organic acid content was below the detection limit, so it is unlikely

All results in wt% Tube deposit Shell deposit Carbon <1 57Hydrogen Nil 5Nitrogen Nil 4Oxygen 10 13Sodium Nil 3Sulphur 22 11Chlorine Nil 1Iron 63 4Silicon 1 TraceComposition Primarily Primarily inorganic organic

NHT deposit analyses

Table 1

Analytical test Fouling concernsBromine number, g Br/100 g OlefinsMercaptan sulphur, ppmw as S Free radical polymerisationHydrogen sulphide, ppmw as S Iron sulphide formationTotal acid number, mg KOH/g Condensation polymerisation Basic nitrogen, ppmw as N Condensation polymerisationPyrrole-indole nitrogen, ppmw N PolymerisationMetals, ppm Inorganic depositsFilterable solids, ppm Inorganic deposits

Typical HDS feed analyses

Table 2

that these nitrogen-based reac-tions were the primary cause of the high fouling rate.

Laboratory fouling testsFouling simulation studies are used to generate deposits and study the ability of chemical additives to control their forma-tion. For these feed streams, existent gums3 were used to measure the as-received poly-mer content, and thermally stressed gums were used to determine the tendency to produce additional polymer. The thermal stress test is also used to select the best-perform-ing polymer inhibitor. Table 4 shows a summary of the gum tests run on the feeds to this NHT unit.

Dispersion tests are used to measure the ability of dispersant additives to hold deposits in

solution. Samples of the gum deposits from the stress tests or deposits from the heat exchang-ers are mixed with a clear organic solvent along with vari-ous dispersant additives. The mixtures are shaken and then allowed to settle. An effective dispersant will hold the deposit in solution longer than an untreated sample. Dispersion tests were run on the polymeric material formed from the gum tests in order to identify an effec-tive product for controlling deposition of the foulant mate-rial. A dispersant specifically formulated for control of organic deposits was found to be highly effective for this application.

Treatment programmeimplementationBased on the root cause analy-sis, a Baker Hughes Lifespan

treatment programme was implemented to control polym-erisation of the reactive feeds and to disperse the organic and inorganic particulates. Polymer Inhibitor A was used to treat the coker naphtha stream before it was mixed with the straight-run naphtha. A dispersant was injected at the NHT charge pump to provide good mixing for treatment of the combined feed stream, including purchased naphtha. This combi-nation programme has provided excellent fouling inhibition capability in similar units and offers the advantage of being able to adjust the treat rates of the two components as needed.

Unit monitoring tools and trendsIn order to verify the perform-ance of the chemical treatment programme, a heat exchanger monitoring programme was utilised to compare current operation to prior cycle performance. The heat transfer coefficient for the feed-effluent heat exchanger bank was trended versus run time. Figure 3 shows the rate of decline of the exchanger heat transfer coefficient for the last three cycles. The first two cycles shown are prior to chemical treatment, while the last cycle shown is after implementation of the chemical treatment programme. During the previ-ous two untreated cycles, the heat transfer capabilities for the preheat exchangers declined at a rate of 0.11 U-coefficient units per day, resulting in a 202-day run and 0.06 U-coefficient units per day for a 404-day run. For the recent cycle with the treat-ment programme in place, the heat transfer decline was 0.01


Analytical test Purchased naphtha Combined crude and coker naphthaFilterable solids, ppmw <10 <10API Gravity 58.3 60.9Bromine number, g Br/100 g 1.4 14% Saturated H, normalised 94.5 96.2% Olefinic H, normalised 0.2 1.4% Aromatic H, normalised 5.3 2.4Mercaptan sulphur, ppmw as S 13 308H

2S, ppmw as S <1 10

Total acid number, mg KOH/g <0.05 <0.05Basic nitrogen, ppmw as N <10 23.6Pyrrole-Indole nitrogen, ppmw as N 0.2 3.7

NHT feed analyses

Table 3

Sample Test Stress Stress Results, Reduction medium temperature, ˚F (˚C) mg/100 ml % Combined naphtha Existent gums N/A N/A 11 N/ACombined naphtha Stressed Nitrogen 212 (100) 35 Polymer Inhibitor A Stressed Nitrogen 212 (100) 11 69Polymer Inhibitor B Stressed Nitrogen 212 (100) 16 54Combined naphtha Stressed Air 212 (100) 48 Polymer Inhibitor A Stressed Air 212 (100) 15 69Polymer Inhibitor B Stressed Air 212 (100) 23 52

Gum test results with combined naphtha

Table 4

U-coefficient units per day, resulting in a 662-day run. The treatment programme allowed the refinery to operate the NHT uninterrupted until the normally scheduled turnaround for catalyst replacement.

Figure 4 compares one of the heat exchanger tube bundles with and without the antifou-lant treatment programme. Both photographs are taken at the end of run prior to clean-ing. The bundle appearance and deposits from cycle 2 were consistent with degraded poly-mers coupled with iron sulphide. Clearly, there was significantly less deposit with the fouling control treatment programme in place.

ConclusionThe root cause of the increased heat exchanger fouling rate was the shift in the NHT feed qual-ity. The refinery configuration change implemented just prior to the increased heat exchanger fouling altered the NHT feed to include C4. The coker butanes and butylenes contain a high concentration of mercaptans and olefins, which lead to free radical polymerisation.

Identification of the primary cause of fouling enabled the development of an antifoulant additive treatment programme that was able to control the rate of heat exchanger fouling. This programme provided the refin-ery an economic return of over 500% by permitting the unit to run at full throughput rates, preventing unit shutdowns prior to scheduled catalyst replacements and reducing maintenance costs.

LIFESPAN is a trademark of Baker Hughes.


3 ASTM D 381, Standard Test Method for Gum Content in Fuels by Jet Evaporation.

Bruce Wright is a Senior Technical Support Engineer in Baker Hughes’s Industrial Technology department in Sugar Land, Texas, specialising in the hydrocarbon process industries. He holds a BS in chemical engineering from Rensselaer Polytechnic Institute, Troy, New York, a MBA from the University of Houston, and is a registered professional engineer in the State of Texas.Todd Hochheiser is a Refinery Optimization Manager with Valero Energy Corporation. He holds a BS degree in chemical engineering from the University of Delaware, an MBA from the University of California, and is a member of the American Institute of Chemical Engineers.

AcknowledgementsThe authors wish to extend their gratitude to Tomasa Ledesma, Baker Hughes Antifoulant Chemist, for her work in conducting the fouling studies; the analytical group at the Baker Hughes Sugar Land laboratory; and Ralph Kajdasz, Baker Hughes Account Manager, for his efforts in keeping the programme running at the refinery, and for development and calculation of the monitoring data.References1 Wright B E, The causes and control of fouling in hydrodesulphurization units — a tutorial, AIChE 2002 Spring National Meeting, 3rd International Symposium on Mechanisms and Mitigation of Fouling in Refining and Upgrading, Mar 2002.2 Medine G, Wright B E, Distillate hydrotreater fouling, AIChE 2008 Spring National Meeting, Apr 2008.


After cycle 2 After cycle 3

11 months online (untreated) 21 months online (treated)

Figure 4 Heat exchanger tube bundle prior to cleaning

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Figure 3 Heat transfer coefficient trends

mitigation of heat exchanger fouling

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