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Greg Harbison (Marathon Petroleum)

Entering the vapor space above an internal floating roof tank creates a set of somewhat unique safety concerns that must be addressed in a facility’s safe work procedures. The primary hazard is entry into an air atmosphere with some level of hydrocarbon vapor or toxics, and liquid hydrocarbon (gasoline for this discussion) beneath the floor, with wiper seals, pontoons, etc. creating a barrier to prevent conditions within the confined space from changing. Some of the specific areas that must be addressed prior to entering this confined space include permitting, atmospheric monitoring, PPE requirements, rescue, tank design or operating status, etc.

Permitting

A confined space work permit is required for entry into the space above an internal floating roof tank. As a best practice, our refineries require approval from a level of supervision above the normal facility permit writer. This ensures the risk associated with the entry is thoroughly reviewed with the expected benefits. Typical activities requiring entry are regulatory inspections, other non-invasive inspections, and minor cold work activities. Confined space work requires an attendant at the point of entry capable of constant communication with the entrants and rescue personnel. Additionally, it is our practice to completely isolate the tank inputs/outputs, and to shut down and lock out all mixers. This practice minimizes the potential for disturbances to the tank’s liquid contents, which could create a change to the atmosphere of the work area above. Hot work in covered, internal floating roof tanks is not allowed.

Atmospheric Monitoring

Confined space entry requires atmospheric conditions of 19.5-23.5 % oxygen, less than 10% LEL, and benzene and hydrogen sulfide levels below the permissible exposure limit. As a best practice, respiratory protection in the form of a supplied air respirator is used. Additionally, the confined space entry attendant is also required to utilize this level of respiratory protection. Continuous monitoring for % LEL and oxygen level in the work area of the confined space is also a best practice, particularly near seals, pontoons, or other roof penetrations where hydrocarbon vapors could escape to the work area above. In some cases, mechanical ventilation may also be required. We use air or steam driven equipment to minimize the potential for ignition sources.

Rescue

A rescue team is always required to be available during confined space entry work. Best practices in this area include the entrant’s use of full body harnesses and lifelines, avoiding entanglement hazards when in the confined space, the availability of a winch or other rescue device, and the rescue team is stationed at the tank.

Tank Design or Condition

Good ventilation is best accomplished when the vertical space between the floating roof and tank fixed roof is minimized. Our experience is to limit the distance from the floating roof to the fixed roof to ten feet maximum, with less being preferred. It is also our practice to prohibit entering onto a covered floater made of fiberglass, aluminum, plastic or similar materials as the condition of the roof is difficult to ascertain. For roofs made of steel, the inspection and service history of the tank should be reviewed to identify any known areas of concern to avoid. Additionally, entrants are not allowed to descend down to a floating roof that is resting on its legs unless the space beneath the roof has been ventilated and atmospheric testing has been completed and is acceptable. Likewise, the entrance is prohibited if the roof has product on it.

Two final notes are:

1. It is our practice to prohibit confined space entry during lightning storms.

2. For additional details, we recommend a review of API Publication 2026 “Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service”.

John Clower (Chevron)

Best practice for vapor space entry is to remove the IFR tank from service in preparation for normal API 653 inspections. CHEVRON will not inspect the vapor space during normal operation of IFR tanks. Decommissioning steps for API 653 inspections include: removal of tank contents, cutter and water washes to remove all sludge, isolation, and preparation for confined space entry.

Alec Klinghoffer (Coffeyville Resources)

Although this list is not “all-inclusive”, here are some general recommended practices when chemical cleaning and/or neutralizing towers and vessels. First, there needs to be a single point of contact for the chemical cleaning vendor. This person is responsible for the planning, preparation and execution of the chemical cleaning process. Prior to cleaning, P&ID’s need to be marked up to identify all injection points, steam and chemical flows and even line ups for the chemical cleaning. In addition, all points should be marked with robust tags so that there is continuity between shifts if the cleaning is going to last longer than 12 hours. The chemistry of the system should be discussed in depth with the vendor to ensure the chemical is compatible with the process stream for cleaning. From personal experience, it is very important to fabricate all piping necessary for the job weeks in advance to save any last-minute confusion. One item that might get overlooked is to make sure any and all environmental issues are addressed before the actual cleaning takes place. Any additional environmental waste permitting should be done in advance but typically, the current chemicals used for cleaning are “environmentally” friendly. It is still a good idea to check with environmental before any cleaning is done and discharge to the wastewater system.

 Conditions that trigger the need to chemically clean a tower include the service of the vessel. For example, vessels/towers in HF service (HF alkylation) need neutralized before any work is done on that vessel. A vessel where there might be suspected highly pyrophoric material might be an excellent candidate for chemical cleaning. One condition that would trigger the need for chemical cleaning is time. Towers and vessels typically clean up with long periods of steaming but in the current market, time can be saved when equipment is chemically cleaned. Again, there are a lot of instances where chemical cleaning can save multiple shifts in a shutdown scenario. Finally, vessels and towers may need to be chemically treated before a startup to ensure the service is clean to improve reliability and long operational duration. This is especially true for cooling towers and boilers.

Greg Harbison (Marathon Petroleum)

All of our refineries utilize cross functional Area Teams to manage the daily operation and maintenance of the facility. A sub-set of our Area Teams (Operations, Maintenance, Safety, Inspection, and Technical Service) reviews shutdown and maintenance work scopes and discusses which towers and exchangers will be opened and the type of work that will be performed (Hot Work, Cold Work, Entry, etc.). Based on this review, the equipment metallurgy and type of deposits expected are determined from engineering judgment and past experience. The Technical Service process engineer will then consult with the refinery laboratory chemists, outside chemical treatment vendors, and our Corporate Process Technologists to determine the appropriate treatment plan. A treatment guideline/procedure is subsequently issued.

There are numerous conditions that can trigger the need for chemical treatment to safely remove a potentially hazardous deposit, condition equipment for safe entry, or help ensure future safe and reliable operation.

Reliability

1.The neutralization of chlorides in austenitic stainless-steel services prior to exposing to air (oxygen) helps prevent future failures due to stress cracking and corrosion. For clean services, washing with a soda ash solution and then passivating with a solution of sodium nitrite is often a successful treatment. In fouling services like naphtha Hydrotreater feed/effluent exchangers, we will either acidize and neutralize or potassium permanganate (KMnO4) clean and neutralize the exchangers prior to exposing to air (oxygen). One cautionary note when using potassium permanganate is that it is a mild oxidizer, and free oil in the system should be absolutely avoided.

2.We take special precautions with titanium bundles. We will have an argon tube trailer on the job site to use in the event we have a titanium metal fire. One of our refineries experienced a fire several years ago on a set of titanium bundles. Nitrogen and steam/water should not be used to put out a hot titanium metal fire (nitrogen can react exothermically with the hot titanium, and water can react with the hot metal and form hydrogen gas). Thus, only Class D extinguishers and extinguishing agents can be used. Each refinery should have a plan in place (and review prior to each shutdown) to prevent a titanium fire, and how to extinguish a titanium fire.

 Safety

1.Sulfidic caustic solutions are treated by utilizing a potassium permanganate solution to prevent the liberation of toxic hydrogen sulfide (H2S). The permanganate treatment converts the hydrogen sulfide (H2S) to sulfate (SO4) and converts the iron sulfide to iron oxide.

2.Refinery sour water tanks are typically circulated back through the SWS tower to decrease the hydrogen sulfide (H2S) and ammonia concentration. The remaining solution is permanganate treated to convert the hydrogen sulfide (H2S) to sulfate (SO4) and convert the iron sulfide to iron oxide.

3.Pyrophoric material is neutralized, handled inertly, or kept wetted while the possibility of exposure to air (oxygen) exists. Iron Sulfide deposits can be present in any sour service equipment, and the hazards of combustion and toxic gas (sulfur dioxide - SO2) should be considered while developing any maintenance plan. Particular care should be taken when iron sulfide may be present in a packed vessel. Our practice is to ensure the packing remains wetted until it is either removed or the equipment is returned to service.

4.Steam, degassing chemicals, and mechanical ventilation are normally used for benzene and LEL reduction. Both steam purging and steam purging with degassing chemicals are utilized to breakup deposits and LEL free process equipment prior to maintenance work. Where demister pads or coalescing pads are present, removal is sometimes required to remove the contaminants.

5. HF Alkylation Units can be cleaned in a number of ways: 1) vapor phase (ammonia) or liquid phase neutralization, 2) acidizing and neutralization (we have experience with Hydrochloric Acid (HCl) and Citric Acid), and 3) utilizing a chelating agent.

Greg Harbison (Marathon Petroleum)

Background/Regulatory Requirements:

Since the inception of the Clean Air Act of 1955 and multiple amendments through 1990, Leak Detection and Repair or LDAR regulations have been a part of air pollution control. Today’s LDAR programs are governed by Federal and State regulations and agreed orders (consent decrees) that provide the control of fugitive emission leaks from process equipment by requiring equipment inspections and leaking equipment repair. As such, the specific requirements can vary company to company or even between refineries operating in different states within the same company. Marathon complies with these regulations.

Equipment Inspections

Components that are LDAR applicable can vary by type and inspection or monitoring frequency. Generally, LDAR components consist of valves, pumps and compressors that are monitored on a quarterly basis. Monitoring requirements can be more stringent for units built or modified post November 2006 and can apply to flanges, connectors, fittings, hatches, and agitators (to name a

few). Process stream speciation determines the applicable regulatory requirements for streams. The typical streams requiring the most rigorous application of LDAR regulations include:

1. gas/vapor streams that are typically > 10% ethane and heavier,

2. light liquid streams are typically heavy naphtha or kerosene depending on specific stream properties, and

3. process streams containing greater than 5% hazardous air pollutants (benzene, methanol, toluene, etc.)

These monitoring requirements can be more or less frequent and have different leak definitions based on different applicable regulations. A leak definition is the threshold in parts per million that a component must reach to be considered leaking. LDAR monitoring is outlined in EPA Method 21, which states that a toxic vapor analyzer (TVA) must be used to assess total volatile organic compound (VOC) leaks from LDAR components. As LDAR regulations become stricter, the leak definitions are increasingly being lowered. With every change in regulation, the LDAR program becomes more challenging to manage since most facilities are required to stay below a facility wide leak percentage for leaking equipment (typically 2%). Thus, a rigorous and well-structured leak repair and maintenance portion of the LDAR program is vital to minimize emissions and maintain compliance.

Program Oversight

A practical LDAR program encompasses multiple people spread across many different job functions. Overall, it is our experience that a successful LDAR program can be successfully managed if several critical items are in place. These include dedicated personnel, a robust software database, good overall management system, well defined roles and responsibilities, and a comprehensive auditing system. At our refineries, it is typically the responsibility of the facility Environmental LDAR Coordinator (HES Professional) to manage and oversee all aspects of the LDAR program. We also use a contract company to conduct the emissions monitoring, and another contract company to make the initial leak repairs on valves (typically injection of a sealant into the valve packing area). Other LDAR applicable components such as motor operated valves (MOV’s), control valves, pumps and compressors are repaired when leaking by qualified individuals within the facility Maintenance Department. The requirements for completing the repairs are often sensitive to equipment and process functionality.

The LDAR Coordinator should have daily communication with the LDAR Monitoring Contractor to go over every open leak Work Order. This information is reviewed and an updated list of all leaks within the facility is given to the Contractor and facility Maintenance Department every day.

Overall, the regulations are complex and can generate an overwhelming amount of information based on the size of the facility and how many leaks are found above the leak definition. A large refinery could have upwards of 70,000 LDAR components governed by state and federal regulations as well as additional requirements from agreed orders. It is imperative to have a functional LDAR database that manages this information. The database should be capable of scheduling all monitoring and repair dates based on applicable regulations for the facility. The progress of the monitoring schedule needs to be easily accessible for all parties involved.

Alec Klinghoffer (Coffeyville Resources)

The three main VOC treating systems for small scale truck loading are vapor combustion system, flare gas recovery unit, and an adsorption/absorption vapor recovery system.

The simplest system is the vapor combustion system. In this system, the vapors flow through a vapor shutdown valve and detonation arrestor and enter a combustor. The vapors are ignited by a pilot and the assist air blower provides some combustion air and mixing energy to ensure smokeless combustion. This system is very robust and provides very efficient combustion of the hydrocarbon vapors. It is also a very simple system mechanically so there is very little maintenance involved and is used in a lot of additional applications (such as wastewater installations).

The second type is the flare gas recovery unit. This unit consists of a knockout vessel, a liquid seal vessel and the flare itself. A flare header collects gases from various sources and as the flare header pressure reaches a set point, a liquid seal compressor starts up and begins to compress the gases. A heat exchanger is used to control the compressor discharge temperature. The compressor discharge is sent to a 3-phase separator that separates the liquid from the flare gas. This liquid is recovered and can be sold as product or used elsewhere in the refinery. The recovered fuel gas can be sent back to the refinery fuel gas system or processed as a chemical feedstock. The advantage of this system is the recovery of the gas and liquid to be re-used in the refinery. Also, there is a minimum amount of flaring since a portion of the gas can be used elsewhere in the refinery. The liquid recovery directly affects profits and minimal flaring is viewed as a better option from the point of environmental stewardship.

The third type of vapor recovery system is the adsorption/absorption vapor recovery system with a “dry” vacuum pump. This system is the most complex but probably also the most environmentally friendly system of the three presented here. The unit is equipped with 2 identical activated carbon filled adsorbers. One adsorber is always on steam while the other is being regenerated. When loading is occurring, the VRU automatically starts and sends hydrocarbon rich air to the activated carbon bed. The bed removes the hydrocarbon through adsorption and vents air with a minimal amount of hydrocarbon. During regeneration, the carbon bed is stripped of hydrocarbon using purge air and high vacuum. The purge air is discharge directly into an absorption column where the hydrocarbons are stripped from the air. The stripping medium in the absorber column is usually a material similar to what is being loaded at the rack (i.e., gasoline). In the absorber, the vapor is liquefied and returned back to the storage tank. A small stream of air and residual vapor is recycled back through the carbon bed for re-adsorption. The major benefit of this system is that most if not all of the hydrocarbons are recovered in this system. There is also an elimination of a flare in this system and there is reduced energy consumption because of the dry vacuum pump system. There is no compressor in this system so maintenance cost decrease and reliability increase for this configuration.

John Clower (Chevron)

Technologies used for VOC recovery are simple adsorption technologies or incineration. The technology used depends on design vapor load and emissions monitoring requirements. The Richmond Refinery employs a carbon adsorption/absorption vapor recovery system at its truck terminal. This system employs two carbon drums, one in adsorption mode and a second in regeneration or standby.

The “adsorption” flow path passes through a carbon vessel and past continuous emissions monitoring and to a vent.

The “regeneration” flow path uses high vacuum and air purge to remove adsorbed hydrocarbons from the carbon bed. The extracted hydrocarbons accumulate in a separator and are processed through an absorber for recovery of heavier hydrocarbons back to the storage tank.

Randy Peterson (STRATCO)

The type of feed is very significant for T90. Amylenes make alkylate with higher T90 in both sulfuric and HF units. Propylene generally makes lower T90 than butylene in HF units. However, with sulfuric-catalyzed technologies, propylene can increase T90 as discussed below. Diene contaminants (butadiene and pentadiene) also raise T90 for both catalysts since they form heavier alkylate. Selective hydrogenation units that remove dienes are therefore helpful in reducing T90.

In sulfuric alkylation, propylene reacted with butylene and especially amylene in the same reactor will lead to higher T90s than if they were alkylated separately. This is due to side reactions that produce heavier alkylate. Therefore, segregated feed systems where different olefins are fed to specific acid stages are beneficial. Normal olefins have lower T-90 and End Points relative to isoolefins. Thus, MTBE/TAME raffinate has lower T-90s than mixed butylenes/mixed amylenes.

For a given feed type in sulfuric alkylation, I/O ratio is the most critical process variable. The lower the I/O, the higher the T90. Low acid strengths also increase T90 so acid staging should be designed to minimize the fraction of alkylate produced at the lowest acid strength. For HF alkylation, low I/O ratio is also the most significant variable causing increased T90. Acid strengths above 90-92 wt% increase EP and T90 due to the higher activity of the catalyst and tendency for polymerization. Low acid strengths (below 87 wt%) also tend to increase T90 due to increased side reactions and increased acid carryover in the iso recycle. Excessive internal acid regeneration can raise EP/T90 as well.

Higher reactor feed nozzle ΔP and/or increased reaction zone mixing reduce T90 for both catalyst types.

John Clower (Chevron)

Alkylate T-90 can be affected by a number of different schemes, feeds, and operating variables within a Sulfuric Acid Alkylation plant. An increase in T90 signifies heavier, lower octane product, normally a result of polymer formation.

The critical operating variable to monitor for alkylate T90 is the isomer to olefin ratio. Polymerization becomes a favorable reaction at I:O ratios of less than 5:1. At these ratios, olefins can react with other olefins in the acid continuous emulsion. At Chevron we monitor alkylate endpoint to track polymerization as a check for reaction conditions.

Increased contactor temperatures can also increase polymerization, but likely would not increase T90 as the polymer would not be a large percentage of the total alkylate product.

Olefin feed segregation is one means of controlling alkylate quality and acid spending strengths. Segregation of C3 olefins allows for their operation at higher acid strength contactors. At Chevron we segregate C3/C4 olefins to high acid strength contactors and C4/C5 olefins to low acid strength contactors.

C3 olefins tend to make conjunct polymers at low acid strengths and will also form polymers with C5 olefins at low strengths. If a plant feeds less than 10% C5 olefins, an increase in that percentage will result in increased T90.

Greg Harbison (Marathon Petroleum)

Reaction temperature and isobutane to olefin (I/O) ratio are two of the most important variables we monitor for alkylate quality. Acid to hydrocarbon ratio is also an important variable and is routinely monitored for our UOP units which have a pumped acid design. For COP Units, this is not a variable that can be changed.

Randy Peterson (STRATCO)

The isobutane recycle sample can be neutralized at the sample location using a chamber filled with alumina or KOH pellets. If using a KOH chamber, it is best to add a filter downstream to filter out any fines.

Alternately, the sample may be neutralized in the lab upstream of the GC by the same method. In some refineries, KOH pellets have been added directly to sample bombs prior to sampling.

The iso recycle from the side draw of an isostripper typically contains about 1% HF. However, if the tower is refluxed and the iso recycle stream comes from the tower accumulator, the sample may contain more HF.

Greg Harbison (Marathon Petroleum) Marathon has six HFA’s. Some of our refineries neutralize the recycle isobutane lab sample with a cylinder containing solid KOH in the field at the sample station, and others complete the neutralization in the lab. Additional KOH is added to the cylinder at a predetermined timeframe via the use of a PM work order. We have not used this arrangement for on-line G.C.s. The reaction of HF with KOH will result in the formation of water. If this feed pretreatment were used for an on-line unit G.C., the water formed would create issues with the addition of a wet stream to an acidic environment. Localized corrosion at the return point to the process may occur.

Randy Peterson (STRATCO)

Oxygen is a major cause of monel denickelfication. Oxygen can enter the circuit during loading operations. Care should be taken to avoid pressuring air contained within loading pipes/hoses into the unit.

Whenever monel is overlaid on carbon steel, a “butter” layer of nickel should be laid down prior to the monel layer. This step reduces the potential of a poor quality overlay.

A corrosion problem has been reported with packed regenerators using monel rings. Due to distribution problems commonly associated with packing, portions of the packed beds run dry and hot. The monel tends to severely corrode under these conditions leaving only a copper residue.

Although packed regenerators typically work well when first commissioned, trayed regenerators tend to have less corrosion over time as the trays are kept cool by the flowing liquid. Therefore, fixed valve trays are recommended in this service.

Randy Peterson (STRATCO)

Fouling in the DIB column is almost always caused by salt deposits. These salts are typically sodium sulfate and sodium sulfite but can also contain calcium or magnesium if the effluent treating water is not demineralized. If these water-soluble salts are present in the DIB feed, the water will evaporate once inside the column leaving the solids behind. The salt deposits are typically found on or near the feed tray.

The long-term solution is to make changes to the effluent treating system. The quickest operational change is to increase the water makeup rate to the system to dilute the aqueous salt concentration. Monitor conductivity in the water effluent and maintain a level less than 5000 μmhos/cm (microSiemens/cm) to minimize salt carryover.

Properly designed and functioning water wash static mixers are very important to wash any salts out of the tower feed. A retrofit of coalescing media should be considered in all effluent treating vessels to minimize carryover of the salt-containing aqueous phase. If the unit does not have a water wash downstream of an alkaline water wash, a water wash coalescer with static mixer should be considered.

Improving the water quality with softer water can also help. However, it is important to note that some refiners have experienced foaming problems in their water washes when using water that is too soft. Mixing a little hard water with the demineralized (soft) water typically solves the problem (40-50 ppm total hardness in the makeup water is a good target).

A quick fix to improve DIB operations while running is to perform an online water wash. Although this carries some risks, several refiners have successfully restored column operations. The typical method is to add water to the column feed. In doing so, the salts fouling the feed tray are made soluble. The salts are then carried away from the feed tray and redeposited on nearby trays as the water evaporates. This is not a permanent solution as the salts typically remain in the column until washed properly off-line. It is best to add the water as close to the tower feed nozzle as possible to avoid stagnant pools of water in the feed line which can lead to corrosion in low points.

Reboiler Fouling

Reboiler fouling is almost always caused by ineffective effluent treating. If the reaction intermediate esters (typically propyl or butyl sulfates) are not decomposed within the treating system, they enter the DIB and travel down the tower. When they reach the hot reboiler, they thermally decompose releasing SO2 while the organic component fouls the reboiler tube bundle. An indication that this is happening is low pH and high iron in the DIB overhead accumulator water draw. The evolved SO2 and water forms corrosive sulfurous acid. A good target pH is 6.5 – 7.5 with less than 10 ppm iron.

To avoid reboiler fouling, an increase in the temperature of the effluent treating water wash temperatures (>120 F) may help break the esters down. Typically, new static mixers, designed specifically for immiscible fluids, are required.

Some refiners report success with online water washing of the reboiler. Either water is directly added to the reboiler hydrocarbon inlet or enough water is added to the feed so that water goes down the column to the reboiler. In many cases, the boiling water breaks up the foulant and sends it downstream. If not severely fouled, the reboiler performance is restored. Care should be taken with the resulting wash water as it will have low pH (1-2) and will contain solids. In severe cases, the tube bundle requires pulling and hydroblasting to mechanically remove the foulant.

John Clower (Chevron)

DIB fouling typically starts in the alkylation unit reaction section. As reaction conditions deteriorate with increased feed rates (higher contactor temperatures, lower I:O, higher OSV) the amount of side reactions increase.

One critical side reactant with respect to DIB fouling is neutral esters. Neutral ester removal occurs at the alkaline water wash upstream of the DIB.

Increased rates through the alkaline water wash can result in declining separation of the hydrocarbon and aqueous phases, and underperformance of the heat input in the treatment section – the outlet of the alkaline water wash must be maintained above 120 °F to decompose the neutral esters, as high as 150°F If feeding large amounts of C3 olefins. Left unchecked, these esters will decompose and foul either trays in the DIB or its reboiler.

To avoid DIB fouling where heat input is the limitation, the installation of a trim heater is appropriate. If the outlet temperature is above 120 °F and fouling still exists, a second treatment step can be added as a water coalescer downstream of the alkaline water wash. The coalescer uses fresh water to polish any dissolved solids carried from the alkaline water wash.

The column dP above the feed tray is the most immediate way to detect column fouling. This can identify fouling 6 months before column performance is negatively affected. Overall column dP may not indicate fouling with the upper trays become more loaded, and the lower trays become less loaded as salts plate out on the feed tray.

Increasing column pressure can prolong run length once fouling is detected at the expense of iC4 recovery from the DIB.

Mark Meterna (Sulzer Chemtech USA)

Distillation is essential to the alkylation unit, where efficiently working trays produce a high purity isobutane recycle stream to the reactors with minimum energy consumption. Trace sulphuric acid and acidic by-products from the alkylation reaction may cause corrosion of distillation internals and damage the capability of trays and heat exchangers.

It is easy to detect corrosion and fouling of the distillation internals and to prevent further corrosion by understanding the mechanism by which it occurs. Corrosion of these internals can be further minimized by effectively operating and monitoring the treating section directly before the distillation columns. The refiner should monitor Deisobutanizer reboiler duty, Deisobutanizer overhead accumulator water pH, and separation efficiency (overlap in product distillation). Trends in any of these items may indicate that adjustments are required to the operation of the treating section. The presence of iron in the overhead accumulator water is another indication that metal losses are occurring upstream as a result of corrosion.

The net effluent stream from the reactor section contains corrosive components such as trace free sulfuric acid, alkyl sulfates and di-alkyl sulfates. These alkyl sulfates, or esters, are reaction intermediates produced during the alkylation reaction and if not treated in the treating section will foul and corrode process equipment and distillation internals.

If the trace acid and esters are left untreated before entering the deisobutanizer, they not only cause corrosion, but the alkyl sulphates will produce solid, tar-like material in the bottom of the column and on the reboiler due to the high temperature. During the formation of the tars, SO2 is released and travels up the column to collect in the overhead system. In contact with water in the overhead, SO2 causes corrosion of the overhead system equipment and piping and also of the rectifying section distillation trays. This reduces the fractionation between isobutane and n-butane resulting in poor purity of the isobutane recycle stream to the reactors.

Another form of corrosion in the Deisobutanizer is caused by water carryover if the treating section is finished with a water treating or caustic vessel. If water or caustic is carried into the column, the feed tray can be fouled with salts which will deposit when the water evaporates.

Though there are various treating section configuration and designs, the main principles hold true for all; efficiently mix the treating agent with the net effluent to maximize the contact between the two fluids, and effectively settle the two fluids before the next process step. The net effluent stream from the reactor section contains corrosive components such as trace free sulphuric acid and reaction intermediates (esters, or alkyl sulphates and di-alkyl sulphates). With well-mixed effluent and treating fluid, the trace acid and esters can be neutralized and removed from the hydrocarbon stream. Both mixing and separation can be improved with static mixers such as Sulzer SMV static mixers which develop the optimal droplet size to improve the contact between the two fluids, while minimizing small droplets and creating the chance of an emulsion to form. An emulsion of the hydrocarbon stream and the treating fluid can be challenging to separate. Separator internals, such as Sulzer Mellaplate, can also be installed in the separator vessel to improve separation between the two fluids. Increased separation capability and efficiency reduce the risk of water or caustic carryover to the deisobutanizer and minimize the chance of corrosion and fouling. Sulzer VG AF™ Trays can also be used in the deisobutanizer to reduce the impact of fouling and accumulation on trays. Sulzer VG AF™ Trays are designed with large, fixed valves that allow vapor to still pass through the trays. They are also designed with push valve technology, which reduce accumulation on the tray deck in stagnant regions and use high performance downcomers to help reduce accumulation. Tailored design features make VG AF™ Trays less sensitive to plugging and increase the run time of fouling applications while delivering high capacity and efficiency.

Procedures for online water washes can be developed to wash away the fouling material on the lower trays as well as the tar on the reboiler but monitoring the unit and minimizing the water carryover from the treating section will help reduce the need for column water washes. Monitoring the amount of water in the overhead accumulator, and the pH and iron content of the water are good indicators of how the treating section is performing and will help reduce the amount of corrosion to the distillation equipment.