Tune-up of amine system avoids costly new system

John Richert, Philip Gilbert
Saudi Aramco-Mobil Refining Co.
Yanbu, Saudi Arabia

Refinery amine-treatment systems can be tuned-up to increase reliability, lower operating costs, reduce corrosion, and increase treating capacity.

These benefits were achieved at Saudi Aramco-Mobil Refining Co.'s Yanbu, Saudi Arabia, refinery through proper filter selection, appropriate flash-drum modifications, bulk amine delivery, increased amine concentration, and increased acid-gas loading.

Ten years of declining performance in an amine unit at the refinery nearly resulted in an expensive decision to change from generic diethanol amine (DEA) to a costly and proprietary "wonder amine." In 1993, a last effort was made to see if the existing system could be improved without the wonder amine.

A tune-up of the existing refinery's amine-treating system helped the unit recover without changing amine type or any major capital expenses. The unit even performed better than expected.

System description

The amine system was originally designed to circulate 20% solution strength DEA at 2,300 gpm. These specifications supported a refinery with a feed rate of 275,000 b/d. The feed rate at the time of troubleshooting was 370,000 b/d.

No other amine type had been used at the refinery since its start-up in 1984. Original equipment included a small back-washable mechanical particulate filter and downstream a 5 cu m carbon filter. This filtering system was abandoned shortly after start-up due to reliability problems.

The amine system is typical: It includes two parallel regeneration trains, which supply eight absorbers and seven contactors in the refinery.

While the amine unit was sized for 20% DEA solution strength, process operators mistakenly believed that keeping amine strength near 17% could minimize corrosion problems. Consequently, 18% strength was held as the upper limit.

Amine was loaded into the system from heated 55-gallon drums. Solution chemistry was generally only monitored for rich/lean loading and total solution strength.

The refinery-inspection group had installed numerous corrosion probes and coupons to monitor the system. Thus, there was a well-documented corrosion-rate history for the system since start-up.

Background

Two enormous (each 50 cu m in volume) carbon filters were installed in 1988 to replace the original filter system. It was believed that sufficient carbon filtering could solve all amine system problems. The charcoal beds were expected to also perform as particulate filters. For short periods of time this was true. It was not long, however, before the entire circulating amine system was contaminated with charcoal fines.

Unfortunately, amine-system problems continued even after the start-up of the large filters. The amine solution was often black in color despite benefiting from the extra filtration capacity. As refinery crude rates were increased, performance declined dramatically. Along with this decline, corrosion rates and equipment reliability suffered as well.

A large amine-flash drum was part of the original equipment design. With an internal volume of 370 cu m, it was supposed to stop liquid hydrocarbons from entering the amine regenerators. Numerous hydrocarbon carryovers prompted several attempts to improve the internals.

Specific system problems were:

• High erosion/corrosion rates of up to 150 mils/year (mpy) in hot lean amine piping and reboiler shells. In areas not exposed to turbulent flow, corrosion rates were typically 10-15 mpy.
• Amine exchangers were fouling badly with particulates. Analyses showed carbon and iron sulfide.
• Contact with LPG by amine was ineffective, as LPG would be more contaminated out of the contactor than on entry. Consequently, the contactor was bypassed and only caustic washing of the LPG was used.
• Frequent hydrocarbon carryovers into the system resulted in contamination of the charcoal filters. The circulating hydrocarbons caused the regenerators to carryover, which upset the downstream sulfur plants on a regular basis.
• Rich/lean exchangers leaked as a result of heavy fouling and under-deposit pitting corrosion.
• Amine-addition rates were very high and created disposal problems for the large number of drums.
• Absorber upsets were frequent. Pressure drop often became a problem. The fluid-catalytic cracking unit (FCCU) gas-plant absorber fouling by polymerization of olefins and amine was exacerbated by charcoal and iron sulfide fines. This resulted in formation of black, "gunky" deposits. Unscheduled chemical cleaning was often performed with the tower on bypass.
• Lean amine air-fin coolers reached their limit at the high circulation rates, and plans were made to install several million dollars worth of exchangers for additional cooling.
• The need to circulate additional amine resulted in the need to run two lean-amine pumps instead of one. One of the pumps failed as a result of cavitation. The flow required was slightly more than one pump could deliver, but below the minimum for two.
• Persistent foaming problems resulted in amine carryover into the fuel-gas system. It was obvious that charcoal and iron sulfide fines were being carried downstream from the charcoal filters. These fines resulted in equipment fouling and contributed to foaming in absorbers. Foaming and resultant carryover caused excessive amine consumption for the plant.

In addition, the fines caused high erosion/corrosion rates.

Also during this time, the refinery was maintaining amine strength below 20%. With higher crude throughput, demands on the amine system increased. At higher circulation rates, the lean amine coolers were overloaded and lean amine ran at excessive temperatures. Recurring hydrocarbon carryover contaminated the charcoal and prevented the charcoal from suppressing foaming incidents.

Most of the problems with the amine unit were interrelated. The two leading factors considered important to initially improve system performance were filtration and flash-drum modifications.

Particulate filtration

To clean up the solution and return the charcoal beds to their intended purpose, cartridge-filter vessels were installed for particulate filtration. Charcoal is not very effective at removing particulates, but it is necessary to remove hydrocarbons and other compounds that contribute to foaming problems.

The final installed hardware included two particulate filters upstream and two downstream of the charcoal filters. Both sets were necessary to prevent contamination of the charcoal and to prevent charcoal fines from entering the circulating solution.

With this arrangement, an upstream and downstream filter should always be in service. A diagram of the amine-system and the filter configuration is shown in Fig. 1 [175,843 bytes].

The installation of the upstream particulate filters eliminated the need for the existing charcoal filters. The charcoal filters were switched from series to parallel operation with one filter in standby. This switch minimized pressure drop and assured that a fresh vessel full of charcoal was available for changeover. Normal change-out is 6-9 months or if a large hydrocarbon carryover occurs.

As a result of the general remoteness of the refinery in Saudi Arabia, about 2,000 cartridge elements for the new particulate filters were stored in inventory. Each filter requires 132 cartridges.

These filters were sized for 50% of the amine flow. The filters have DP cells with control room indicators.

There is no rigorous method to define what filtration capacity is required for a given flow rate.

Requests for bids with identical requirements were sent to five different vendors. The resulting bids offered dramatically different filter-vessel sizes. In addition, all vendors had disclaimers on filtering capacity being related to material being filtered.

Obviously, all of the filters would have worked; however, it was apparent that some would have only lasted a few hours before an unacceptable pressure drop arose.

The capital costs for large filters must be balanced with increased maintenance costs for small filters. In this case, Saudi Aramco-Mobil installed large vessels that use replaceable cartridge-filter elements.

The following benefits were attributed to oversized filter vessels:

• Greater dirt-holding capacity as a result of lower flow per cartridge element. More dirt is collected before pressure drop becomes excessive at constant flow.
• Ability to quickly handle upsets by filtering a larger proportion of the circulating amine.
• Lower maintenance expenses.
• Additional capacity for future filtering requirements.

Both 100µ and 10µ filter elements were tried. No detectable difference in amine appearance has been observed between the use of the two elements. It is believed that this is due to the low velocity in the filters, which results in superior particulate removal. Since the filters were installed, the amine normally runs bright and clear.

Filter elements are replaced when the pressure drop across a vessel approaches 2 bar (about 30 psi) The upstream filters catch most of the dirt and are changed most often. Upstream filter-element replacement started out once every several days until the circulating solution cleared. Normal replacement occurs after several months of operation, based on pressure drop.

Once the filtration system was upgraded, there was an immediate improvement in the appearance of the amine. In addition, corrosion rates started to fall (Fig. 2 [56,985 bytes]).

Flash-drum modifications

Even after the new filter installations, hydrocarbon upsets continued to cause havoc with the system, particularly the regenerators. Obviously, the amine-flash drum was not doing its job effectively as the drained hydrocarbon contained more amine than oil.

A perforated vertical distributor pipe that approached the bottom of the vessel had been installed in previous attempts to improve the internal distributor in the flash drum.

The annular space between the two concentric pipes was sealed at the top. Holes in the sleeve were designed to allow escape of amine and vapor.

Inspection of the vessel clearly showed that the previous modifications caused vapor to disengage below the surface of the amine. The rising gas caused turbulence at the surface and sloshed the amine and hydrocarbon over the weir. Another shortfall was that the vertical distributor pipe was located within 20 cm of the hydrocarbon overflow weir.

Modifications to the drum were constrained by a 1-week window during a refinery turnaround. Time dictated that the improved design accommodate all new material through a manway and require no welding on the drum shell.

The following four changes were made:

1. The top annular space was opened to allow gases to quickly exit from the incoming liquid.
2. A splash baffle was installed close to the distributor to direct the gases and any entrained liquid away from the overflow weir.

In the previous design, the engineers failed to recognize that even in the most serious upset, the amount of hydrocarbon is small compared to the volume of the flash drum and the amount of amine circulated. Thus, there is no reason to have the overflow weir stretching along the entire width of the drum for hydrocarbons. Saudi Aramco-Mobil acknowledged this by installing a splash baffle that allowed a small overflow near the ends of the weir.

1. The bottom 0.75 m of the sleeve was opened up to allow as much amine as possible to exit the sleeve from the bottom.
2. The company also added baffle wings to the bottom of the distributor to direct the flow in a quasi-radial direction. The intent was to promote more flow through the main disengaging zone as the amine moved towards the amine-overflow weir. It is hard to quantify the effectiveness of these baffle wings, but they were added to provide some benefit at a small cost.

Details of the flash-drum modifications are shown in Fig. 3 [192,477 bytes].

The positive effect of these modifications was dramatic upon start-up of the amine unit. The hydrocarbon draw was now primarily hydrocarbon with only a small amount of amine.

Reduced erosion and amine losses

The effects of the improved filtration and flash drum modifications were spectacular. The amine was now clear almost all of the time and hydrocarbon upsets were greatly reduced. One of the first apparent benefits of the new operation was the drop in corrosion rates in hot lean streams. Corrosion rates dropped from 150 mpy in turbulent areas to 10-15 mpy.

Amine regenerator and sulfur-recovery unit upsets became rare. Fresh amine makeup dropped by over 40% to 189 tons from 330 tons the year before the tune-up. The improvements in the system encouraged the company to make further changes. These changes included

• Bulk delivery of amine
• Increased amine concentration without side effects
• Increased acid-gas loading.

Bulk delivery

To maintain a low amine cost with reduced amine usage, it was decided to switch to bulk amine delivery. Benefits of bulk delivery are:

• Elimination of steaming and handling of drums
• Elimination of drum disposal
• Minimization of oxygen entering the system and thus reduction of the resultant formation of heat stable salts (HSS)
• Elimination of amine loss from remains in the bottom of drums.

Delivered amine was specified to be 10% water and 90% amine. This specification was used to prevent solidification of amine and the corresponding need for steam heating.

Increased amine concentration

The original process design called for a maximum DEA solution strength of 20%. At higher refinery throughputs, higher circulation rates at a constant loading were required. This, in turn, meant that lean amine coolers could not adequately cool the hot lean amine, particularly in the summer. Inadequate cooling of amine reduced absorption efficiency.

The refinery purchased two amine-circulation pumps to maintain adequate flow. Unfortunately, the flow per pump was below minimum design and recirculation was causing pump reliability problems. To alleviate these problems, amine strength was gradually increased over a 2-year period to a current strength of 27-28%.

Concerns were expressed over the effect on corrosion of increasing amine strength, since company guidelines recommended a maximum strength of 25%. Within industry practice however, as reflected in API Recommended Practice RP 945, concentrations up to 40% have been used. Obviously, as units are pushed harder, process and corrosion monitoring become even more important.

The primary factors that determine amine-solution corrosivity, in decreasing order of impact, are acid-gas type and ratio, amine-degradation products including HSS, temperature, and finally amine type and concentration.

Amine type is important in that degradation products and HSS (and what to do about them) are in part related to the amine used and the contaminants in the hydrocarbon feed streams to be treated. Other contaminants that may also impact corrosion rates are oxygen and chloride ions.

As the amine concentration was slowly raised in the refinery, corrosion rates never increased. Another side benefit of higher amine strength not often recognized is higher solution viscosity, which directionally lowers foaming tendencies.

Increased acid-gas loading

Increased refinery throughput resulted in capacity problems in the high-pressure absorber in the dieselhydrotreaters. To prevent flooding in this absorber, amine circulation was reduced to that tower. By doing this, the refinery increased its rich-amine loading. Loadings, essentially all from H2S, were increased from 0.35 mole acid gas/1.0 mole of amine to 0.50 mole acid gas/1.0 mole of amine. No increase in corrosion was detected.

It should be noted that treating only H2S-containing streams is considered less corrosive than CO₂-containing or mixed-gas streams.

Degradation products

All of the improvements in the system led to a situation that often occurs when amine losses are minimized. Analysis of the amine showed a buildup of HSS. HSS and other degradation products in amine solutions cause corrosion and a loss of system treating capacity.

HSS are formed by the combination of amine with acids. The salts are sufficiently strong so that they do not thermally decompose in the regenerator. The overall effect is that HSS can increase corrosion rates by raising the effective loading on the remaining "active" amine.

Considering that there is equilibrium between these stronger acids, the amine, and HSS, it has been shown that unreacted acids increase corrosion rates.^{1 2} As amine-solution pH is lowered, corrosion rates are directionally increased.

Acids that cause HSS problems have several sources. Cracking units (for example, cokers and FCCUs) contribute the greatest amounts of acid contaminants, like formic and acetic acids and hydrogen cyanide (HCN). A common industry guideline has been to keep HSS at a level below 10% of the amine concentration. The system was exceeding that amount.

An oxygen analysis of the circulating amine streams was performed to determine whether it was contributing to amine-solution deterioration. Trace oxygen can have a strong influence on increasing corrosion rates, both by acting as corrosive agent and by contributing to amine degradation. Trace oxygen can react with amine to form carboxylic acids like oxalic or with H₂S to form thiosulfate.

Oxygen enters amine streams primarily from unblanketed tanks and sumps. Operating units like cokers and FCCUs can contribute trace oxygen, whereas larger amounts can come from tail-gas treating or vapor recovery and treatment systems.

A survey of individual circulating streams showed no oxygen contamination in the amine system. The system includes nitrogen-blanketed tanks and sumps. Proper gas blanketing has long been recognized as a means to help reduce corrosion, HSS, and degradation-product buildup.

Amine-degradation products most often arise from thermal reasons (for example, overheating amine in the reboiler) or from side reactions involving CO₂.

These compounds, among them HEO (hydroxyethyloxazolidone), THEED (tris-hydroxyethylenediamine) and BHEP (bis-hydroxyethylenepiperizine), are only considered mildly corrosive to carbon steel in DEA. They do, however, reduce active amine available and raise effective loading similar to HSS. At high levels, degradation products can also reduce overall system capacity.

HSS control

Units operating with a primary amine like MEA can keep HSS and degradation products under control by the proper use of a reclaimer. DEA, however, is not easily reclaimed by traditional means and purging. Instead, ion exchange or electrodialysis is sometimes used.

As a result of the high costs of purging a large system such as that at Saudi Aramco-Mobil's refinery and general lack of local ion exchange services, the simple approach to reduce HSS was taken. Saudi Aramco-Mobil added a strong base to the circulating amine to reduce HSS and free up bound amine.

At the same time, the company raised the solution pH, which also directionally lowers corrosion rates.

It should be noted that caustic (that is, sodium hydroxide, NaOH) is the preferred choice rather than soda ash (sodium carbonate) or potassium carbonate because of a greater risk of fouling with the latter two.

Within the industry, there are still debates over the merits of strong base additions, and the authors recognize they are not suitable for all systems. Properly dosed and monitored however, caustic can be a valuable tool.

The normal concerns of the use of caustic include the buildup of sodium salts in the circulating amine. Some misinformation even exists concerning a potential for increased risk of stress corrosion cracking. A National Association of Corrosion Engineers (NACE) survey showed no correlation between strong base addition and incidents of cracking.³

Experience has shown that caustic additions are required on about a quarterly basis. Caustic is only added when the HSS concentration approaches 3% of the total solution, and a lower bound is targeted such that only enough caustic is added to reduce the HSS to 1% of the total solution.

Sodium monitoring has shown that normal amine losses have been sufficient to maintain total salts in the system to a comfortable level. Sodium levels have typically ranged between 5,000 and 7,000 ppm.

While never yet met, an upper limit for sodium has been set at 30,000 ppm for future planning. If an unacceptable increase is found, one possible option considered is a salt-removal service offered by the amine vendor.

Refinery records indicate that caustic additions reduced the corrosion rates to about 5 mpy in the hot lean-amine circuits.

Results

Using judgment and good industry practice, Saudi Aramco-Mobil's Yanbu refinery avoided the use of proprietary wonder amines. Specific and documented improvements from the tune-up include:

• Lower corrosion rates
• Lower fouling in amine exchangers
• Lower fresh-amine additions to the system and elimination of drum handling
• Lower circulation requirements and operating only a single lean-amine pump
• Lower frequency of hydrocarbon carryover
• Rare occurrence of amine foaming and carryover to the fuel gas system
• Stable regenerator operation and no more sulfur-plant upsets
• Elimination of capital expenditure for lean-amine coolers as existing coolers are now able to handle the load, even in the hot summer season
• LPG can now be treated with amine and is no longer contaminated by dirty amine.

Acknowledgments

The authors would like to express appreciation to Mobil Oil and Paul Guercio for support and permission to publish this article and to Mohammed Al-Fozan for supporting us in our efforts to bring about the changes discussed.

References

1. Liu, Dean, Bosen, "Neutralization Technology to Reduce Corrosion from Heat Stable Salts," NACE Corrosion 1995, Orlando.
2. Asperger, Liu, Dean, AIChE Spring Meeting 1995, Houston.
3. Richert, Bagdasarian, Shargay, "Stress Corrosion Cracking of carbon Steel in Amine Systems," Materials Performance, January 1988.

The Authors