REDESIGNED FILTERS SOLVE FOAMING, AMINE-LOSS PROBLEMS AT LOUISIANA GAS PLANT

Feb. 4, 1991
C.Richard Pauley Pauley Gas Conditioning Chattanooga, Tenn. Donald G. Langston Mobil E&P U.S. Inc. Midland, Tex. Frank C. Betts Mobil E&P U.S. Inc. Coden, Ala. Upgrading the amine filtration system at Mobil E&P U.S. Inc.'s Lowry, La., gas plant solved persistent foaming and amine-loss problems.
C.Richard Pauley
Pauley Gas Conditioning
Chattanooga, Tenn.
Donald G. Langston
Mobil E&P U.S. Inc.
Midland, Tex.
Frank C. Betts
Mobil E&P U.S. Inc.
Coden, Ala.

Upgrading the amine filtration system at Mobil E&P U.S. Inc.'s Lowry, La., gas plant solved persistent foaming and amine-loss problems.

After the amine solution became fouled with contaminants, the benefits associated with the high-efficiency formulated amine were all but lost. The problems encountered included lost gas-treating capacity, high energy consumption, and increased costs brought about by foaming, excessive amine losses, and high filter duty.

The existing filtration system was then called upon to perform a job beyond its capabilities. After careful analysis, the filtration system was upgraded.

New amine-solution filters (cartridges and carbon) were respecified and installed, and an inlet gas-liquid coalescing filter was installed ahead of the absorber and downstream of the existing inlet filter-separator.

The plant was then able to achieve the projected performance from the formulated amine.

LOWRY PROCESS

A process flow diagram for the Lowry, La., plant, is presented in Fig. 1.

The unit was originally equipped with a traditional inlet-filter separator to remove bulk liquids from the raw gas. Raw gas first entered the inlet separator then passed through a gas-to-gas heat exchanger before entering the amine contactor at about 920 psig.

In the contactor, the gas was countercurrently scrubbed by a specialty solvent (at approximately 45 wt % methyldiethanolamine, MDEA). The treated gas left the tower at Tray No. 24, was cooled by cross exchange with the inlet gas, passed through a knockout drum, and was sent downstream to further processing.

Liquids caught in the overhead separator were piped to the flash tank.

Rich amine from the bottom of the contactor entered a flash tank where the pressure was reduced to about 70 psig. A portion of the CO2 was to flash from the richamine solution, thereby reducing the heat required in the reboiler. Flash gas was sent to the fired-heater fuel system.

Semi-rich amine from the bottom of the flash tank passed through two parallel full-flow mechanical filters, each containing 286 stacked 36-in. elements. Downstream of the mechanical filters, a 10% slip stream of semi-rich amine was filtered by a carbon bed containing about 1,400 lb of a 5 x 7 mesh activated carbon.

The recombined semi-rich amine then passed through the amine cross exchanger before entering the top of the 22-tray regenerator.

In the regenerator, the pressure was further reduced to approximately 6 psig. This pressure reduction at the elevated temperature caused another CO2 flash in the top of the regenerator.

After this second flash, semi-rich amine was stripped by vapors generated in the solution reboiler. Stripping vapors were produced by reboiling lean amine with indirect heat exchange with hot oil.

Hot lean amine was pumped from the bottom of the regenerator through the other side of the amine cross exchanger, The lean amine was further cooled by an aerial cooler before entering the amine surge tank. From the bottom of the amine surge tank, the solution was pumped back to the contactor to complete the amine loop. When used, antifoamer was added at the suction of the lean-amine booster pump.

Acid gas from the regenerator overhead was cooled by an air-cooled reflux condenser. Reflux water caught in the accumulator was returned to process with the semi-rich amine solution entering the top of the regenerator.

LOWRY HISTORY

The Lowry amine unit was originally designed to treat 300 MMscfd of natural gas containing about 2.5% CO2 and 4 ppm H2S with aqueous DEA.

The process was converted to a proprietary MDEA technology in September 1985 and operated without difficulty until August 1986. That month, the plant began experiencing foaming-related problems that resulted in several emergency plant shutdowns.

In August 1986 two new wells were put into production and a gathering system line that had been out of service for several years was returned to service and pegged.

Shortly thereafter, foaming in the amine contactor caused unacceptable amine losses, high sock-filter duty, and high activated-carbon consumption.

During the second half of 1986, several measures were taken in order to solve the foaming problem. Antifoam agents were added more often to the amine solution and activated carbon was changed more frequently.

FOAMING; AMINE CONSUMPTION

By November 1986, foaming had limited the absorber's mass-transfer capability thereby reducing acid-gas pickup in the amine solution. To compensate, the amine circulation rate was increased to 750 gpm.

At the elevated circulation rate, the rich CO2 loading was significantly lower than design which eliminated any measurable flash. The flashgas analysis presented in Table 1 confirms that very little CO2 was released in the flash tank.

With little flash, the bulk of regeneration falls on the reboiler. A high circulation rate, combined with low mole/mole rich-amine loading, gives little or no energy savings over DEA (Table 2).

The actual Lowry plant heat required was 69,000 BTU/mole CO2 removed as compared to the 47,500 BTU/mole projected for the MDEA based solvent. The MDEA process heat requirement was actually higher than the original DEA design heat requirement.

Amine consumption was about three times higher than expected.

At the given operating conditions, the amine vapor content in the treated gas was calculated to be less than 2 ppm (vol). Allowing for typical entrainment losses, the total overhead amine losses should not have exceeded 0.60 lb/MMscf.

At the time, amine losses required a makeup rate of about 1,000 gal/month which equates to 1.9 lb/MMscf of gas treated. During this period, the plant was under close observations.

Attrition losses and MDEA degradation were considered insignificant.

FILTER DUTY; CARBON CONSUMPTION

Mechanical filter duty was quite high compared with previous duty. Initially 572 36-in., 10-m nominally rated sock-filter elements were replaced every 3-4 months, But in August 1986 the frequency increased to once a month. (Elements were replaced when the pressure drop through the filter reached a critical maximum.)

This equates to an increase in filter-element duty from one element per 31 MMscf of gas processed to one element per 8 MMscf of gas processed. During this period, the 10m nominal specification was changed to 2 m nominal without significant improvement in the solution quality or impact on the foaming problem.

Test runs on the filtrate from the 2-m nominal filters revealed that some particles as large as 50 m were slipping through. More stringent particle filtration was recommended, and the first set of 10-m absolute rated filters was installed on Dec. 23, 1986.

These filters had to be changed after service of only 2 weeks. Visual inspection revealed that the amine solution had improved a great deal at this time, but even with fewer particulates in the solution, the foaming problem persisted.

A 10% slip stream of amine solution was filtered through 1,400 lb of a 5 x 7 mesh activated carbon. The bed was initially recharged annually.

When the foaming problem began, activated carbon consumption increased drastically. Beginning in August 1986, the carbon was changed monthly.

New carbon reduced foaming for about 1 week, then provided little or no help. Laboratory tests presented in Fig. 2 show carbon filtration actually increased the solution's foaming tendency.

Carbon filtration apparently removes the antifoamer added by the supplier but not the contaminants which promote foaming.

Treating solution quality was visually poor, appearing yellowish which indicated the presence of liquid contaminants.

A field test with a liquid-gas coalescing filter downstream of the inlet separator indicated that the gas stream still contained a significant amount of liquids. The solution also contained a fine black solid later determined to be iron sulfide.

Trace amounts of H2S are present in the gas, creating the potential for the formation of iron sulfide. The solid passed through a 40-m absolute filter but was captured by a 10-m absolute filter.

ANALYSES, RECOMMENDATIONS

No doubt pipeline pigging and well-treating activities added liquids to the gas-gathering system that the filter-separator could not remove even after the slugs had been caught. Liquids entered the amine unit and mixed with the treating solution.

FOAMING; AMINE LOSSES

Liquid hydrocarbons and well treating fluids were determined to have caused the foaming problem in the contactor. Foaming, in turn, reduced the treating capacity of the absorber, making it necessary to increase the circulation rate in order to achieve specification gas.

According to the analytical results presented in Table 3, little or no flash was taking place in the flash tank under then current operating conditions. The rich-amine loading prior to the flash tank was about equal to the semi-rich amine loading after the flash.

Based on material-balance calculations and MDEA equilibrium data presented in Figs. 3 and 4, the circulation rate need not exceed 400 gpm to sweeten 150 MMscfd of gas at the conditions given.

At a higher circulation rate, the amine solution was not loaded to its potential, thereby eliminating any sizable CO2 flash. Based on MDEA equilibrium data, the rich amine from the absorber was only loaded to about 50% of equilibrium.

It should have been possible to load the rich solution to near equilibrium, in a non-foaming environment, by reducing the circulation rate to design conditions.

The Lowry amine unit experienced a sharp rise in amine consumption coincident with its foaming problem. The chemistry that causes the formation and stabilization of foam also causes excessive amine losses.

Foaming is the result of a change in surface chemistry. Contaminants which lower the surface tension of the solution tend to promote the formation of smaller more stable bubbles. Lowering the surface tension of a solution also promotes the formation of smaller liquid droplets, i.e., the formation of aerosols.

Aerosols, typically submicron in size, become entrained in the treated gas and are carried overhead, past conventional mist-elimination equipment. Such equipment is not designed to remove droplets much smaller than 3 m.6 The operating principles and limitations of common mist eliminators are presented in Table 4.

Mist pads commonly used in gas treating plants have very little "turndown" because effective impaction or interception depends on the velocity of the particles. A mist pad designed for 300 MMscfd of gas would most certainly be less effective at 150 MMscfd in the same tower.

Even without a foaming problem, the Lowry plant would likely have experienced higher than anticipated amine losses at reduced throughput due to the inefficiency of the mist pad at reduced throughput.

If continuous operation at reduced rates is anticipated, the mist pad should be resized for the reduced throughput or a coalescing filter should be installed downstream of the contactor to capture amine mist or aerosols for reuse.

MECHANICAL FILTERS

Increased mechanical-filter duty at the Lowry plant was another indication of a foaming problem in the making.

Very fine particulates concentrate in the surface layer of the treating solution and lower its surface tension. Removing these fine particulates destabilizes foam and reduces aerosol formation.

Unfortunately, not all mechanical filters can remove these fines. Nominally rated mechanical filters removed coarser particulates, leaving most of the fines behind as evinced by no measurable improvement occurring even after the specification had been changed from 10 m nominal to 2 m nominal.

Absolute-rated filter cartridges with a 10 m absolute rating will remove the fines that tend to stabilize foam and cause aerosol formation. In some cases mechanical filtration at a 10 m absolute rating alone will solve a foaming problem.

Consideration must be given to the construction of the filter medium as well as the rating. As a filter collects solid particles, the pressure differential will increase.

Under high pressure, many filter media will deform in order to relieve that pressure. If the pressure differential becomes constant, it indicates either the solution is clean or the filter medium is unloading fine particles.

A dimensionally unstable medium will unload fine particles and add to the foaming problem. It is essential that the medium be dimensionally stable.

In this case the substitution of 10m absolute filter cartridges alone did not solve the problem, indicating that the problem was definitely a result of liquid contaminants.

However, dimensionally stable, 10 m, absolute-rated filter cartridges will prevent fine solids from becoming a problem in the future and will extend the life of the activated carbon.

CARBON CONSUMPTION

Activated carbon works well only when the bed is properly designed and the carbon properly specified. When not correctly applied, activated-carbon filtration can actually cause a foaming problem.

The data presented in Fig. 2 illustrate this point quite clearly. Before carbon filtration, new amine solution showed no foaming tendency or foam stability. After filtration, the new amine solution exhibited an increased foaming tendency and stability.

Subsequent testing with used treating solution showed that certain types of carbon increased foaming tendency and stability while others reduced both. Based on the test results, the use of activated carbon with formulated products can be counterproductive.

In the Lowry case, the plant carbon apparently removed whatever the amine supplier added to the formulation to retard foaming. Consequently, the operator paid a premium for an amine, formulated with an antifoamer that the plant carbon preferentially removed, thereby contributing to the foaming problem, increasing amine losses, and increasing carbon consumption.

Analyses of the deionized makeup water, lean amine, rich amine, stripper reflux inlet-separator liquids, and amine carryover (foam) were made to identify any contaminants that could have caused the foaming problem. Aliphatic hydrocarbons of C1o through C26 were found to be present at only 670 ppm concentration. No aromatics or degradation products were found.

Originally a 5 x 7 mesh carbon had been specified for use in the Lowry amine unit, based on the assumption that greater surface area means longer bed life. Fine mesh activated carbon does have a higher surface area than coarser grades of carbon, but the ability to remove surfactants which cause foaming depends more on pore size than surface area.

Fine-mesh activated carbons are often less effective at removing high molecular weight contaminants which cause foaming in amine plants than more granular carbons with a larger median pore size. In addition, finemesh carbons release more fines and are more easily fouled by particulates in the treating solution.

In this case, a larger-mesh carbon with a larger median pore size would be more effective at removing the liquid hydrocarbons and surfactants already in the solution.

The method used to charge the carbon bed has a major impact on its efficiency. The bed should be partially (one third) filled with amine solution or steam condensate prior to adding any carbon. The carbon should then be dumped into the liquid and permitted to settle to the bottom in a uniform manner.

If possible a slight vacuum should be applied to the vessel after filling in order to "degas" the carbon and increase its effective surface area. If it is impractical to apply vacuum to the vessel, it is advisable to back-flush the bed with warm condensate water to remove fines and displace entrained air.

Wet carbon, however, being quit corrosive, should not be stored in carbon steel for extended periods of time.

Aqueous amine carbon solutions are much less corrosive. Carbon filter beds can be constructed of carbon steel, and aqueous amine carbon solutions can be stored in carbon steel for extended periods.

In January 1987, the plant was shut down as a result of amine foaming. The severity of the problem prevented the plant's being brought back on line.

On essentially the same date, one of the plant's gas-gathering lines was experiencing a severe emulsion problem in its field separators.

The emulsion was quite stable and would not "break." (As early as November 1986, stable emulsions had been reported during meter proving on that line.)

A rental carbon filter skid unit containing 10,000 lb of 8 x 30 mesh carbon was moved to the plant and connected to the amine piping system in place of the existing carbon filter. Amine solution was recirculated through the new carbon for several days without sour gas moving to the absorber.

The amine solution became crystal clear. There were no visible particulates and no discoloration at the time sour gas was reintroduced.

When sour gas was allowed to enter the absorber, foaming began almost immediately and the plant was again shut down.

Samples were immediately gathered and tested in the plant laboratory for foaming tendencies.

The amine was found to form a persistent stable foam, that is, a foam with a long break time.

The antifoam products in use at the time were simply ineffective. New products were recommended.

The plant laboratory tested a number of alternate antifoam products and found an acceptable candidate. The new antifoam product was added to the circulating amine solution to a concentration of 50 ppm. Gas was then allowed to enter the absorber.

No carryover (foaming) occurred.

SOLUTIONS; PERFORMANCE

The foaming and amine loss problems were eventually solved by respecification and installation of new amine solution filters (cartridges and carbon) and by installation of an inlet gas-liquid coalescing filter ahead of the absorber and downstream of the existing inlet filter-separator.

The activated carbon specification was changed to an 8 x 30 mesh granular activated carbon with a larger median pore diameter. Mechanical filters were retrofitted with 10m absolute filter elements with a p 5,000 specification in order to remove fine particulate matter.

(The value is equal to the number of particles of given size and larger in the inlet divided by the number of particles of given size and larger in the outlet. Consequently, a p 5,000 rating would equate to 99.98% removal of particles 10 m in size and larger.)

With high-efficiency coalescing elements, a field test was conducted on the plant's inlet gas at a point downstream of the existing inlet filter-separator.

The test confirmed that particles of liquid were passing through the existing filter-separator.

Retrofitting the existing filter-separator with high-efficiency coalescing elements was investigated but was impossible because of the vessel's internal design.

During the following months it was necessary to add antifoam in small quantities, but only when foaming tendencies were indicated by laboratory tests.

Initially, the carbon filter was cycled in and out of service, based on foam test results; that is, the carbon filter was put in service only when foam height and break time tests indicated that carbon filtration would be effective.

Samples of well-treating chemicals and pipeline corrosion inhibitors were obtained, mixed with the plant's amine solution in the laboratory, and tested for foaming characteristics.

Low concentrations of well-treating chemicals did not cause problem foaming, but higher concentrations were seen to be a problem. The pipeline corrosion inhibitors caused problem foaming even at low concentrations.

After confirmation that the amine was being contaminated by liquids passing through the filter-separator and that these liquids were the cause of foaming, an inlet coalescer was installed downstream of the inlet filter-separator.

Absolute rated coalescing elements (0.3 m) were specified.

The coalescer was designed with a lower chamber to catch small slugs of liquid and an upper chamber containing the coalescing elements to remove aerosols.

Following startup, it was noted that each section maintained a continuous liquid level with continuous liquid removal.

Once the coalescer was put into service, antifoam consumption was reduced to an insignificant level, although not completely eliminated. The carbon bed and mechanical filters were also put into continuous services after the coalescer was installed.

The system has been operating since November 1987 with no serious shutdowns caused by foaming.

The economic impact is shown in Fig. 5. With proper filtration, the Lowry plant was projected to save approximately $100,000/year, or about $2/MMscf of gas treated.

REFERENCES

  1. Ross, S., "Mechanisms of Foam Stabilization and Antifoaming Action," Chemical Engineering Progress, Vol. 63, No. 9, September 1967.

  2. Meusburger, K. E., and Segebrecht, E. W., "Foam Depressants for Gas Processing Systems," 1980 Gas Conditioning Conference, Norman, Okla., March 1980.

  3. Pearce, R. L., et al., "Amine Gas Treating Solution Analysis: A Tool in Problem Solving," 59th GPA Annual Convention, Houston, Mar. 17-19, 1980.

  4. Pauley, C. R., and Perlmutter, B. A., "Texas plant solves foam problems," OGJ, Feb. 29, 1988, p. 67.

  5. Perry, C. R., "Filtration Method and Apparatus," U.S. Patent No. 3,568,405, Mar. 9, 1971.

  6. Monat, J. P., et al., "Accurate Evaluation of Chevron Mist Eliminators," Chemical Engineering Progress, December 1986.

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