CANADIAN GAS PLANT USES AMINE UNIT TO SWEETEN LIQUID ETHANE

Feb. 24, 1992
Ian M. Wesch Amoco Canada Petroleum Co. Ltd. Fort Saskatchewan, Alta. Treating liquid ethane with amine to remove CO2 has proven successful at Amoco Canada Petroleum Co. Ltd.'s Fort Saskatchewan gas plant. Experience at the plant indicates that, if recommended operating procedures and guidelines are followed, an amine contactor tower is economical and reliable for sweetening liquid hydrocarbons. The Fort Saskatchewan CO2-removal facility is unique, in that it is the only plant in North
Ian M. Wesch
Amoco Canada Petroleum Co. Ltd.
Fort Saskatchewan, Alta.

Treating liquid ethane with amine to remove CO2 has proven successful at Amoco Canada Petroleum Co. Ltd.'s Fort Saskatchewan gas plant.

Experience at the plant indicates that, if recommended operating procedures and guidelines are followed, an amine contactor tower is economical and reliable for sweetening liquid hydrocarbons.

The Fort Saskatchewan CO2-removal facility is unique, in that it is the only plant in North America which is treating a pure liquid-ethane stream.

USUAL APPLICATIONS

Amine treating of liquid hydrocarbons to remove H,S and CO2 is more common in refineries than in gas-processing facilities.

Approximately 400 such units are operating in North America, most in refinery applications.

Almost all of these units have less than 1,000 b/d capacity.

Amoco Canada Petroleum Co. Ltd. operates a 27,000 b/d liquid-liquid amine sweetening plant which treats liquid ethane at Fort Saskatchewan.

Construction of the CO2-removal plant was completed Mar. 1, 1989, at a total project cost of approximately $11 million (Canadian). The facility was originally designed for a nominal 20,000 b/d of liquid ethane (950 psig) with 3.5 mole % CO2 content and would produce specification ethane with a maximum of 500 ppm (mole) CO2 content.

The process utilizes methyldiethanolamine (MDEA) in a concentration of 40 wt % and a circulation rate of 240 gpm.

The facility is flexible in that raw ethane can be fed from pipeline (Alberta ethane gathering system), underground storage cavern, or both simultaneously.

Treated ethane is shipped in batches through the Cochin Pipeline to a Mid-America Pipeline Co. (Mapco) custody-transfer point at Clinton, Iowa.

The treated ethane is mixed with propane before being used as feedstock into chemical plants.

TREATING PROCESS

The raw ethane containing 3.5 mole % CO2 flows from pipeline or storage to a brine settler where entrained brine from the underground salt caverns is separated. The ethane preheater maintains the raw ethane temperature at higher than 61 F. to prevent hydrate formation within the contactor tower.

The raw ethane enters an 84-in. diameter contactor at 950 psig and flows upward countercurrent to the amine. The 60-ft high contactor consists of liquid distributors for the ethane and amine to ensure adequate mixing and two 14-ft packed sections (2-in. Norton Hy-Pack).

Treated ethane leaves the top of the contactor at 870 F. containing 500 ppm (mole) CO2. The increase in the ethane temperature results from sensible heat transfer with the amine and the exothermic reaction occurring within the contactor.

Two parallel static mixing units are provided to water wash the treated ethane to recover soluble and entrained amine from the ethane. The water and amine are recovered in the water-wash settler. The treated ethane then enters a series of centrifugal pumps where it is increased to a pressure of 2,300 psig for injection into an underground storage cavern (Fig. 1).

The process utilizes methyldiethanolamine (MDEA) in a concentration of 45 wt % and a circulation of 240 gpm. The MDEA solution is a proprietary solvent (Dow Gas Spec CS-1M), but there is no associated licensing fee.

The amine-regeneration system is similar to those found in gas-liquid treating systems (Fig. 2). Items worth noting are that the flash tank operates at 65 psig where approximately 50 Mcfd of ethane is recovered for fuel gas and that the total amine stream is put through the activated carbon bed.

The lean-amine coolers and lean-rich exchanger are plate-type design. Suspected plugging and fouling problems have not developed as yet in these exchangers.

The acid gas is incinerated to convert any residual H,S and other sulfur compounds to SO2 as required by Alberta regulations (Fig. 5).

REMOVAL SYSTEM

Initial amine level within the contactor was set at maximum (top of the level column) for start-up, as recommended. Operating at this high amine level resulted in large amounts of amine being carried over into the wash water settler. Amine loss was probably very high at this time.

The carry-over could not be stopper until the amine level was lowered by 4 ft. A recommended procedure for initial plant start-up is to begin with a low amine level and then increase the level as necessary to meet specification; this will reduce carryover problems and overloading of the amine solution.

If amine carry-over persists even at a lower amine level in the contactor or if product specification prohibits a reduction of amine level, inject antifoam into the lean-amine stream. The antifoam may break up the ethane-amine emulsion which is causing the amine carryover.

The upgraded operating capability of the facility is 27,000 b/d of raw ethane containing 3.4 mole % CO2 and a treated product containing 50 ppm (mole) CO2. The CO2 level from an online analyzer has been as low as 20 ppm (mole) in the treated product.

At these conditions, the amine circulation rate was decreased to 220 gpm where amine solution was loaded at 0.42 mole acid gas/mole of amine, based on the actual 3.0 mole % CO2 composition in the raw-ethane feedstock.

Various methods of reducing energy consumption of the plant by increasing the CO2 level to 500 ppm (mole) in the treated ethane were examined. Because of operating conditions that must be maintained in the regenerator (discussed later in a section on corrosion), all but one method would result in increased amine-system corrosion and therefore were not pursued.

The only viable method was to reduce the amine level in the contactor and therefore the number of equilibrium stages. The contactor amine level was decreased an additional 10 ft but the 50 ppm (mole) CO2 level was still maintained.

At this time, the amine level was at the bottom of the bridle line and therefore it was thought best not to reduce the level any farther for safety considerations until the bridle line was extended.

The economic benefits of increasing the CO2 content to the desired 500 ppm (mole) level are questionable; the amine loading would decrease by only 1.5%.

In addition, if the 500 ppm CO2 content was achieved in the treated product, the amine height vs. CO2 content may be very sensitive.

This means that a relatively small fluctuation in the amine level or ethane feed rate could increase significantly the CO2 content in the treated ethane. Therefore, the additional operating problems associated with a decrease in amine level could far outweigh the economic benefits.

It should be noted that ethane specification is 680 ppm (mole) CO2 Although a distinct ethane-amine level exists in the bridle line, the same cannot be said about the interface in the contactor (Fig. 3). The interaction of the streams results in a "blurred" level.

This blurred level, or "mutually dispersed zone," may extend beyond the beds because of the momentum of each fluid, requiring additional distance for the ethane and amine completely to disengage from one another.

In general, the amine level within the contactor should not be considered as a legitimate control variable. An amine level which doesn't promote excessive amine carry-over and achieves the desired product specification should be determined and then maintained as best possible.

Attempting precisely to control product specification by adjusting the amine level within the contactor on an ongoing basis could result in amine carry-over if the level is too high. Or it could cause the amine flash tank to over pressure because of ethane entrainment if the level is too low.

When the contactor is being operated at greater than design ethane-flow rates, it is important not to exceed the maximum allowable velocity of the holes in the feed distributor. Exceeding the velocity will cause the ethane to emulsify, in amine resulting in ethane entrainment to the amine flash tank (cold vessel temperature) and the regenerator tower (foaming).

The holes can be drilled to a larger diameter to reduce velocities if necessary.

Other causes of ethane entrainment are low amine level in contactor and high amine concentration.

Table 1 compares the design with some actual operating conditions for the CO2-removal facility.

The start-up procedure of the CO2-removal plant took 10 hr to complete initially.

The procedure called for an initial ethane rate of 8,000 b/d to be recycled through the facility and then additional raw ethane to be admitted slowly until design ethane-feed rate was achieved. The recycle would be discontinued at full ethane feedrate.

The start-up procedure has since been modified to reduce the duration to 1 hr. Amine circulation is set at the desired rate.

The ethane rate is initiated at 9,900 b/d until the system stabilizes and is then increased to 27,000 b/d; no recycle occurs.

SOLUTION MAINTENANCE

The CO2-removal unit's amine losses are estimated to be 4-5 gpd.

The majority of the loss is attributed to packing leaks in the reciprocating amine pumps.

Losses associated with solubility of the mdea in the ethane are approximately 2.5 gpd.

The low amine losses, well below the design of 4.5 gpd, indicate that the water wash system is functioning well. The low amine level within the tower may also be a major factor.

Operational literature obtained for some liquid-liquid amine treating facilities states that amine losses can range from 20 to 30 gpd and increase to 100 gpd or more during upsets.

Because of the severe corrosion potential associated with CO2 removal, amine maintenance is of utmost importance. Amine samples are obtained daily for analysis to determine foaming tendency, amine loading, and concentration.

Rich-amine loading is obtained by use of a material balance on the acid gas system and lean-amine loading. Detailed amine analyses are conducted monthly to determine amine corrosiveness and the level of degradation products.

Formates are produced when CO2 absorbed by the amine reacts with oxygen and, therefore, indicates the amount of air entering the system. Thiosulfate and sulfates are formed when H,S absorbed by the amine reacts with oxygen.

The most prevalent degradation product found in the MDEA solution at the CO2 removal facility has been formate.

Corrosivity of the amine solution has been maintained under 1 mil/year (mpy) with the use of the activated carbon bed. The carbon bed adsorbs corrosion precursors and entrained hydrocarbons.

In one instance, the amine solution corrosivity increased from 1 to 17 mpy within 1 month; the activated carbon was subsequently replaced and the amine-solution corrosivity returned to

Currently, heat-stable salts comprise 0.3 wt % of the amine, far less than the target level of 10% of total solution alkalinity or 4.5 wt %. The formate level is at 300 ppm.

The iron and sodium levels are at 46 ppm and 32 ppm, respectively. This indicates that some brine carryover is occurring into the contactor and subsequently the amine; the levels as yet are not of concern. Surprisingly, chlorides have not as yet been detected in the amine solution.

A reverse osmosis (RO) unit treats potable water for use in water make-up in the amine system. The RO unit will remove any dissolved metals, minerals, and salts.

The treated-water storage tank should be internally coated if of steel construction. The CO2-removal plant's treated-water storage tank was uncoated. Within 1 year, serious internal corrosion was evident. This is detrimental to the amine condition and basically defeats the purpose of a water-treatment system.

The tank has since been sandblasted and internally coated.

CORROSION

Corrosion primarily caused by CO2 is termed "sweet" corrosion. This type of corrosion is more aggressive than sour corrosion and results in pitting in vessels and piping.

[SEE FORMULA]

The CO2 removal plant's amine system contains little stainless steel pipe. Therefore, it is very important to maintain amine condition so that solution corrosivity is reduced. System corrosion is monitored with an annual corrosion coupon analysis and ultrasonic survey.

Detailed analyses of the MDEA solution are conducted monthly to maintain a "passive" amine condition. The maximum recommended amine solution loading of 0.45 mole acid gas to mole MDEA is not exceeded. In addition, by maintenance of adequate stripping in the regenerator, the lean-amine loading of 0.015 is not exceeded.

The high temperature and high CO2 partial pressure within the amine-regenerator tower make it an ideal location for severe corrosion.

To reduce corrosion within the vessel, the reboiler heat input is such that a regenerator tower overhead composition of 0.9 mole H2O to mole CO2 is maintained. This decreases the partial pressure of the CO2 to 10-5 psia, making the acid gas mildly corrosive.

Recent visual inspection of the regenerator trays with associated piping and the reboiler tube bundles discovered no visible damage or pitting. Ultrasonic and corrosion-coupon analyses indicate that some "hot spots" exist within the amine system, particularly directly upstream and downstream of the flash-tank level control valve.

The pressure drop (55 psig) compounded with the temperature increase across the lean-rich exchanger make the control valve a likely location for acid-gas break out. The carbon steel piping located between the lean-rich exchanger and the regenerator tower was replaced with stainless steel in June 1991.

The corrosion rate upstream (30.3 mpy) and downstream (31.4 mpy) of the amine flash-tank level control valve decreased to 0.27 mpy and 0.31 mpy, respectively. Otherwise, system corrosion is considerably less than the desired level of 5 mpy; the average corrosion rate throughout the amine-regeneration system is approximately 2 mpy

The installation of full port valves on the rich amine piping will reduce the chance of CO2 breaking out of the solution. All welds in rich and lean amine service are stress relieved to avoid cracking; this is a recommended practice.

OPERATIONAL PROBLEMS

Foaming in the regeneration tower has been an ongoing problem. Anti-foam is constantly injected at a rate of 0.5 gpd. This anti-foam is being adsorbed by the activated carbon bed and is thus reducing bed life.

The primary cause of the amine foaming was the inability of the cartridge filter downstream of the carbon bed to remove particulates in the amine.

This cartridge filter has since been replaced by a bag-type filter and has reduced filtration to 5 m nominal in an effort to clean up the amine. The frequency of filter change out, at the present 5 m level, is approximately once a week.

Another possible cause of the regenerator tower foaming is ethane carry-over from the flash tank. Analysis indicates that ethane comprises 0.8 mole % of the acid gas; whether this is a factor in the foaming is unknown.

Large temperature increases are experienced across the booster (11 F.) and injection pumps (38 F.).

These pumps operate in series increasing ethane pressure to 1,200 psig and 2,300 psig, respectively. The treated ethane leave; the water-wash settler at 950 psig and 87 F.

At these conditions, the ethane is greater than both the critical pressure and critical temperature making it "dense" phase. When a fluid is dense phase, any pressure increase subsequently increases the temperature, similar to vapor phase.

Ethane on the discharge side of the injection pumps is used as a flush to its mechanical seals. The seals' design for 50 F. and the 127 F. seal-flush temperature has resulted in frequent seat failures.

Unsuccessful attempts have been made to reduce failure by increasing flush rates and by modifying the seal design. A heat exchanger which utilizes a slip stream of the CO2-removal plant inlet raw ethane has been installed to reduce the seal-flush temperature to 75 F. at 2,300 psig (any lower temperature would risk formation of hydrates).

In addition, a heat exchanger has been installed which exchanges thermal energy between the cold raw ethane entering the facility and the warm treated ethane leaving. The reduced treated-ethane temperature has resulted in a lower frequency of seal failure and a decrease in plant-operating costs as a result of the preheating of the raw ethane stream (Fig. 4).

Quintuplex reciprocating pumps are used to circulate amine. Upon start-up of the CO2-removal facility, excessive amine losses of as much as 25 gpd were occurring because of packing leaks. These losses increased until the packing would fail.

Visual examination of the Colmonoy No. 6 coated steel plungers showed them to be heavily scored. In addition, the stuffing boxes were found to be pitted after 3 months of service.

When ceramic plungers were installed with the existing aramid fiber (Kevlar) packing, amine losses were reduced to 2 gpd. The carbon-steel stuffing boxes were replaced with stainless steel; no pitting has occurred since. Pump vibration has resulted in drain lines failing due to fatigue. Pipe supports have been modified and increased to provide better reinforcement.

As described earlier, when the activated carbon bed was spent, the formate levels increased rapidly. This indicated that enough air was entering the system to be of concern. A gas blanket is provided on all vessels containing the MDEA solution. Therefore, dissolved oxygen in the treated water used for make-up was the suspected source.

A natural gas blanket on the treated water has since been installed to reduce air infiltration into the amine solution. The gas blanket reduces the partial pressure of oxygen above the water and hence decreases the solubility of oxygen in the treated water.

Another possible source of air entering the system is the packing in the amine reciprocating pumps.

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