CORROSION I N CRUDE TOWERS

CROSS REFERENCE TO RELATED APPLICATION

[0001] The present application claims priority under 35 USC §1 19(e) to U.S. Provisional Patent Application Serial No. 61/604,002 filed February 28, 2012 and entitled "Steam Generator Additives to Minimize Fouling and Corrosion in Crude Towers".

BACKGROUND

[0002] Steam generators are used to provide steam to a variety of industrial processes. In the petroleum refining industry, steam is provided to the fractional distillation tower as a stripping medium to fractionate crude oil into various cuts or fractions of different volatility including gasoline, fuel oil, gas oil, naphtha, kerosene, and others. In the fractionation tower, steam is injected into the bottom of the tower as a stripping medium. When it is introduced, it reduces the partial pressure of the hydrocarbon compounds in the crude to facilitate the separation and removal of volatile compounds. The steam helps separate the lighter products which then rise to the top of the tower where they condense on horizontally disposed trays. These trays are increasingly cooler higher in the towers. Thus, the heaviest hydrocarbons are collected on the lower trays while the lighter products collect on the higher trays.

[0003] The lower boiling fractions are recovered as an overhead fraction from the distillation zones. The intermediate components are recovered as side cuts from the distillation zones. The fractions are cooled, condensed, and sent to collecting equipment. No matter what type of petroleum feedstock is used as the charge, the distillation equipment is subjected to the corrosive activity of acids such as H ₂ S, HCI, organic acids and H2CO3. [0004] Corrosion may occur on the metal surfaces of fractionating towers such as crude towers, trays within the towers, heat exchangers, etc. The most troublesome locations for corrosion are tower top trays, overhead lines, condensers, and top pump around exchangers. It is usually within these areas that water condensation is formed or carried along with the process stream. The top temperature of the fractionating column is usually but not always maintained about at or above the boiling point of water. The aqueous condensate formed contains a significant concentration of the acidic components mentioned above. This high concentration of acidic components renders the pH of the condensate highly acidic and, of course, dangerously corrosive. Accordingly, neutralizing treatments have been used to render the pH of the condensate more alkaline to thereby minimize acid-based corrosive attack at those apparatus regions with which this condensate is in contact.

[0005] In the past, a variety of amines has been fed to the distillation tower in order to neutralize the mostly acidic corrosive acids found in the crude charge. Often, the amines can form corrosive salts such as amineHCI salts. Desirably, these salts remain volatile in the tower. If the salts precipitate at all, it is desirable that they do so only in the overhead lines so that the precipitating salt species may be washed away by wash water systems commonly employed in conjunction with condenser feed and return lines.

[0006] Industrial steam generation systems are also prone to corrosive attack. One of the most common corrosive concerns is that of acid attack related to the formation of carbonic acid, H2CO3, in the water. Acid attack can occur when the pH of the water drops below about 8.5. At that point, the carbonate alkalinity in the water is converted to CO ₂ gas. The CO ₂ is carried with the steam and, upon condensation, dissolves in the water to form carbonic acid, H ₂ CO ₃ . Such acid attack may adversely affect condensate piping.

[0007] Traditionally, in order to provide corrosion protection in steam generation systems, both neutralizing amines and filming amines have been used. Neutralizing amines are highly basic and are commonly fed to the boiler feedwater or to the steam drum to neutralize the carbonic acid that may form in the condensate. Additionally, filming amines are added to the boiler system so as to form a protective layer on condensate plumbing, primarily to protect it from oxygen and acid attack. Usually, the filming amines are fed to the steam drum.

[0008] Accordingly, in those petroleum refinery operations in which generated steam is used as a stripping medium to facilitate hydrocarbon separation as mentioned above, it would be beneficial to provide an amine treatment that could be supplied to the boiler to provide effective protection in the boiler as a neutralizing amine while carrying over with the generated steam that is used as a stripping medium for the distillation column. Ideally, this amine would also serve to neutralize acidity in the distillation tower while remaining in the vapor phase in the distillation unit. If the amine or its salt, such as the amineHCI salt were to precipitate, this precipitation would desirably not occur inside the tower, rather it would occur in the overhead condensate lines downstream from the fractional distillation tower. These lines are usually subjected to a water wash operation so that any salts precipitating in these lines could be readily washed away from the metallic piping surfaces.

BRIEF DESCRIPTION

[0009] In one embodiment of the invention, an integrated solution is provided for protection of both the steam generator system and the distillation towers of a petroleum or petrochemical refinery from corrosion and fouling.

Neutralizing amines are chosen to provide protection for the steam condensate section of the boiler while simultaneously minimizing amine fouling and corrosion issues in the crude distillation tower and the overhead condensing system of crude distillation units.

[0010] These "dual action" amines provide both corrosion protection for the boiler system and the added benefit of minimizing fouling deposits inside the distillation tower. When these amines reach the distillation tower with the steam, they do not precipitate and foul inside the tower. They are pushed to the tower temperature sections of the crude overhead system where their corrosive impact can be minimized by other corrosion inhibition strategies.

BRIEF DESCRIPTION OF THE DRAWINGS

[0011] The attached figure is a simplified process flow diagram of a typical steam fed crude oil fractional distillation unit.

DETAILED DESCRIPTION

[0012] As shown in the figure, crude fractional distillation tower 20 distills the crude entering the tower through charge line 56 into various fractions of different boiling ranges. The crude fractional distillation tower is sometimes referred to as an atmospheric distillation unit because it operates at slightly above atmospheric pressure.

[0013] It is noted that the crude admitted to the tower is typically subjected to preheating and desalting operations upstream from the charge line 56, but these are omitted herein for the sake of brevity. The crude is distilled into a plurality of fractions in the tower 20, with side cuts 22, 24, and 26 shown in the figure representing atmospheric gas oil (AGO), diesel, and jet fuel/kerosene side cut fractions respectively. (The horizontal condensation trays in the tower are shown in phantom).

[0014] The crude is typically preheated to about 200-700 °F before it enters the tower. After preheating, the feed is then flashed into the atmospheric distillation unit which operates at pressures of about 1 -3 Atmospheres gauge.

[0015] In the figure, a two stage condenser unit is shown for the removal of overhead that condenses to form naptha with reflux admitted at the top of the tower. The two stage condenser includes heat exchangers 32, 50 with line 30 leading to heat exchanger 32 and line 33 leading to reflux drum 34. Gases from the drum 34 advance to second stage compressor 50 through line 42. A vacuum is drawn on reflux drum 34 by pump 36 resulting in return of reflux through line 35 to the pump and then through line 38. Naptha collection is shown at 40.

Gases from the second stage condenser 50 are advanced to condensate drum 44 with condensate recycled through line 60 to the vacuum pump 36.

Noncondensing gases are vented at 46 with sour water exiting at 48 for neutralization or other treatment.

[0016] As shown, the overhead condensate system is provided with a water wash, diagrammatically shown at 28, to wash the vapors exiting at the top of the tower. In the past, corrosion problems have been experienced not only on the tower trays but especially in the overhead components of the system such as the lines 30,33,35,42,60, the heat exchangers 32,50, and the reflux and condensate drums. Overall, typical operating temperatures in the overhead condensate system range from about 200 °F to about 350 °F.

[0017] Residuum exits from the bottom of the tower through vacuum line 54 and is typically condensed to form fuel oil or coker naptha and/or coker gas oil.

[0018] As shown, stripping steam is fed to the bottom of the tower via line 14. The steam is produced in boiler 2 via conventional processes. For example, boiler feedwater 10 may be subjected to softening treatment 6 and deaerator 8 prior to entry into the boiler. Steam produced in the boiler is collected in a drum or header 4 and is then fed to the distillation tower 20 via line 14.

[0019] In accordance with one embodiment of the invention, a "dual" action neutralizing amine is fed in vapor phase to the distillation tower 20 through feed line 14 along with the stripping steam. By "dual action", I mean to denote those amines which function to perform effectively as a volatile neutralizing amine in the boiler while, after being fed as steam to the tower, persist in the tower in vapor phase to effectively neutralize acidic components from the crude. Deleterious amine salts, such as amineHCI salts, do not precipitate in the tower with injection of these amines into the unit 20. Precipitation of such salts such as the amine-HCI salt will occur, if at all, only in the overhead condensation units and related lines which operate at temperatures proximate the water dew point.

[0020] In one exemplary embodiment, the dual action amine is N,N- dimethylethanolamine - DMAE. Another exemplary dual action amine is morpholine (MORPH).

[0021] In another exemplary embodiment, the "dual" action amine may comprise one of members of the group selected from DMAE, MORPH, NH ₃ , N- hexylamine, Ν,Ν-dimethylcyclohexylamine (DMCA), 1 -Dimethylamino-2-propanol (DMIPA), t-butylmorpholine (TBM), Dimethyl-t-butanolamine (DMTBA), N- ethylmorpholine (NEM), Ν,Ν-dimethylmethoxypropylamine (DMMPA), N- methylmorpholine (NMM), Ν,Ν-Dimethylmethoxyethylamine (DMMEA), trimethylamine (TMA), hydroxylamine (HA), cyclohexylamine (CYCLO), 1 - methylpyrrolidine, 1 ,4-dimethylpiperazine, Ν,Ν,Ν',Ν'-tetramethylethylenediamine, 2-Aminomethylfuran, Ν,Ν-Diethylhydroxylamine (DEHA), 1 ,2- Dimethylpropylamine, N-Methyldibutylamine, N-Methyldipropylamine, 2-Ethyl-1 - hexylamine, N,N-Diethyl-propargylamine, Ν,Ν-dipropylamine, diallyl amine, pyrrolidine, 2-(methylamino)-ethanol, N,N,N',N'-tetramethyl-1 ,3-propane diamine, 4-methylpyridine, and N-methyl-2-aminomethylfuran.

[0022] Although applicant is not to be bound to any particular theory of operation, the overall performance of a given amine as a "dual action" amine may be predicted upon assessment of several factors. Initially, the pka of the amine should be chosen to be in the range of about 5.7 to about 10.7. Present data indicates that a more preferred range is about 8.0 to about 10.0. Additionally, the amine HCI salt volatility index should be about 2.1 or less. This amine/HCI salt volatility index may be calculated from the formula:

P225 (NH ₄ CI) P300 (NH ₄ CI)

P225 (AmineCI) Γ 300 (AmineHCI) 2 wherein P is the vapor pressure at either 225 °F or 300 °F. In general, it can be said then that the "dual action" amines are defined by having a pka of about 5.7 to about 10.7 and an amine salt volatility index of about 2.1 or less. However, while dimethylaminopropylamine (DMAPA) possesses such pka and volatility index characteristics, preliminary data suggest that DMAPA does not perform well as a "dual action" amine, and thus DMAPA is not to be deemed a part of the invention and is not to be considered as a "dual action" amine.

[0023] The artisan will appreciate that the "dual action" amines may be used in combination with other "dual action" amines.

[0024] Further, the "dual action" amines may be conjointly used in combination with commonly applied boiler treatments such as oxygen

scavengers, dispersants, polymers, filming amines, corrosion inhibitors, deposit control agents, etc.

[0025] The dual action amine can be fed to the boiler in any one or more locations such as to the boiler feedwater, in the economizer section of the boiler, in the condensate system, or to the steam header or drum. A sufficient amount of the dual action amine should be fed to the boiler so that the amine can provide its intending function as a neutralizing amine in the boiler, remain volatile in the steam fed to the tower, and remain volatile in the tower while neutralizing acidic components of the crude. The dual action amine or amines can be fed to the boiler system in an amount of about 0.1 to 100 ppm based on one million parts of water in the system. More preferably, the feed rate may be from 1 to 25 ppm.