PROCESS FOR REDUCING CORROSIVE CONTAMINANTS IN PROCESS WATER

Description

CROSS-REFERENCE TO RELATED APPLICATIONS AND CLAIM OF PRIORITY

This application claims the benefit of priority of application Ser. No. 1020240149769, filed in Brazil on Jul. 22, 2024, and of application Ser. No. 1020250150913, filed in Brazil on Jul. 21, 2025; the complete disclosures of which are each incorporated herein by reference.

FIELD

This disclosure relates to the field of oil and gas, more specifically in the area of downstream and biofuels, and refers to a process for reducing corrosive contaminants in process water.

BACKGROUND

The presence of ammonia, sulfides and cyanides in the water condensed in the gas recovery section of the fluid catalytic cracking (FCC) unit leads to a corrosive process that can cause the unit to stop for equipment replacement or even result in a process safety accident, when the corrosive process is not detected in time. Cyanide dissolves the protective layer of ferrous sulfide, formed on the inner wall of the pipeline, exposing the metal iron to attack by H₂S, which releases atomic hydrogen that inserts itself into the crystalline metal matrix and forms bubbles of molecular H₂ when it encounters another atomic hydrogen in the same situation.

Hydrogen bubbles grow over time and create cracks that weaken the walls of equipment. The problem is more severe in partial combustion FCC units, where the burning of the coke produces a mixture of CO and CO₂ in the combustion gas of the regenerator. In these units, the content of ammonia and residual cyanide in the combustion gas is higher. Ammonia dissolved in the process water raises the pH and increases the solubilization and the degree of ionization of sulfides and cyanides, enhancing the corrosive process.

The corrosion control strategy in the gas recovery section of the FCC has been the problem remediation, through the control of the pH in the range of 7 to 8 and the dilution of contaminants by the wash water or even by the injection of ammonium polysulfide to convert the cyanides into thiocyanates.

STATE OF THE ART

In the fluid catalytic cracking (FCC) process, typically, a feedstock of heavy hydrocarbons, with a boiling point greater than 350° C., is converted into lighter compounds through cracking reactions in the presence of a pulverized acid catalyst. Cracking reactions predominantly produce gases with 2 to 4 carbon atoms, naphtha with 5 to 12 carbon atoms, and to a lesser extent, heavier products and coke. Coke consists of a carbonaceous material that is deposited on the catalyst causing the catalyst to be deactivated. To remove the coke, the used catalyst is transported to a vessel separate from the reaction section, the regenerator, where the coke is burned with air, releasing heat, restoring the catalyst's activity, and producing a combustion gas that is released into the atmosphere. The regenerated and hot catalyst is transported back to the reaction section. The burning of coke in the regenerator can be done with a sufficient amount of air for the complete burning of carbon to CO₂ (called total combustion) or for an incomplete burning with less oxygen, which produces a mixture of CO and CO₂ (called partial combustion).

Document U.S. Pat. No. 5,240,690A refers to a method of removing NH₃ and HCN from the FCC regenerator gas sent to the CO boiler. This method consists of adding an oxygen-containing gas to the output line of the regenerator operated in partial combustion under certain defined process conditions. The regenerator output gas contains 1-6% CO by volume and at least 300 ppm of nitrogen compounds comprising NH₃ and HCN. Without the addition of an oxygen-containing gas, about 25% of NH₃ and HCN are converted to NOx in downstream CO boilers.

Document U.S. Pat. No. 6,881,390B2 refers to a method for reducing emissions of reduced nitrogen species in the gas phase of the regeneration zone during fluid catalytic cracking of a hydrocarbon feedstock through an additive catalyst of defined composition.

Document U.S. Pat. No. 8,926,928B2 refers to a process to reduce the amount of HCN discharged into the atmosphere from an FCC unit. The process comprises adding a catalyst to the combustion gas output line of the regenerator before it enters the collection medium, which can be a cyclone, a filter, or an electrostatic precipitator, and precipitating the catalyst into the collection medium to form a catalyst bed. Ammonia or ammonia precursor is optionally added to the combustion gas. The HCN combustion gas reacts in the presence of water and oxygen in the combustion gas, and optional ammonia or ammonia precursor, reacts in the presence of the catalyst bed to reduce the amount of HCN. The combustion gas containing a reduced amount of HCN is discharged into the atmosphere.

Document EP1558367B1 refers to a process for reducing NOx emissions in refinery processes, and specifically to a fluid catalytic cracking (FCC) process. Particularly, the EP1558367B1 disclosure refers to a process for reducing gas-phased reduced nitrogen species (e.g., NH₃, HCN) in the output gas of a fluid catalytic cracking unit (FCCU) regenerator operating at a partial or incomplete combustion. The reduction is achieved through the use of an additive oxidation catalyst mixed with the FCC main catalyst.

The Johnson Matthey document, 2019, titled ‘Taking steps to reduce FCC NOX emissions,’ refers to measures taken to reduce NO_X emissions from FCC processes. Among other things, the document states that oxygen is a key factor in determining whether the nitrogen in the coke forms N₂ or NO_X in the FCC regenerator. An excess of oxygen will push the reaction further in the direction of NOx, rather than N₂, in the oxygen-rich environment of the downstream CO boiler. Similarly, a lack of oxygen will increase the formation of reduced nitrogen species, which end up as NO_X instead of N₂. The theoretical “ideal spot” of oxygen would be the point between total and partial burn, i.e., close to zero O₂ excess and ppm levels of CO in the combustion gas.

A small part of the combustion gas produced in the FCC regenerator is transported to the riser along with the regenerated catalyst and the contaminant gases, ammonia and HCN, present in this stream are condensed in the FCC gas recovery section, in which the fraction of the cracking products that remains in steam form after condensation of naphtha on top of the FCC main fractionator is compressed and cooled for LPG recovery (3 and 4 carbon hydrocarbons).

Partial combustion units must work with low excess oxygen and relatively high CO levels in the combustion gas, resulting in higher NH₃ and HCN levels in the condensed water in the gas recovery system. In these units, the corrosive processes caused by ammonia and HCN are more intense.

Thus, unlike the state of the art, in some embodiments the present disclosure proposes a process in which the air injected into the riser converts part of the ammonia carried from the regenerator to the riser into N₂, reducing the ammonia content in the process water condensed in the product recovery section. By treating only the small percentage of combustion gas carried along with the regenerated catalyst, some embodiments of the disclosure interfere minimally in the FCC operation, proving to be advantageous in relation to the alternatives for oxidation of nitrogen species in the FCC combustion gas reported in the literature.

SUMMARY

An embodiment of the disclosure aims to propose a process for the reduction of corrosive contaminants in process water comprising: (a) injection of air or oxygen-containing gas or even pure oxygen at a base of the riser, which may be through a lift steam injection nozzle or through a specific gas injection nozzle below a feedstock injection; and (b) use of a combustion promoter with a maximum noble metal content in the catalyst inventory equivalent to 1 ppm on a mass basis in the catalyst. For information purposes, catalyst inventory refers to the total quantity of catalyst present in the process, that is, it describes the stock of active catalyst used or considered for calculation.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 illustrates the feedstock injection nozzle (100), the lift steam injection (200) and the air or oxygen injection (300) according to an embodiment of the disclosure.

FIG. 2 shows the process flowchart of the fluid catalytic cracking process including the application of the disclosure to the control of corrosion precursors in the product recovery section.

DETAILED DESCRIPTION

Embodiments of the present disclosure refer to a process for reducing corrosive contaminants in process water comprising the following steps:

• • (a) Injection of feedstock through a feedstock injection nozzle (3) located 4 m above the steam injection nozzle at the base of the riser (100);
  • (b) Injection of air or oxygen-containing gas or even pure oxygen into the base of the riser through the lift steam injection nozzle (4) below the feedstock injection nozzle (3) or by specific injection nozzle; and
  • (c) Use of combustion promoter with maximum noble metal content in the catalyst inventory equivalent to 1 ppm in the catalyst along with the injection of air or oxygen-containing gas or pure oxygen.

For a better understanding of the mechanism of action of the disclosure, it is convenient to know the flowchart of a fluid catalytic cracking process, as exemplified in FIG. 2. A preheated feedstock (1) is injected into a riser (2) through a feedstock injector nozzle (3), coming into contact with hot regenerated catalyst from a regenerator (13). Feedstock vaporization and volumetric expansion propel the catalyst and vaporized products to the top of the riser and into a separator vessel (6), where the spent catalyst, deactivated by the coke produced, and the volatile products are separated.

The volatile products (or cracking products) (7) are routed to the product recovery section and the spent catalyst to a stripper (9) where residual volatile products retained in the catalyst pores are recovered by steam injection. From the stripper (9), the spent catalyst is transferred to a regenerator (10) via a transfer line (8). In the regenerator (10), the coke from the spent catalyst, containing a relatively low content of nitrogen compounds from the feedstock, is burned with air (11) to produce combustion gas (12). The combustion regime can be total or partial. In the latter, due to the scarcity of oxygen, a larger portion of the nitrogen in the coke is converted into reduced species: ammonia and HCN. After the regeneration step, the regenerated catalyst is transferred back to the riser through a transfer line (13). A small portion of the combustion gas, including nitrogen species, is carried along with the regenerated catalyst.

At the base of the riser (2), fluidization steam (4) is injected to raise the catalyst to the topmost charge injection point. Along with the fluidization steam, air or oxygen-containing gas or even pure oxygen is injected through the injection nozzle (5) object of the invention, as shown in FIG. 1. The injection of air at the base of the riser converts the reduced nitrogen species from the regenerator to N₂ and NOx, which are inert to the corrosive process of the cold area.

The cracking products (7) exiting the top of the separator vessel proceed to a main fractionator (14) where they are cooled by circulating refluxes from the lateral withdrawals of a tower (16), with the lightest product of all being withdrawn from a top (15) of the tower (16), where it is partially condensed and collected in a top drum (17), which separates a light naphtha (18), gases (19), and part of a condensed water vapor (20).

The gases, in turn, proceed to a gas recovery section (21), where they go through the two stages of compression for LPG condensation. Wash water is injected into the discharge of a first compression stage (22). The condensed liquid streams and the gas streams are sent to a high-pressure vessel (23). At the high-pressure vessel (23), the streams are separated into a the mixture of light naphtha and LPG (24) that sent to the distillation and fractionation section, non-condensed gases (25) which go to the absorber, and a second part of the process water (26), in which the reduced nitrogen species that accelerate the corrosive process are dissolved.

Example

The proposed process was tested in a prototype research unit of a circulating FCC, with 200 kg/h of feedstock flow and 350 kg of catalyst inventory, equipped with a riser of 18 m in length.

The unit was operated in partial combustion, with the CO₂/CO ratio of the combustion gas being equal to 3. The unit operated with a used refinery catalyst without a combustion promoter and with a vacuum gasoil feedstock.

The temperature of the riser was 535° C. and the temperature of the regenerator was 680° C.

Thus, the air flow rate injected in the example was 1 kg/h. The calculation of the air flow rate was made by the CO content in the combustion gas multiplied by the inert gas content carried from the regenerator to the reactor. The air injection in tests following the example cited was varied from 0.5 kg/h to 2 kg/h. The air flow rate was proportional to the vacuum gasoil feedstock flow rate of 200 kg/h.

Additionally, four conditions were compared: in the first, the base case, 1 kg/h of nitrogen was injected at the base of the riser; in the second condition, 1 kg/h of air was injected; the third condition repeated the air injection and added 20 g of a platinum-based commercial combustion promoter to the 350 kg of the base catalyst; and in the fourth condition, the unit was operated in complete combustion with 3% excess O₂ in the combustion gas. To date, the best condition tested was the one in which the injection was combined with the use of the combustion promoter in the catalyst, whose maximum platinum or noble metal content is equivalent to 1 ppm in the catalytic system. Other metals can be used as combustion promoters in the catalyst, like palladium, rhodium and iridium.

The process water was sampled in the water/oil separation vessel at a pressure of 1.6 kgf/cm² g and the ammonia content in the water was measured using the APHA 4500—(SM4500NH3) method. The ammonia nitrogen contents measured in the first three conditions were respectively 2,992 mg/kg, 2,304 mg/kg, 1,695 mg/kg and 1,400 mg/kg. The injection of air into the riser reduced the ammonia nitrogen content by 700 mg/kg and the air injection combined with the combustion promoter reduced the ammonia nitrogen by 1,300 mg/kg compared to the base case.

In the example, air was injected into the base of the riser through the double-fluid lift steam injection nozzle (100), shown in FIG. 1, and the feedstock was injected into a nozzle located 4 m above the base of the riser, ensuring a residence time of up to 4 s for the reaction of the ammonia from the regenerator with the oxygen from the injected air before the upflow reached the feedstock.

Application

Embodiments of the disclosure reduce the concentration of nitrogen species in the process water from FCC units operating in partial combustion, and thus reduce the corrosion rates of equipment in the product recovery section, extending the service life of the equipment and reducing operational risks.

Embodiments of the disclosure extend the service life of the equipment in the UFCC gas recovery section, which does not need to be changed as frequently, avoiding the associated costs.

This reduces the incidence of cracks in the equipment of the gas recovery section, thus reducing the risks of hydrocarbon leaks to the outside.

By reducing the corrosion rate, the reliability of the equipment in the FCC gas recovery section is increased.