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Internal document – Confidentiality required. Guidelines for Preventing Coking in Catalytic Cracking Units (Draft for Comment). Refining Division of Sinopec Corporation, January 21, 2005. Chapter 1: General Provisions 1.1 Purpose: To avoid or reduce unplanned shutdowns of catalytic cracking units due to coking, the Technical Department of the Refining Division of the Corporation has prepared these Guidelines for Preventing Coking in Catalytic Cracking Units, in the hope that they will provide guidance for design, production, and technical management departments during the future renovation and operation of such units. 1.2 Scope These guidelines apply to the catalytic cracking units in the refineries within the Sinopec Corporation system. 1.3 Refining companies are required to attach great importance to the problem of coking in catalytic cracking units. Relevant technical, production, equipment, and unit management personnel must share a common understanding, and based on the guidelines and the actual conditions of their respective units, take targeted preventive measures to reduce equipment coking and ensure the long-term operation of the catalytic cracking units. Chapter 2: Current Status of Coking in Catalytic Cracking Units Since residue oil has been blended into catalytic cracking units, the problem of equipment coking has increasingly become a bottleneck restricting the long-term operation of these units. Over the years, catalytic cracking experts have conducted in-depth and thorough research on the problem of coking in catalytic cracking units. It has been found that coking in such units mainly occurs above the feed oil nozzles in the riser, on the outer walls of the primary cyclone separators, on the inner walls and \"dead zones\" of the settlers, on the outer walls of the lift pipes of the cyclone separators in the settlers as well as on the guards of the wing valves in the feed legs, at the bends in the feed legs, in the secondary feed legs, as well as in the stripping section and the slurry inclined tubes. It also occurs in the gas collection chambers of the settlers and the large oil and gas pipelines, at the bottom of the distillation tower and in the slurry circulation system. When coking becomes severe in these areas, it directly affects the safe operation of the unit, leading to unplanned shutdowns. In recent years, various technical efforts have been made to address the coking problem in catalytic cracking units, with fruitful results achieved. At present, the coking issue in certain areas has been essentially resolved and effectively controlled, such as in large oil and gas pipelines, the bottom of distillation towers, and the slurry circulation system ； However, some areas that pose a significant threat to the long-term operation of the unit have not yet been fundamentally resolved or effectively controlled, such as the top of the settler and the outer wall of the gas lift pipe in the cyclone separator. According to incomplete statistics, coking in the cyclone separator alone accounts for over 50% of all unplanned shutdowns in catalytic cracking units. In some units, severe coking occurs repeatedly in the same areas, leading to unplanned shutdowns of the unit. It is evident that the coking problem has severely affected the safe, stable, and long-term operation of the catalytic cracking unit. Chapter 3: Measures to Prevent Coking in Catalytic Cracking Units 3.1 Raw Material Management 3.1.1 Each enterprise formulates corresponding quality control principles for catalytic cracking raw materials based on the characteristics of its own units, in order to standardize the quality of the feedstock supplied to the catalytic units. 3.1.2 Scientifically allocate catalytic raw materials in daily production management, select an appropriate slag blending ratio, and optimize the properties of the raw materials. 3.1.3 Strengthen the analysis and testing of raw materials; ensure a smooth transition when the properties of these materials change, in order to avoid significant operational fluctuations in the equipment. 3.1.4 Based on the current actual conditions of catalytic cracking units, the quality of feedstock is evaluated according to the value of the crackability parameter FFa. Raw materials with an FFa value greater than 0.7 are considered high-quality feedstocks for heavy oil catalytic cracking, while those with a value less than 0.6 are considered low-quality feedstocks and require pretreatment. 3.1.5 The hydrogen content of the catalytic cracking feedstock shall be not less than 11.8%, the density (d204) shall be not greater than 910 kg/m3, and the asphaltenic content shall be not greater than 5 w%. 3.1.6 The total metal content (Fe+Ni+V+Ca) in the catalytic cracking feedstock shall not exceed 25 PPm. 3.1.7 When the slurry density is greater than 1000 kg/m3, it is not fed into the riser for reprocessing. 3.2 Catalysts 3.2.1 Select the catalyst appropriately based on the characteristics of the equipment, the properties of the raw materials, and the production plan. 3.2.2 Catalysts with strong heavy oil cracking capacity, good coke selectivity, resistance to contamination by elements such as nickel, vanadium, calcium, sodium, and nitrogen – particularly strong resistance to vanadium – as well as excellent stripping properties and hydrothermal stability, and a favorable gradient distribution of large, medium, and small pores, should be selected. 3.2.3 The catalyst’s activity at equilibrium should be above 60, its specific surface area should be greater than 100 m2/g, with a minimum value of 90 m2/g; the content of heavy metals (Ni+V) should be less than 10,000 ppm, and the calcium content should not exceed 5,000 ppm. 3.2.4 Strengthen the daily management of catalysts by establishing records for their issuance and consumption, tracking the unit consumption of catalysts and monitoring their properties; this enables timely feedback to catalyst manufacturers and research institutions so that they can adjust the catalyst formulations as needed. 3.2.5 Select an appropriate metal passivator based on the type and degree of heavy metal contamination in the catalyst. 3.3 Engineering Design 3.3.1 Catalyst pre-boosting technology is applied to create a piston flow of the catalyst, with appropriate distributors being used, such as traditional \"faucet\" type pre-fluidization distributors as well as advanced pre-fluidization distributors developed both domestically and internationally. 3.3.2 The length of the pre-lifting section is 5 to 8 meters. 3.3.3 Improve the design of the riser feed section to reduce catalyst backmixing, and maintain the average linear velocity in the riser at around 15–25 m/s. 3.3.4 High-efficiency rapid separation devices are used at the outlet of the riser, such as China’s VQS cyclone rapid separation technology and foreign technologies like VSS (for internal risers) and VDS (for external risers). 3.3.5 When a coarse swirl structure is used for the quick separator at the outlet of the riser, a hopper designed with coarse swirling can be employed, as well as a \"soft connection\" consisting of coarse swirling plus a single-stage cyclone separator – that is, the oil and gas outlet pipe of the coarse swirling unit extends to the inlet of the single-stage cyclone separator. 3.3.6 Use high-efficiency atomizing nozzles. Domestically, there are the new-generation LPC, BWJ, and KH types of nozzles developed by Luoyang Petrochemical Engineering Company, Beijing Design Institute, and the Institute of Mechanics of the Chinese Academy of Sciences; internationally, there are the ATOMAX type of nozzles developed by Kellogg and Mobil companies, as well as the Optimix nozzle developed by UOP company. 3.3.7 The linear velocity of the nozzle should not be higher than 90 m/s nor lower than 20 m/s; it is generally maintained at around 50 m/s. For the first use of a new nozzle (or replacement of an old one), data from cold mold test results are required. 3.3.8 The anti-coking steam for the settler uses two-stage orifice nozzles, with the nozzles directed toward all the static spaces at the top. 3.3.9 During engineering design, sufficient attention should be paid and conditions created to raise the temperature of the settler shell, thereby preventing low-temperature oil and gas from condensing and coking. 3.3.10 Improve the design of the stripping section by employing efficient stripping techniques, so that the H2 content in the coke is no more than 6 w%. 3.3.11 Large oil and gas pipelines are designed in a cold-wall configuration, with a temperature drop of no more than 5°C. 3.3.12 The designed gas flow velocity for large oil and gas pipelines is 35–45 m/s. 3.3.13 Minimize the length of large oil and gas pipelines, and provide a slope to allow the condensed liquid to flow automatically into the fractionation tower. 3.3.14 For large oil and gas pipelines, the number of elbows should be minimized, their length should be kept as short as possible, and the pressure drop should be as low as possible (not exceeding 15 KPa). 3.3.15 For large oil and gas pipelines, elbows with a large radius of curvature are used at the reactor outlet, while elbows with a small radius of curvature are used at the distillation tower inlet, ensuring that the distance between the elbow and the distillation tower inlet is as short as possible. 3.3.16 The device’s emergency shutdown system ESD or FSC shall have a properly designed sequence of operation for the safety valves. In the design of the self-protection valve operation sequence, after enabling the differential pressure protection between the two vessels and the low main air flow self-protection, the feed self-protection valves such as those for crude oil and slurry reprocessing close first, while the regeneration slide valve and the spent catalyst plug valve should close later than the valves in the feed valve group. 3.3.17 Steam for bottom agitation is provided at the bottom of the distillation tower. 3.3.18 An oil slurry stirring ring pipe is installed below the stirring steam ring pipe at the bottom of the tower, and at the bottom of the filter for removing coke from the oil slurry extraction port. 3.3.19 Raise the filter at the bottom of the distillation tower to 1.5–2.0 meters, install a filter before the slurry pump, and raise the outlet of the bottom extraction line by 0.5–1.0 meter. 3.3.20 The flow velocity of the slurry in the system pipes should be no less than 1.5–2.0 m/s, and the flow velocity within the tubes of the heat exchanger should also be maintained at 1.5–2.0 m/s. 3.3.21 The pre-heating line for the slurry pump is designed with two manual valves: the upstream valve is kept fully open, while the downstream valve is used for throttling ； Alternatively, a wear-resistant flow-limiting orifice plate can be installed between the two hand valves, with both the upper and lower hand valves fully open. 3.3.22 Select an slurry pump with a sufficient net positive suction head to ensure it can operate without cavitation in the range of 50–390°C. 3.3.23 The fractionator output is connected to the inlet pipeline of the slurry pump; minimize the number of elbows and keep the pipeline as short as possible. 3.4 Operating Conditions 3.4.1 For units with a high slag blending ratio, the outlet temperature of the lift pipe should be maintained within the range of 500–520°C; for units with a lower slag blending ratio, this temperature should be kept between 490–510°C. 3.4.2 The linear speed in the pre-raising section should be controlled at 2.0–3.0 m/s, with a catalyst density of 240–480 Kg/m3. 3.4.3 Control the catalyst density at the riser nozzle at 250–400 kg/m3. 3.4.4 The riser reaction section can adopt MTC—mixed temperature control technology. 3.4.5 The terminator is injected into the riser; the injection location must be carefully designed, and the injection rate should be 4–10% of the amount of fresh feedstock. The medium to be used is determined based on the conditions of the facility (for example, catalytic cracking crude gasoline, straight-run gasoline, catalytic cracking diesel, light polluted oil from refineries, water purified by wastewater stripping units, and catalytic cracking acidic water). 3.4.6 The oil-to-agent ratio should be maintained between 6 and 8. 3.4.7 For incomplete regeneration, the temperature of the regenerating agent is controlled between 640°C and 710°C ； For complete regeneration, the temperature of the regenerating agent should be controlled at no more than 730°C. 3.4.8 In the re-refining process, it is necessary to control an appropriate re-refining ratio, which is generally around 0.1 ； Secondly, recycle more refined oil and less oil slurry; recycling is not carried out when the density of the oil slurry is greater than 1000 kg/m3. 3.4.9 The viscosity of the crude oil at the feed temperature should be less than 5 mm2/s; the lower limit of the preheating temperature is determined based on this viscosity requirement (it should generally be no lower than 195°C, and if possible, it should be kept above 210°C). 3.4.10 The flow rate of the atomizing steam should be controlled at 5% to 8% of the total feed rate; when the processing capacity is below the designed value, the flow rate of the atomizing steam shall be kept at the upper limit. 3.4.11 The temperature of the atomized steam shall be no less than 230°C. 3.4.12 The amount of anti-coking steam shall be no less than 1000 kg/h, and the internal temperature of the settler shell shall be controlled at 500–550°C. 3.4.13 The residence time of the reaction oil and gas in the oil and gas pipelines shall not exceed 3 seconds. 3.4.14 The residence time of the distillation column bottom slurry should be controlled at 3–5 minutes. 3.4.15 Control the liquid level at the bottom of the distillation tower at 30–50%. 3.4.16 The solid content of the slurry shall be controlled at ≤6g/l. 3.4.17 The density of the slurry should be controlled at around 1050 kg/m3 or less; for paraffin-based raw materials, this value can be slightly lower. 3.4.18 While ensuring the minimum flow rate of the slurry returning to the tower (to satisfy the catalyst washing effect of the circulating slurry on the oil and gas), maximum flow rate control is applied for the slurry circulating back down to the tower [8]. 3.5 Maintenance Work 3.5.1 During the shutdown for maintenance of the unit, all the coke that has accumulated on the lift pipe feed oil nozzles and the inner walls above those nozzles, on the inner and outer walls of the primary centrifugal separator, on the inner wall of the settler and in its \"dead zone\", on the protective covers of the leg valves, as well as on the secondary legs, the stripping section and the slurry inclined tubes, in the gas collection chamber of the settler and the reaction oil and gas pipelines, at the bottom of the distillation tower, and in the slurry circulation system must be thoroughly removed to ensure that no loose coke residues remain. 3.5.2 Enhance the insulation of large oil and gas pipelines; ensure that the exposed areas at the oil and gas inlets of the fractionation towers, as well as the manholes used for coking removal, are properly insulated after maintenance, so that the temperature drop in these large oil and gas pipelines does not exceed 5°C. 3.5.3 Pay attention to the quality of nozzle installation; the maximum error in the horizontal plane shall not exceed ±2mm. 3.5.4 Before concluding the equipment maintenance, a thorough inspection must be carried out to ensure that there are no foreign objects in the nozzles, no foreign objects in the cyclone separator, and that the material legs are unobstructed; only then can the access holes and manholes be sealed. 3.5.5 The unit before the oil and gas enter the distillation tower should be equipped with rain protection facilities to prevent leaks ； Ensure unobstructed flow of anti-scorching steam. 3.6 Production Operations 3.6.1 Ensure the stable operation of the unit, minimize the number of times reaction feed is interrupted and catalyst fluidization is halted, and avoid large fluctuations in the temperature of the settler. 3.6.2 Ensure proper commissioning of the unit, appropriately extend the fluidization time in the two reactors, ensure that the temperature inside the settler is consistent with the temperature at the outlet of the lift pipe, and only when the temperature at the outlet of the lift pipe is not lower than 500°C can oil injection into the lift pipe be initiated. 3.6.3 During the startup fuel injection and restoration operations, the feed to the nozzles must be injected symmetrically to ensure uniform flow rates of raw material and atomizing steam for all nozzles, thereby preventing uneven flow ； Furthermore, from the moment fuel injection begins in the riser until the feed rate reaches the level corresponding to normal operating conditions, it is necessary to maintain the temperature at the riser outlet above that of normal production. 3.6.4 The wax oil catalytic cracking unit must be appropriately modified before it can be used for blending with residue; it is prohibited to solely pursue short-term benefits by increasing the proportion of residue used in blending. 3.6.5 For devices with excess compressor capacity, dry gas pre-boosting technology can be employed. 3.6.6 The bottom temperature of the catalytic fractionation tower for distillate oil should be controlled at ≤365°C, while the bottom temperature of the catalytic cracking fractionation tower for heavy oil should be controlled at ≤350°C. 3.6.7 Adjust the reaction depth according to the properties of the raw materials, and control the slurry density (1030–1050 kg/m3). 3.6.8 The slurry scale inhibitor is continuously injected from the start of operation of the unit. 3.6.9 The solid content of the slurry shall not exceed 6 g/l. 3.6.10 The control valve for the thermal bypass temperature of the slurry steam generator shall remain fully closed during normal operation. 3.6.11 When switching the slurry pump, wait until the standby pump is operating properly before making the switch to prevent vacuum formation. 3.6.12 Strengthen seal oil management to prevent water in the seal oil from causing the slurry pump to run dry. 3.7 Equipment Operation 3.7.1 The nozzles are arranged symmetrically in an even-numbered plane, so that the oil streams converge at a 360° axis. 3.7.2 Guide rings can be added to the outer wall of the riser pipe. 3.7.3 Add anti-coking grills to the transition section of the settler. 3.7.4 The outlet of the raw slurry inclined tube is located in the cylinder, with the grid placed vertically ； A coking grid shall be installed at the inlet of the raw riser. 3.7.5 Critical equipment such as the main fan units and pressure enhancement units shall be equipped with dual power supply. 3.7.6 Ensure the quality of steam for the main fan unit and the main oil pump of the air pressure unit; if the steam quality fluctuates significantly and this affects the proper operation of the main oil pump, the auxiliary emergency oil pump shall operate simultaneously with the main oil pump. 3.7.7 Based on the service life of the nozzles and the results of inspections during maintenance, nozzles that are worn or clogged must be replaced; it is strictly prohibited to use nozzles beyond their designated lifespan. 3.7.8 Strengthen equipment maintenance and management; for key equipment such as main fan units, air pressure units, pressurization units, regenerative slide valves, standby slide valves or plug valves, double-acting slide valves, and slurry pumps, implement a comprehensive special maintenance system that integrates mechanical, electrical, instrumentation, piping, and operational aspects. 3.7.9 Improve the management of utility systems to ensure a stable supply of water, electricity, steam, and air to the equipment in accordance with the process requirements. 3.7.10 The slurry pump is provided with 200% redundancy. 3.7.11 Each set (unit) of the slurry steam generator and the heat exchangers in the slurry system shall be able to be isolated for maintenance separately, with a sufficient margin ensured. 3.7.12 For nozzles used for the separate reprocessing of slurry oil and reprocessed oil, high-efficiency nozzles must be employed; obsolete old-type nozzles such as target nozzles and throat nozzles are prohibited. 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Ye Xiaodong, Xu Wuqing, Liu Jingxiang. Analysis of coking causes in RFCCU units with different structures and preventive measures. 9th Annual Conference on Catalytic Cracking. Zhai Wei et al. Controlling equipment coking to ensure long-term operation of heavy oil catalytic cracking units, Petroleum Processing and Chemical Engineering, Volume 34, Issue 8. Ma Bowen. Technical Q&A on catalytic cracking units. Zhang Hongxing. Technical measures to prevent coking in catalytic cracking units for vacuum residue. 8th Annual Conference on Catalytic Cracking. Lin Shixiong. Petroleum Refining Engineering (3rd Edition). Petroleum Industry Press. Wang Wenqing et al., Causes of Coking in Heavy Oil Catalytic Cracking Units and Countermeasures. Refining Engineering and Technology