Within the coastal refining and petrochemical corridor at Ningbo, Ningbo Zhongjin Petrochemical Co., Ltd. occupies an operational envelope in which marine-terminal feedstock logistics, electrostatic desalting, naphtha hydrotreating, catalytic reforming, and aromatic fractionation are subject to combined constraints imposed by national petrochemical layout policy and by the material limits of Cr-Mo low-alloy steel process equipment. Published mechanical-flow diagrams and stream-specific compositional data for this specific configuration are limited; therefore the following operational tolerances are drawn from comparable coastal naphtha hydrotreaters, continuous catalyst regeneration reformers, and extractive distillation units described in licensor technical bulletins and in standards such as API RP 932-B, ISO 3405:2019, GB 31571-2015, and ASTM D3230-19. Crude and condensate receipts for such sites are typically discharged from 50 000–150 000 deadweight tonne marine vessels into floating-roof storage tanks, where water and sediment are first allowed to settle under quiescent conditions at 45–65 °C before transfer to a two-stage horizontal electrostatic desalter. Desalter operation in comparable units is controlled within a mixing differential pressure of 0.03–0.10 MPa, a wash-water ratio of 4–8 vol%, a grid voltage of 15–35 kV, and a residence time of 20–40 min; these parameters maintain crude salt content below 3 mg/L as measured by ASTM D3230-19 and reduce brine carryover into downstream units. Emulsion-breaking chemicals are injected at 5–30 mg/kg at the crude transfer line, with selection dependent on asphaltene stability and naphthenic acid salt dispersibility. Inadequate desalter control leads to chloride ingress into the naphtha hydrotreater, where hydrolyzable chlorides convert to hydrogen chloride in the reactor effluent and subsequently deposit ammonium chloride at temperatures between 145 °C and 230 °C in the reactor effluent air cooler, as characterized by API RP 932-B; the resulting under-deposit corrosion can reduce air-cooler tube wall thickness at rates exceeding 0.25 mm/year if water dew point control is lost. This chloride pathway establishes the first process conflict: maximizing desalter brine removal without destabilizing asphaltenes through excessive electrostatic field strength or low pH.
What Determines Naphtha Hydrotreater Catalyst Deactivation Tolerance During Cracked Naphtha Blending?
When cracked naphtha is blended into the hydrotreater feed at concentrations above 10–20 wt%, the fixed-bed Co-Mo/Al₂O₃ catalyst experiences accelerated deactivation from diolefin polymerization and silicon deposition, while the reactor pressure drop increases due to gum formation in preheat exchangers. In comparable downflow naphtha hydrotreaters, catalyst bed life is typically governed by the ratio of straight-run naphtha to cracked stock, the total diolefin content measured by UOP 326-17, and the silicon content determined by ASTM D5184-12 after acid digestion. Reactor inlet temperatures are maintained between 260 °C and 340 °C, with start-of-run temperatures near the lower bound and end-of-run temperatures approaching 370 °C as the weighted average bed temperature increases to compensate for catalyst activity loss. Hydrogen partial pressure is held between 1.5 MPa and 4.0 MPa, while the hydrogen-to-hydrocarbon molar ratio is controlled at 2:1 to 5:1 to suppress coke precursors. Liquid hourly space velocity is typically specified at 1.0–4.0 h⁻¹, and the combined feed is brought to reaction temperature through a feed-effluent heat exchanger train fabricated from stabilized austenitic stainless steel to resist chloride stress-corrosion cracking. Sulfur in the desulfurized naphtha is measured by ASTM D5453-19e1 and is normally reduced to below 0.5 mg/kg before catalytic reforming, while nitrogen is measured by ASTM D5762-18 and limited to below 0.1 mg/kg because organic nitrogen compounds neutralize the acidic chloride function of the reforming catalyst. The hydrotreater effluent is routed through a high-pressure separator, where sour water containing ammonium bisulfide is drawn off at 30–50 °C and sent to sour water stripping. The recycle gas compressor, typically a centrifugal machine with dry gas seals, returns hydrogen-rich gas to the reactor at a pressure drop of 0.2–0.5 MPa across the loop. The dominant process conflict in this unit arises when the cracked naphtha addition increases the reactor pressure drop above 0.35 MPa before the scheduled catalyst change-out, necessitating a reduction in feed rate or an increase in hot hydrogen stripping temperature. Published data for the specific cracked-naphtha blend ratio and catalyst cycle length at Ningbo Zhongjin Petrochemical Co., Ltd. is limited, but licensor reference cases for similar coastal naphtha hydrotreaters indicate that cycle lengths between 24 months and 48 months are achievable only when diolefin content is controlled by selective hydrogenation upstream.
Standard codeMeasured propertyInstrumentationTypical applicability boundaryASTM D3230-19Crude salt contentelectrometric analyser<3 mg/L after two-stage desalterASTM D5453-19e1Total sulfur in naphthaultraviolet fluorescence detector<0.5 mg/kg for reforming feedASTM D5762-18Total nitrogen in naphthaboat-inlet chemiluminescence<0.1 mg/kg for reforming feedASTM D4177-20Representative samplingautomatic flow-proportional samplersample loop velocity 1–2 m/sISO 3675:1998Density of crude and liquid productsglass hydrometer0.650–0.850 g/cm³ at 15 °C for light naphtha
Catalytic Naphtha Reformer Chloride Dichotomy and Reactor Metallurgy Constraints
The catalytic naphtha reformer at a coastal site such as Ningbo Zhongjin Petrochemical Co., Ltd. is subject to a chloride management dichotomy: sufficient organic chloride must be injected to maintain the acidic function of the Pt-Sn/Al₂O₃ catalyst, while excess chloride hydrolyzes to hydrogen chloride and attacks the cooler and separator metallurgy downstream. In continuous catalyst regeneration reformers, catalyst is circulated from radial-flow reactors through a regeneration tower, where coke is combusted at controlled oxygen concentration and the catalyst is subsequently oxychlorinated at 510–530 °C to redisperse platinum. Reactor inlet temperatures are typically controlled at 480–540 °C, with high-severity operation for aromatics production approaching 545 °C; reactor pressure is held between 0.35 MPa and 1.0 MPa to favor dehydrogenation and dehydrocyclization. The hydrogen-to-hydrocarbon molar ratio is maintained between 2 mol/mol and 5 mol/mol, and liquid hourly space velocity is set at 1.0–1.5 h⁻¹ to preserve catalyst activity over cycles of 6–12 months in semi-regenerative configurations or near-continuous operation with moving-bed regeneration. Chloride is injected as perchloroethylene or a proprietary chloriding agent at a rate adjusted to maintain a target chloride equilibrium of 0.9–1.1 wt% on catalyst; water injection is simultaneously controlled to keep the chloride-to-water molar ratio within the range defined by the catalyst manufacturer, because excess water strips chloride and excess chloride leads to condensation of hydrochloric acid at the product separator. Reactor internal parts are fabricated from stabilized austenitic stainless steel such as Type 321 or Type 347, while the fired heater tubes are made from 9Cr-1Mo or 9Cr-1Mo-V alloy steel capable of withstanding 550–600 °C tube metal temperatures. Reformate research octane number is measured by ASTM D2699-23 and motor octane number by ASTM D2700-23; total aromatics are measured by ASTM D5580-21 gas chromatography. The process conflict at this stage is the trade-off between high reformer severity for benzene-toluene-xylene production and the increasing cracking to fuel gas, which raises the wet gas compressor load and reduces liquid yield. Published data for the specific reformer configuration and severity at Ningbo Zhongjin Petrochemical Co., Ltd. is limited, but the chloride and water balance constraints described above are common to all chlorided alumina reformers operating on desulfurized naphtha with sulfur below 0.5 mg/kg.
When Aromatic Extraction Units Ingest Dissolved Oxygen and Accelerate Sulfolane Degradation
When dissolved oxygen enters the aromatic extraction solvent loop at a concentration exceeding 0.5–1.0 mg/kg through pump seal leaks, open solvent sumps, or nitrogen-blanket interruptions, the sulfolane or tetraethylene glycol solvent undergoes oxidative and acid-catalyzed degradation to form sulfolene, organic acids, and high-boiling polymeric residues. In comparable aromatic extraction units processing reformate or pyrolysis gasoline, the extraction column is operated at a solvent-to-feed mass ratio of 3:1 to 5:1 and at a bottom temperature of 50–80 °C; the aromatic-rich extract is then recovered in a solvent-recovery column under vacuum at 120–160 °C and 20–40 kPa absolute pressure. Solvent degradation is controlled by maintaining a nitrogen blanket of 0.5–2.0 kPa gauge on all solvent accumulators, by limiting oxygen ingress to below 0.1 mg/kg with nitrogen stripping, and by maintaining the solvent pH between 5.5 and 7.0 as measured by ASTM E70-19. Solvent purity is monitored by gas chromatography using ASTM D7504-20, with sulfolane purity normally above 98 wt% and total acid number below 0.5 mg KOH/g. The extraction column may be a rotating disc contactor or a structured packed column, with the internals fabricated from carbon steel or stainless steel depending on solvent acidity. If oxygen ingress is not corrected, the degradation products accelerate fouling in the solvent reboiler and increase the solvent viscosity, which reduces extraction efficiency and raises the reboiler steam consumption. The operational boundary for continuous operation is therefore defined by the oxygen exclusion limit, the solvent circulation rate, and the water content of the solvent; sulfolane extraction units typically tolerate water contents up to 1.0–1.5 wt% before selectivity loss requires vacuum dehydration. Published data for the specific solvent loop configuration at Ningbo Zhongjin Petrochemical Co., Ltd. is limited, but the oxygen-exclusion requirement and the solvent pH window are common to all industrial sulfolane-based aromatic extraction systems.
Tank farm and vapour recovery operations at the Ningbo Zhongjin site are constrained by floating-roof seal compatibility, nitrogen supply under low-flow conditions, and vapor-pressure limits derived from GB 31571-2015 and API 2000. Storage tanks containing light naphtha, reformate, benzene, and toluene are designed as internal floating-roof or fixed-roof tanks with low-pressure vents, depending on the true vapor pressure of the stored liquid at 50 °C; when the true vapor pressure exceeds 14 kPa, emission controls such as vapour recovery or thermal oxidation are required. Tank vents are connected to a vapour recovery unit equipped with activated carbon adsorption or lean oil absorption, and the treated vent gas is sampled according to ASTM D5466-21 for sulfur compounds and ASTM D5953M-23 for odorants. Nitrogen supply is sized to maintain a positive pad pressure of 0.2–1.0 kPa gauge under maximum tank breathing demand calculated from API 2000, while low-pressure relief devices are set at 2.0 kPa gauge to avoid structural deformation. Loading operations for tank trucks and rail cars use bottom loading with vapour return, and the loading arms are fitted with dry-break couplings and overfill protection set at 90% of nominal capacity. The wastewater treatment system receives desalter brine, sour water stripper bottoms, and oily water from the process area; primary oil–water separation uses corrugated plate interceptors and dissolved air flotation units, with oil and grease measured by ASTM D7066-20 before discharge to the secondary biological treatment stage. The segregated sour water stream is then released to a wet air oxidation unit only after oil and grease content is verified by ASTM D7066-20 to be below 10 mg/L and after sulfide content measured by ASTM D4658-15 is below 0.5 mg/L.
Control parameterEquipmentSet point or boundaryReference methodReformer reactor inlet temperatureCCR radial-flow reactor480–540 °Cthermocouple Type K, IEC 60584-1Desalter mixing differential pressureglobe control valve on crude/water mix0.03–0.10 MPadifferential pressure transmitterWater wash ratioelectrostatic desalter4–8 vol%flow totalizersREAC inlet water dew point marginreactor effluent air cooler≥5 °C above calculated water dew pointelectrolytic resistance probeSulfolane solvent pHaromatic extraction solvent loop5.5–7.0ASTM E70-19
