Introduction
The first phase of a large-scale coal-to-natural gas project in China features two 48,000 m³/h air separation units, primarily providing qualified oxygen, nitrogen, and utility air for the entire plant. These units were designed and manufactured by Hangzhou Oxygen, with construction and installation completed by Sinopec No. 10 Company. The units utilize a liquid oxygen internal compression process, and the air compressor units comprise an air compressor, steam turbine, and booster. On September 5, 2011, a series of steam turbines successfully completed individual commissioning, and on November 6, the air compressor units completed a combined commissioning. After surge testing, all performance indicators met design requirements. During the three-month commissioning process, numerous design and operational issues were encountered. However, through the concerted efforts of all commissioning personnel, these issues were resolved one by one. The following is a summary of the issues encountered during the commissioning process for your reference.
Main Steam System
Main Steam Line Flowmeter Impacts Purge Time
When developing the main steam pipeline purge plan, considering the long manufacturing cycle for the quick-closing valve purge plug, a temporary purge line was installed at the last elbow of the main steam pipeline, bypassing the quick-closing valve. Key plan details included: argon arc welding for priming to ensure a smooth internal surface; pickling and sandblasting of the riser pipe approximately 3 meters from the last elbow to the quick-closing valve; and cold cutting and manual cleaning, as well as endoscope inspection, during removal of the temporary purge line to ensure cleanliness. However, during the actual purge, the turbine flowmeter between the main steam gate valve and the quick-closing valve had not yet arrived, so the decision was made to purge this section of pipeline first. After the purge was complete, the steam flowmeter would be installed and inspected using the aforementioned method. One week after the main steam pipeline was purged, it passed the hot and cold target test. When removing the temporary purge pipe to install the flowmeter, concerns about secondary contamination of the pipe led the foreign experts to offer two options: one was to install only the piping upstream of the quick-close valve without installing the flowmeter, then conduct a test run of the unit. After the unit was fully handed over, the flowmeter would be installed as needed. The other was to install the flowmeter but retain the temporary purge pipe temporarily, continue the purge, and remove the temporary purge pipe after passing the target test, then reinstall the piping upstream of the quick-close valve. Ultimately, the purge was continued after installing the flowmeter, which increased the purge time by approximately one week.
(2) Failure to implement steam isolation measures nearly resulted in a steam-related injury accident
The company's steam system utilizes a main pipe system. Following the power high-pressure steam boundary valve is a high-pressure steam main pipe. This main pipe is connected in parallel to an 8.5MPa high-pressure steam main pipe for air separation, purification, and methanation, as well as 5.0MPa, 2.0MPa, and 0.8MPa steam desuperheating and pressure reduction systems. After the main steam pipeline of the ASU was purged, the high-pressure steam boundary valve was closed, and the ASU began to reinstall the pipeline upstream of the quick-closing valve. To prevent residual pressure in the pipeline, the main steam gate valves in the first and second series of the ASU were fully opened, and the main steam drains along the pipeline were fully opened. However, while the foreign experts were checking the alignment and clearance between the main steam pipeline flange and the large steam flange of the quick-closing valve, water and steam suddenly emerged from the steam flange. Fortunately, no one was injured. Later investigation revealed that the gasification system was undergoing a 5.0MPa steam purge. This near-miss serves as a reminder to ensure unified coordination and command during initial startup to avoid safety accidents during cross-commissioning. Furthermore, when inspecting equipment and pipelines handling hazardous media such as high-temperature, high-pressure, flammable, explosive, and toxic media, it is imperative to ensure system isolation and confirm blind plates to eliminate major safety hazards at the source.
Lubricating Oil System
Oil Cooler Impacts Oil Cleaning
During the oil cleaning process for the air compressor unit, extracorporeal circulation is first performed. This involves short-circuiting the upper oil pipe and the return oil pipe with a hose, adding a filter to the upper oil pipe connection, and starting the lubricating oil pump to circulate for 4-6 hours. The filter is then removed for inspection. However, more than a month after the oil system was cleaned, the filter was removed for inspection and black, hard particles were discovered. Analysis suggested that the oil cooler had been on-site for an extended period, causing oxidation and rusting inside the heat exchanger housing, which had been carried into the pipes by the lubricating oil. Disassembly and inspection of the oil cooler revealed significant rust on the housing. Measures were taken, including high-pressure water jet flushing, air drying, and sandblasting of the housing. After this treatment, the oil pump was started, and after 3-4 cycles of flushing, the oil quality was found to be acceptable.
Cleaning the lubricating oil tank caused secondary contamination of the lubricating oil.
After the lubricating oil system was flushed, the lubricating oil was pumped out and cleaned. After verification by the engineering department, the supervision company, and the air separation plant, the lubricating oil was refilled. However, sampling and analysis after the refilling revealed that the water content in the lubricating oil had increased from 78 × 10⁻⁶ before cleaning to 680 × 10⁻⁶, which did not meet the oil quality standards. Therefore, the vacuum oil filter inlet was connected to the drain valve at the bottom of the oil tank, and the outlet was connected to the fill port at the top of the tank. The vacuum oil filter was then turned on to circulate and filter the lubricating oil in the tank. Sampling and analysis three days later revealed that the water content in the lubricating oil had returned to the standard of less than 160 × 10⁻⁶. Subsequent analysis determined that the primary cause of the secondary contamination was rainwater entering the lubricating oil drums while they were stored outdoors. The lubricating oil was then pumped into the water-filled drums, causing secondary contamination.
Air Cooling Island and Condensate System
The air separation unit primarily consists of six variable-frequency fans, two condensate pumps, two drain pumps, a hot well, a flash tank, a condensate tank, and connecting piping. The process flow is as follows: exhaust steam from the turbine enters the air-cooled downstream tube bundle through the exhaust manifold for heat exchange. Condensate is collected in the lower header and then piped to the condensate tank. Non-condensable gas is sent to the exhaust pump through the air pipe at the top of the countercurrent tube bundle. After pressurization, the condensate exchanges heat with steam from the exhaust cooler in the exhaust cooler. It is then split into two paths: one path returns to the condensate tank through the condensate return valve (LV814) to maintain a stable liquid level, and the other path is sent to the condensate network through the condensate outlet valve (LV815). Turbine exhaust steam and condensate from the exhaust manifold are collected in the hot well and returned to the condensate tank via the variable-frequency drain pump.
Condensate Pump Motor Current Exceeds Rated Current
During the condensate pump commissioning process, LV815 was fully closed and LV814 fully opened to start the condensate pump. The outlet valve was then slowly opened. When the outlet valve was opened approximately four turns, the condensate pump motor current reached 200A (rated current 210A). Repeated tests failed to resolve the motor current exceeding rated current issue. After analysis, when selecting the pump, the resistance of the peripheral pipeline was considered to be 110mH₂O, and the 200NB-110 pump was selected (its performance curve is shown in Figure 1). That is, when the resistance after the pump reaches 110mH₂O, the pump flow rate reaches its design value (the vertical dotted line in Figure 1). When the resistance after the pump is less than 110mH₂O, the pump flow rate will increase and its power will increase accordingly. When the flow rate reaches 215t/h, the resistance after the pump is 103mH₂O and the motor power is 110kW. When the resistance after the pump is further reduced, as the flow rate increases, the motor power will exceed its design value, and the pump motor will be overloaded. Therefore, a throttling orifice was added between the condensate pump return line and the condensate tank inlet. The orifice has a flow area of 0.00255 m², a throttling orifice diameter of 57 mm, and a thickness of 10 mm. The calculated flow rate is 80 t/h. After the condensate pipeline modification, the condensate pump was started. When the outlet valve was opened to 50%, the condensate pump motor current was 90A. When the outlet valve was fully open, the condensate pump motor current was only 130A.
The main vacuum extractor failed to maintain vacuum during operation in the first and second stages.
During the compressor interlock test run, after reversing the main vacuum extractor (using the first and second stages), it was discovered that vacuum could not be maintained.
The vacuum pressure (absolute pressure, the same below) rose from 13kPa to 20kPa. The vacuum pressure continued to rise to 30kPa and showed signs of continuing to rise after reversing the main vacuum extractor. To ensure safe operation of the unit, the start-up vacuum extractor was re-activated, and the vacuum pressure quickly dropped to 13kPa. After the test run, the inlet filters and nozzles of the two main vacuum extractors were opened and inspected. No debris was found, indicating that the main vacuum extractors were not clogged and were operating normally. Analysis showed that the operation of the start-up vacuum extractor was related to the working steam pressure. Since the working steam of the start-up vacuum extractor does not condense, it was not related to the steam superheat temperature. The working steam pressure currently meets the design requirements, and the start-up vacuum extractor can be used normally. When the system establishes vacuum, exhaust steam from the turbine enters the condenser for condensation. Once the condensate system is operational, primary and secondary vacuum extractors are typically deployed. A significant difference between primary and secondary vacuum extractors and startup vacuum extractors is that the driving steam is not directly discharged but recovered through condensation. Their extraction efficiency is directly related to the condensation performance of the extraction cooler. Three factors influence the condensation performance of the extraction cooler: the cooling water inlet temperature; the working steam temperature; and the non-condensable gas flow rate (vacuum leakage from the turbine side). The design parameters for the steam ejector in this project are as follows: operating steam pressure of 1.5 MPa, temperature of 201°C (slightly superheated); cooling water inlet temperature of 69.1°C, outlet temperature of 70.5°C, flow rate of 118 t/h; and back pressure of 28 kPa. Let's first discuss the impact of cooling water temperature. During on-site commissioning, the condensate system's peripheral systems had not yet been established. The pump flow rate had already reached over 180 t/h, but only a portion of this water (tens of tons) was discharged. The majority of the water flowed through the return line into the condensate tank, where it then entered the exhaust cooler. The cooling water used to cool the steam primarily circulated in a closed circuit. When the primary and secondary exhaust coolers were operational, the cooling water's temperature rose after passing through the exhaust cooler, and the temperature rose further after passing through the closed circuit. As the operating time increased, the cooling water temperature continued to rise, and the system backpressure also gradually increased. Let's consider the impact of operating steam temperature. The exhaust cooler operates by first absorbing the sensible heat of the superheated steam and then absorbing the latent heat of the steam to condense it. Currently, because the turbine's intermediate-pressure seal steam and working steam are drawn from the same pipeline, the turbine's intermediate-pressure seal steam requires a superheat of 30K, causing the working steam temperature to reach 270°C, a severe overheat. Most of the heat exchange area of the extraction cooler is used to absorb the steam's sensible heat, severely affecting its condensation efficiency and, consequently, reducing its extraction capacity. Data collected from several test runs show that when the working steam temperature is relatively low (210°C, slightly superheated), the primary and secondary exhausters can operate normally and maintain system backpressure. However, when the superheat is excessive, they cannot operate normally. Therefore, to ensure the proper operation of the jet steam extractor, the working steam temperature must be lowered to approximately the design value.
Frequent clogging of the drain pump inlet filter
During the combined test run of the air compressor unit, when the turbine steam flow rate reached approximately 70 t/h, the drain pump began to malfunction, causing the hot well liquid level to continue to rise. After switching to standby operation, the liquid level briefly dropped before continuing to rise. Upon disassembly of the pump inlet strainer for inspection, it was discovered to be clogged with a large amount of rust and sludge. To maintain unit operation, personnel were assigned to frequently reverse the pump to continuously clean the strainer. However, even after the unit's commissioning, the exhaust main pipe had not been flushed clean, and the strainer remained clogged. Disassembly of the exhaust main pipe revealed a large amount of rust and sludge at the bottom of the main pipe and the hot well. Analysis revealed that the rust and sludge primarily originated from the exhaust main pipe. This was due to the air-cooling island not being hot-cleaned during commissioning. Rust, welding slag, and dust adhering to the inner wall of the exhaust main pipe were washed away by exhaust steam from the turbine and collected in the hot well with condensate. This rust, sludge, and rust were then continuously carried to the pump inlet by the drain pump, clogging the filter and causing the drain pump to malfunction.
