182-Leaf separator used as a coking prevention solution for the mesh separator at the inlet of the dry gas compressor in the mixed dehydrogenation unit of the olefin project

In the mixed dehydrogenation unit of the olefin plant, the dry gas is treated through absorption, and then sent to an alkaline wash tower for acid removal. The dry gas emerging from the alkaline wash tower proceeds to a dry gas compressor to be pressurized before being sent to downstream processes. Many companies have reported that dry gas compressors suffer from frequent coking, which affects their normal operation, results in a reduced gas delivery volume and insufficient discharge pressure, and leads to high maintenance costs for these compressors.

The owners have been reporting this issue to the design institute and the process package supplier. The response was that the vast majority of dry gas compressors suffer from coking problems. The process package supplier UOP also responded to the owner, confirming this common problem, and explained that there was an issue with the \"dryness\" of the gas entering the compressor; as a result, the \"dry gas\" carried alkaline liquid droplets, heavy aromatics, and their saponifications into the compressor, where these substances caused coking at high temperatures. The more alkali mist, aromatics, heavy oils, and saponifies that enter the dry gas compressor, the greater the coking and damage that occur within it.

Some companies have reported that for their dry gas exhaust gases and VOCS treatment systems, the regenerated gas obtained through adsorption is also pressurized using compressors. The compressors used for pressurizing this regenerated gas are the same as those used for handling dry gas; coking occurs frequently within these compressors, leading to damage and shutdowns. This results in high costs and extensive maintenance efforts required for the compressors, and the frequent malfunctions of these compressors affect normal operations.

After discussions with the design institute and patent holders, the owners concluded that the dry gas coming from the pretreatment process contained excessive amounts of washing oil and heavy diesel, had a high aromatic content, and also included acidic gases such as hydrogen sulfide and hydrogen chloride. It is necessary to remove the liquid hydrocarbons carried by the dry gas using a high-performance liquid separation tank installed at the inlet of the alkali scrubber; otherwise, the entry of these liquid hydrocarbons into the alkali scrubber not only significantly affects the efficiency of the scrubbing process, but also causes the liquid hydrocarbons to react with the alkaline solution to form large amounts of soaps that remain suspended on the surface of the liquid. This leads to foaming, and as a result, the dry gas exiting the top of the alkali scrubber contains alkaline solution, soaps, aromatic hydrocarbon foams, and other substances, which then end up in the dry gas compression process. The design firms and patent holders also require the owner to install a high-performance gas-liquid separator at the top of the alkali scrubber, in order to remove the alkaline solutions, saponifications, and aromatic foam carried by the airflow at the top of the scrubber. This prevents these substances from being carried by the dry gas into the dry gas compression process. More importantly, to protect the compressors that will operate at high speeds later on, design firms and patent holders emphasize that the owner should install high-performance gas-liquid separators at the inlet of the dry gas compressors, replacing traditional wire mesh demister coagulators. This is done to prevent excessive amounts of alkaline solutions, saponifications, aromatic foams, and other substances from entering the compressors during fluctuating operating conditions, thereby avoiding coking. It is important to remind everyone to pay close attention to \"saponates\"; they are a type of high-carbonate substance that not only causes foaming but also leads to scaling, which can clog traditional separation components such as screens, packing, filter media, and filter elements.

This post was last edited by luoli519 on 2021-4-7 at 10:30. Here, we discuss the technical upgrade of the original inlet mesh demister-coalescer in the dry gas compressor, with the owner suggesting that Novellus Energy Technologies’ vane separator be used. The attached figure shows the dimensions of the original inlet mesh demister coalescer for that dry gas compressor.

This post was last edited by luoli519 on 2021-4-7 at 10:31. The original inlet liquid separation tank for the owner’s dry gas compressor did not have any gas-liquid pre-distribution internals; instead, a wire mesh demister and coalescer with a height of 150 mm was installed throughout the upper part of the tank, along the radial direction of the shell, in a bottom-mounted configuration. The owners added that the liquid separation tank at the inlet of their caustic scrubber is also a traditional, simple mesh-type demister and coalescer of similar design, and the top of the caustic scrubber is equipped with a mesh demister of a traditional, simple structure as well. The following diagram is the installation diagram of the original inlet mesh demister coalescer for this dry gas compressor, provided by the owner.

As the dry gas carries washing oil, heavy oils, and other aromatics into the alkali scrubber, a large amount of saponified alkali is formed and floats on the surface of the alkaline solution, leading to foaming. This results in the accumulation of saponified alkali in the wire mesh demisters located at the upper part of the scrubber as well as in the wire mesh demister-coalescers installed at the inlet of the dry gas compressor, thereby blocking the flow channels within these wire mesh components. Frequent occurrences of \"liquid flooding\" and \"liquid surges\" lead to a significant reduction in the separation efficiency of these components, or even to a loss of their separation capacity, resulting in poor exhaust flow. In a clogged mesh element, pressure builds up due to the gas flowing in from upstream, while a vacuum is created downstream by the compressor. This combination of high pressures on both sides causes the clogged mesh to be torn into pieces, which are then drawn into the compressor and cause damage there. The image below shows a clogged screen under similar operating conditions, torn apart by the high pressure difference from both sides, for everyone’s discussion:

As can be seen from the diagram of this wire mesh demister coalescer shown on the 6th and 7th floors, its diameter is only 900 mm. So what are the corresponding operating conditions? The operating condition data provided by the owner are as follows: 1. Dry gas flow rate: the normal operating flow rate is 19,000 Nm^3/h, and the maximum operating flow rate is 21,000 Nm^3/h. 2. Gas phase composition: mainly hydrogen, accounting for 93.4% (mol), carrying alkaline water, washing oil, heavy diesel, and their saponified products, along with foam. 3. Operating temperature: 52°C. 4. Operating pressure: 0.32 MPa.

This post was last edited by luoli519 on 2021-4-7 at 10:32. The schematic diagram showing Novail Energy Technology Company’s upgrade plan for the original inlet mesh demister-coalescer of this dry gas compressor, using a vane separation inlet assembly and precision vane separation internal components, is as follows:

As can be seen from the schematic diagram of the original liquid separation tank at the inlet of the dry gas compressor, which has been upgraded using the vane separator technology as shown on the 10th floor, the technical upgrades were carried out primarily on the following key internal components, while making use of the existing shell structure of the original liquid separation tank and leaving its pipe connections unchanged: First, a G50B-1 type vane separator inlet assembly was installed at the end of the pipe leading to the dry gas inlet of the liquid separation tank； II. Install the G50D type pre-allocated coalescing internal component set ； III. Install G50P4/6 type precision vane separator ； IV. Install the G50LD type anti-siphon short-circuit liquid-level reducing internal component set.