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High pressure vessel

Home Forums Coking Technical Fractionation & Process Process High pressure vessel

This topic contains 3 replies, has 2 voices, and was last updated by  Mike Kimbrell 3 years, 2 months ago.

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  • #28960

    Hedewandro Lucredi
    Participant

    Our DCU has a high pressure vessel in the gas recovery section that has a interface between sour water and hydrocarbons. This vessel operate at +/- 14 Kgf/cm2. Sometimes we have problem with the Level valve and its interface sour water control (plugging, etc) that can produce some control error (error in the indication level). In this case there is the possibility to send LPG with water to the SWS. How can I prevent this ? Two interface level control ? Add a XV in the sour water stream ? What are the typical configuration to avoid this possibility (send LPG with sour water to SWS Tank receiver) from the High pressure vessel?

  • #28989

    Mike Kimbrell
    Participant

    The situation you are describing is a classic high pressure to low pressure interface problem. Sour water and amine systems commonly have this problem. There are several other examples.
    The low pressure system typically has a degassing drum where any hydrocarbon vapors from the high pressure system can be separated from the liquid and where light liquid hydrocarbons can flash some vapor and be a separate layer in the degassing drum that can be removed and returned back to the process. The low pressure side should have adequate relief capacity installed to manage the highest single gas blow through event or any combined events that are caused by a single event. If the low pressure equipment does not have adequate relief capacity, then an instrumented system with a shut-off valve is required. The required number of instruments to make the instrumented system reliable is dependent on the size of the hazard that is being mitigated. I always like to have redundant level indication, one for control and one for back-up, that come into the DCS. In some cases three levels are needed with a two out of three voting logic to trigger the shut-off valve.
    A standard displacer style level transmitter can get stuck and read an incorrect level. This is particularly true if there are particulates in the liquid. Sour water often has corrosion products that can cause the displacer to stick. A standard differential pressure transmitter can provide good reliability in this service. Having the impulse tubing purged will increase the reliability. Using liquid filled diaphragm cells with sealed capillary tubing to the transmitter is another way to get reliable level readings. Both the displacer and DP cells are dependent on knowing the density of the liquid to provide and accurate level. Other style level transmitters, such as guided wave radar, are not dependent on density. Guided wave radar level transmitters give erroneous level information if there are solids or gas bubbles in the level chamber. No technology for level indication is perfect.
    If the primary concern is a process upset with routing LPG to the sour water system, using redundant level indication with a DCS interlock on low level would be a reasonable solution. A hazards analysis is needed to understand the potential severity of the incident you describe. Once that is known, the amount of redundancy can be determined.

  • #29004

    Hedewandro Lucredi
    Participant

    What about if we recycle the sour water to upstream of the top heat exchanger of the main tower ? In this case the sour water can be send to SWS using the fracionator top vessel ? What about the champagne effect (releasing of the contaminants by despressuring) and its effects in the recovery gás section (corrosion, amine degradation, etc) ?

  • #29005

    Mike Kimbrell
    Participant

    It is possible to use the main fractionator overhead accumulator as the degassing drum. You are correct in saying any dissolved gasses in the sour water will evolve at the lower pressure and become a recycle through the wet gas compressor and the primary absorber in the gas plant. This flashed gas flow rate is much smaller than the total wet gas flow, so I think the impact on amine degradation and corrosion will be small. As you know, a change like this should go through a Management of Change process that includes a process hazards review. The capability to route sour water from the overhead accumulator to the Sulfur Plant needs to be adequate for this increased water rate to prevent refluxing water back to the main fractionator.

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