Sour water: where it comes from and how to handle it
Sour water strippers are common in gas processing facilities, sulphur recovery units, wellhead facilities, and refinery applications. Understanding the variables allows engineers to better optimise the initial design and operation.
Dr. Ing. Mariana Siwek, Verfahrenstechnik und Automatisierung GmbH
Luke Addington, Carl Fitz, Kevin Lunsford, and Lili Lyddon
Bryan Research and Engineering
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This paper reviews options for sour water stripper configuration and presents a method to optimise stripper operation by finding the most efficient operating parameters. Options investigated include: single or double column for increased product purity; addition of acid or caustic for improved performance; refluxed or non-refluxed columns to mitigate water in the overhead gases; condenser or pumparound and their effects on overhead composition; reboiler, direct steam injection, or a combination of these and the effect they have on corrosion concerns. In addition, optimisation of the steam rate is investigated. Overall stage efficiency for trayed strippers, HETP for packed strippers and individual component efficiencies are discussed based on available sour water stripper operating data.
Sources of sour water Gas processing
Water is the single largest waste stream in oil and gas production worldwide. Wastewater streams come from a variety of sources, the largest of which is associated or production water. Other sources of wastewater include water used during startup and industrial hygiene, purge water from amine sweetening units (ASU), and wash water used in the tail gas treating section (TGTU) of the sulphur recovery unit (SRU). Of these sources, associated water is the largest in total volume; however, the latter two are the largest sources of sour water.
Water always exists in oil and gas reservoirs, often sitting towards the bottom of the production zone. While production may be relatively dry at the beginning of a field’s life, water-to-hydrocarbon ratios will increase over the life of a well as hydrocarbons are depleted and water begins migrating upwards to areas of production. The United States averages around ten barrels of associated water per barrel of oil produced1.
There are a variety of impurities found in this associated water, such as oil and grease, suspended solids, BTEX/VOCs, as well as sulphur and ammonia. Table 1 lists the concentration of typical contaminants in associated water from sources in the Gulf of Mexico2 and in Pennsylvania3. Notice that the largest concentration of contaminants is the suspended solids while the smallest is typically sulphur species and ammonia, those components typically removed in a sour water stripper.
As a waste stream, associated water is disposed of in a variety of ways, depending on the production site’s geographical location, geological concerns, the types of contaminants in the water, and whether production is onshore or offshore. The overwhelming majority of associated water is reinjected into either the production reservoir for Enhanced Oil Recovery (EOR) or into depleted or unused underground reservoirs. As much as 95% of onshore associated water is disposed of in this way4. The implication is that although associated water is a huge waste, much of it is minimally treated and readily disposed of back into reservoir rock.
The remaining uninjected associated water is either used beneficially or disposed of on the surface in evaporation ponds. Beneficial uses include agricultural use when circumstances allow, such as US onshore reservoirs that produce water with a low salt content and lie west of the 98th meridian5. Some water is also treated and reused in gas processing facilities6. Evaporation ponds, as a means of onshore disposal, are falling out of favour due to the additional processing needed and environmental concerns such as salt contamination of surface soil and erosion7. Table 2 provides a summary of US onshore associated water disposal practices.
Offshore water disposal practices for associated water vary from onshore practices. Drilling injection wells and setting up the infrastructure to get the produced water from the platform back to the injection site can be cost prohibitive, so associated water is not typically reinjected offshore4. Some production water is treated and reused; however, the majority is simply treated and discharged into the sea1. The primary contaminants of concern for this discharged water are suspended solids, oil, and BTEX/VOCs. Removal of these contaminants, by means of coalescers or degassing units, often results in the by-removal of any sour components. This wastewater, therefore, does not need to be introduced to a sour water stripper. The net result is that the primary source of sour water being sent to sour water strippers in upstream applications is not comprised of associated water.
In rare cases, amine sweetening units in upstream applications may be sources of sour water. In most cases, the sweet gas temperature is higher than the inlet gas temperature due to absorption of acid gas components in the absorber. The increase in gas temperature results in water actually being removed from the amine solution. If, however, the sweet gas temperature is lower than the inlet gas temperature, water may actually build up in the amine solution and be removed from the sour liquid condensate in the amine regenerator. This could occur if the inlet gas contains little acid gas and the lean amine solution is at a lower temperature than the inlet gas.
Quench systems for sulphur recovery unit tail gas are the primary source of sour water in upstream applications. Hydrogenating tail gas units, such as Shell’s SCOT system, are often used to improve the overall removal efficiency of SRUs. In these systems, any sulphur remaining in the tail gas is converted to H2S where it is subsequently removed in an amine plant and recycled back to the sulphur burner. Before the hydrogenated tail gas can be fed to the amine absorber, it must first be cooled, typically with a water quench system. This quench system produces a wastewater stream containing primarily H2S, but potentially NH3 as well.
There are more sources of sour water from refining than there are in gas processing applications. These sources include distillation, wash systems, water from knockouts and amine systems. The largest source of sour water, as indicated in Table 3, is from the steam stripping of the crude in the atmospheric and vacuum tower processing units. Fluidised catalytic crackers (FCC), hydrodesulphurisation units (HDS) and hydrocrackers also generate a substantial amount of sour water. The byproduct water contains H2S, NH3, phenols and possibly HCN8. Note that, while the Claus process is one of the largest producers of sour water in gas processing, it accounts for less than 2% of that generated in a refinery.
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