Removing contaminants from crude oil
Natural and introduced contaminants limit crude desalting effectiveness, increasing fouling and corrosion risks in downstream units
JAMIE MCDANIELS and WOLE OLOWU
Athlon Solutions LLC
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Crude oil contains millions of components. Most components are natural, resulting from millions of years forming beneath the surface of the earth. Among these, saturates are carbon atoms linked together by single bonds. These can be long or short chains. The short chain saturates become lighter products produced from crude oil, such as butane, heptane, and octane. Longer chain saturates form wax, which can serve as a useful product but also contributes to both corrosion and fouling. Aromatics are benzene derivatives that are useful in boosting octane numbers in gasoline, but are limited due to their harmful effects on health and the environment. Resins are high molecular weight molecules that are readily soluble in oil, unlike asphaltenes, which exist in crude oil as a colloidal suspension.1 Asphaltenes are polyaromatic materials in heavy residues, characterised by not being soluble in aromatic-free, low boiling point solvents (such as heptane). They are soluble in carbon disulphide.2 This loose definition exists due to the complex nature of the asphaltene molecule. Asphaltenes are particularly problematic in regards to corrosion and fouling.
From first production to the refinery, crude oil is being contaminated. Many contaminants are naturally occurring, such as rock fragments, naphthenic acid, and salt water. Production fluids, H2S scavengers, and corrosion inhibitors, while necessary in the upstream and midstream, can be troublesome for refiners. Organic chlorides are sometimes used as a solvent in oil production sites and can contribute to corrosion and fouling at the refinery. Iron corrosion products picked up by crude oil in pipelines can lead to fouling problems. Zinc compounds found in reclaimed lubricants can create tight emulsions. Many of these contaminants can upset desalter operations, creating corrosion and fouling risks.3
Once crude oil arrives at refineries, the contaminants must be contended with by the plant. The quality of crude can vary shipment to shipment. If refineries are not prepared to deal with the contaminants in the crude, they can face serious consequences resulting from fouling and corrosion of process equipment. NACE International defines corrosion as “the deterioration of a material, usually a metal, because of a reaction with its environment”.4 Deteriorated equipment can cost a refinery a lot of money in replacement, reduced throughput, and shutdown time. A process leak can result in fire and chemical hazards, posing a catastrophic threat to personnel. Fouling’s consequences are similar to those of corrosion with costs including equipment cleaning and increased energy costs.5
Dealing with corrosion and fouling early in the refining process
Good desalting practices are important for corrosion and fouling control. There are several strategies to address crude contaminants before the desalter that also aid the desalting process.
Tank farm management
The tank farm is the first stop for crude oil once it reaches the refinery via rail, ship, truck, or pipeline. Crude oil in the tank farm will likely contain water with dissolved salts and solids. Crude tanks should be drained of water before the crude is charged to the unit. This addresses several problems: it reduces the salt contents in the raw crude charge, and it helps avoid slugs of water to the desalter. Water slugs will cause loss of level control and potentially send excess water containing salts into the crude tower. Too much water can increase tower pressure, usually resulting in backing out crude charge and sometimes blowing out trays and causing a forced shutdown. Crude tank switches should be feathered in over a couple of hours if possible and operated to minimise abrupt changes in feed quality.
Slop oil management
Often, refineries will blend slop oil waste into fresh crude charge to reprocess it. This practice should be limited because the waste and slop are laden with surfactants from around the refinery. The premise of desalting is to wash crude oil with water to remove contaminants and then separate the contaminated water from the dry, clean oil. A surfactant will reduce the surface tension between two fluids. By lowering the surface tension between two fluids (in the case of desalting – oil and water), they are allowed to mix together and become difficult to separate.
Best practices for treating slop oil are:
1. Remove surfactant laden solids via centrifuge before sending slop to the crude tank
2. Break any emulsion that has formed in the slop and separate the oil from the water before sending the oil to crude charge
3. Bypass crude charge and feed slop to another part of the refinery, such as the coker
4. Continuously inject slop directly to the crude charge line at a very low rate, typically <1% of the crude charge rate
5. Have a dedicated slop tank and test the slop for BS&W (basic sediment & water) and filterable solids before charging to the unit.
Asphaltene precipitation can be troublesome for both the preheat exchangers and the desalting process. Asphaltene precipitation occurs when incompatible crude oils are blended together. Some crude oils are self-incompatible and will precipitate asphaltenes on their own. There are many crude compatibility models out there, including one developed and patented by Exxon Research & Development.6 Refineries can use such models to predict how different crudes will react when mixed together. Chemical suppliers can use models to predict potential precipitation in crude blends for better optimisation of treatment programmes such as asphaltene dispersants that can help keep asphaltenes in solution. A consequence of asphaltene precipitation is fouling of preheat exchangers, which, as previously mentioned, can be very costly. The application of an antifoulant in the cold preheat exchanger can help reduce the fouling, but can also potentially stabilise an emulsion in the desalter (see Figure 1).
Crude unit cold preheat exchangers are usually shell and tube exchangers, with the crude in the tube side and crude unit products on the shell side. These products (naphtha, diesel, kerosene, and so on) are typically at around 200-350°F (90-175°C). The more efficient the heat exchange is between the shell and tubes, the more the crude will be heated before entering the desalter. Heat helps the demulsifying process in the desalter. Heat decreases the viscosity of crude oil and weakens bonds formed by surfactants. This is especially important when running highly paraffinic crudes or highly asphaltenic crudes. Asphaltenes act as surfactants, and paraffinic waxes and asphaltenes can encapsulate water, salts, and solids, carrying them over into the crude unit and creating fouling and corrosion problems.
Desalter operations: mechanical and electrical
A desalter’s purpose is to remove crude oil contaminants that will have harmful effects in downstream equipment and process units. The more desalting is optimised, the more contaminants will be removed. As mentioned previously, feeding the desalter a consistent diet will help in the process as well as keeping the temperature high.
The desalting process is as follows:
1. Water is added to crude oil
2. The mixture passes through a mixing device
3. The mixture enters the desalter and separates
4. Oil exits the top of the desalter
5. Water exits the bottom of the desalter.
Wash water rate, injection location and quality
The amount of water, injection point of the water, and the quality of the water are important. Wash water volume should be between 6-10% of the crude charge volume, and a heavier crude diet may require a higher wash water rate. Higher water rate provides more opportunity for water to contact salts and solids in the crude oil.
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