Improving Mechanical Integrity while processing High TAN crudes
Subramanian Bhaskaran
Develop, Engineer, Commission Troubleshoot: Process Engineering | Technical Safety | Technical Services | Commissioning
High TAN crude has the following properties: a high acid value, fewer light components, a high density and viscosity, a high gel-asphalt content, and high salts and a heavy metals content, which give rise to equipment corrosion and severe problems with product quality and environmental protection.
High-acid crude (HAC) oils, also called high-total acid number (TAN) crudes, are oils where TANexpressed in terms of milligrams of potassium hydroxide per gram (mg KOH/g), is more than 0.5. Acidity is mainly due to the presence of naphthenic acids. Corrosion has been observed in many cases even at TAN less than 0.5 milligrams of KOH per gram of oil, So, relying on a so-called ‘‘safe’’ level of naphthenic acid, using rules of thumb from the literature is not reliable. This can be a warning flag, but not as absolute indicators.
So, the question is what strategies are adapted by designers and operating folks to control corrosion?
The strategies may be categorized as: dilution, metallurgy, neutralization, inhibition, other
Dilution
There are several options for controlling naphthenic acid attack. Blending with an acid free crude so that the acids are diluted below a critical level is a common practice. Keeping the acid number below 0.5 ml KOH/gm is usually accepted as safe, but we do know of several cases where this level did not prove to be safe.
Although the industry has traditionally accepted a safe level of naphthenic acid to be that which gives a total acid number of about 0.5 ml KOH/gm oil, there are case histories of attack by crudes well below this level. Because of the tremendous variety of sulfur compounds in crude oil, it is difficult to correlate sulfur content with corrosivity.
The major drawback to this approach is that the total acid number is not always indicative of either the amount of acid present in the crude, or the extent of corrosivity of the crude. Often during the distillation process, the corrosive acids concentrate in specific distillation zones, or in downstream units, causing corrosion in localized areas of a unit.
Metallurgy
Metallurgy is one way to control either type of attack. For naphthenic acid, the critical alloying element is molybdenum, a minimum of about 2.5%. The usual choice is 317 stainless steel, which has a higher molybdenum specification than 316. For sulfur attack, the critical ingredient is chromium at about 12% to 14% as found in the 400 series stainless steels.
Neutralization
One additional method which is not so widely practiced is neutralization where lime, caustic, or amines can be added to react with the naphthenic acids. This changes the distillation profile and is believed to make less reactive products. There are several disadvantages with these methods including caustic embrittlement of equipment, poisoning of downstream catalysts and, for amines, insufficient reaction time in most units.
Inhibition
Success can be achieved by the use of corrosion inhibitors, which are applied to the specific area where the corrosion is occurring. A thorough review of this class of inhibitors can be found in a NACE paper, “Naphthenic Acid Corrosion In A Refinery Setting,” paper No. 631, NACE Corrosion 33.
Other
In order to reduce corrosion, the liquid velocities to be limited to under 10 ft/sec.
Corrosion coupons and electrical resistance probes of the pertinent metallurgy can be used to monitor both types of corrosion in some locations, and it is obviously important to have a good location to make an accurate measurement.
One other strategy to consider for handling these high TAN crudes is to send the ATB to a ROSE AR unit and recover the gas oil at temperature low enough to avoid the corrosion problem in the first place. This is going to also saves a lot of money and avoid a high alloy vacuum unit.
In conclusion, with the practice of running “opportunity crudes”, the corrosion issue is much complicated and the mechanical integrity engineers are forever busy in monitoring, inspecting, brainstorming solutions in crude operations.
Process Manager at SLNG
4 年Very insightful
Hydrocracking | Catalysis | Renewable
4 年Thank you. Good knowledge sharing. However, TAN alone might not be the only indication of crude corrosivity by naphthenic acid. Above 0.3 mg KOH/g of TAN, naphthenic acid corrosion becomes a problem when sulfur level is too low, e.g., below 0.3 wt%. This is mainly from lacking protective iron sulfide layer in the absence of sulfur. So it is another way around to your statement that the corrosion may occur below 0.5 mg KOH/g TAN because of various sulfur species with unknown corrosivity. Past industrial experience has shown that when the sulfur level is above 0.3 wt%, up to 0.5 mg KOH/g TAN is acceptable. Another important consideration is problems associated with downstream units. For example, the corrosion rate might be acceptable at crude distillation downstream pipings but the level of corrosion product, soluble iron naphthenate, might be still a problem. With too high concentration of soluble iron naphthenate in feeds for hydroprocessing units, soluble iron naphthenate will be hydrotreated and forms solid iron sulfide which will in turn plugs the front part of the reactor beds. Even with good feed filtration, this problem is still unavoidable as mechanical filtration does not remove soluble iron napthenate. The effective cure is to select higher grade piping materials, e.g., SS317, as you pointed out. So it is also important to account these concerns when selecting the piping material for each product fraction, in addition to corrosion rate alone.
Oil, Gas and Instrumentation consultant and trainer
4 年This is a very good article. Can you mail me. We will discuss rest details by mail. Best Wishes.