Acid Number

The acid number, formally the total acid number (TAN), is a standardized measurement of the concentration of acidic components in a crude oil or petroleum product, expressed in milligrams of potassium hydroxide (KOH) required to neutralize all the acidic material in one gram of sample (mg KOH/g). The test method is ASTM D664 (potentiometric titration with KOH in alcoholic solution) or ASTM D974 (colour indicator titration). A TAN of 0.5 mg KOH/g or higher is generally considered elevated and of concern for corrosion in refinery processing equipment, particularly in crude distillation units where naphthenic acids in the 200 to 400°C boiling range concentrate in the atmospheric and vacuum distillation overheads and sidestreams. Crude oils with TAN above 1.0 mg KOH/g are called high-acid crudes or naphthenic acid crudes, and they command a price discount relative to benchmark crudes because of the additional corrosion management cost at the refinery. The Alberta oil sands bitumen and some offshore West African crudes are among the most significant high-TAN crude supply streams in the world market.

Key Takeaways

Naphthenic acids are the primary acidic components in high-TAN crude oils. They are cyclopentane and cyclohexane ring structures with one or more carboxylic acid (COOH) groups attached to alkyl side chains, described by the general formula CₙH₂ₙ₋ₓO₂ where x reflects the number of rings. Naphthenic acids boil primarily in the 200 to 400°C range, which means they concentrate in the kerosene and atmospheric gas oil fractions during distillation. The corrosive attack by naphthenic acids on carbon steel is a direct acid dissolution process: the COOH group reacts with iron to form iron naphthenate (a soluble soap that dissolves into the liquid) and water, continuously removing iron from the pipe wall. This attack is most severe at temperatures between 220 and 400°C and in flowing liquid (particularly two-phase flow where impingement of liquid droplets on carbon steel can strip the protective iron naphthenate film).
The TAN test measures total acidity but does not distinguish between the corrosive naphthenic acid fraction and other less-corrosive acidic species (phenols, hydrogen sulfide dissolved in oil, organic chlorides). A crude oil with TAN 1.5 mg KOH/g from naphthenic acids is far more corrosive in a refinery distillation unit than a crude with TAN 1.5 mg KOH/g from mostly phenols, because phenols are less reactive with steel at typical distillation temperatures. Supplementary testing (the high-temperature naphthenic acid content using ASTM E1663 or similar methods, or the oxidation stability) can distinguish the corrosive fraction, but TAN remains the primary commercial specification because it is simple, standardized, and universally used in crude oil purchase contracts.
Refinery corrosion from naphthenic acids is controlled by materials selection and chemical treatment. The main protective measure is the use of chromium-molybdenum alloy steel (typically 5 Cr-0.5 Mo or 9 Cr-1 Mo) in the sections of the crude distillation unit most exposed to naphthenic acid attack: transfer lines, fired heaters, atmospheric and vacuum column sidestream draws, and overhead condensers. Carbon steel provides essentially no protection in high-TAN crude service above TAN 1.0 at temperatures above 230°C. Chemical treatment with corrosion inhibitors (film-forming amine or phosphate ester inhibitors injected into the distillation overheads) supplements materials selection and is mandatory in most refineries processing high-TAN crudes. The inhibitor neutralizes the naphthenic acids and forms a protective film on the steel, though chemical treatment alone is not sufficient for very high-TAN service without alloy upgrade.
In upstream oil production, naphthenic acids in high-TAN crudes cause corrosion problems in production facilities, particularly in emulsion treaters, storage tanks, and crude oil heaters operating above 150°C. The formation of iron naphthenate soaps in these vessels creates persistent emulsions that are very difficult to break: the iron naphthenate acts as a natural emulsifier that stabilizes tight water-in-oil emulsions and makes the produced water difficult to separate to pipeline specifications. Naphthenate precipitation (calcium naphthenate scale) is also a problem in high-TAN wells when naphthenic acids in the crude oil react with calcium in the produced water, forming a white waxy scale that deposits in perforations, wellbores, production tubing, and surface flowlines. This calcium naphthenate scale is virtually insoluble in acid and requires mechanical removal or specialized chemical solvents.
The price discount for high-TAN crudes relative to benchmark light sweet crude of equivalent density and sulfur content varies with market conditions and refinery configuration. In periods of tight crude supply, high-TAN crude discounts narrow because refiners are willing to incur higher corrosion management costs to secure supply. In periods of oversupply, high-TAN discounts can reach USD 3 to 8 per barrel versus a comparable non-acid crude. Alberta bitumen-derived synthetic crude (produced by upgrading, which reduces TAN) is generally low-acid, but diluted bitumen (dilbit) transported in pipelines as a blend of bitumen and condensate diluent retains the naphthenic acid content of the bitumen until it is processed at a refinery. Refineries receiving dilbit for processing must manage TAN-related corrosion in the crude preheating and atmospheric distillation sections even when the overall TAN of the blend is below 1.0 mg KOH/g, because local concentrations can exceed the global TAN during distillation.

How Naphthenic Acids Corrode Refinery Equipment

Naphthenic acid corrosion in a crude distillation unit follows the liquid flow paths through the process, attacking carbon steel wherever naphthenic acid-containing liquid contacts metal at elevated temperature. The atmospheric distillation column receives crude preheated to 360 to 380°C in a fired heater. The fractions most concentrated in naphthenic acids pass through the transfer line (the large-diameter pipe connecting the heater to the column), the atmospheric column wash section, and the sidestream draw piping for atmospheric gas oil (AGO) and kerosene.

The corrosion rate in this service is not linear: it increases sharply above 230°C (where naphthenic acids become fully active corrodents), reaches a peak around 280 to 320°C, and drops above 380°C as the acids thermally decompose (decarboxylation). Within this corrosive window, turbulent flow in bends, reducers, and tees dramatically accelerates attack by stripping the iron naphthenate film before it can protect the surface. Pitting at bends and welds is the typical manifestation, and the pits can penetrate the full wall thickness of a 6-inch carbon steel pipe in six to eighteen months of continuous service with high-TAN crude.

Inspection programmes in refineries processing high-TAN crudes use phased array ultrasonic testing (PAUT) and corrosion coupons to monitor wall thickness at high-risk locations on a quarterly or semi-annual schedule. Refineries that process a blend of high-TAN and low-TAN crudes manage their TAN exposure by scheduling high-TAN crude runs for periods when the alloy sections of the column are in service and reverting to carbon steel sections during low-TAN runs, a practice called TAN blending management.

Fast Facts

Naphthenic acid corrosion was recognized as a refinery problem in the early 20th century but became a major industry concern in the 1980s and 1990s as oil producers began marketing significant volumes of high-TAN crudes from West Africa (Nigerian Escravos, Angolan Dalia and Girassol crudes), South America (Venezuelan Orinoco heavy crudes), and the Canadian oil sands (dilbit and raw bitumen). The TAN test method, ASTM D664, was standardized in 1948 and has remained the dominant commercial specification for crude oil acidity despite its limitations in distinguishing corrosive naphthenic acids from other acidic species. Athabasca oil sands bitumen has TAN values typically ranging from 2.0 to 4.5 mg KOH/g, among the highest of any commercial crude supply stream in the world. Upgrading the bitumen to synthetic crude oil reduces TAN to below 0.2 mg KOH/g by thermal and hydrocracking processes, but the upgrading cost adds approximately CAD 10 to 20 per barrel to the production cost. The naphthenic acid issue in Alberta oil sands is therefore both a refinery economics question (how much discount for high TAN?) and an upgrading economics question (is it cheaper to upgrade at the mine or to sell dilbit at a discount?).

Acid Number in Pipeline Quality Specifications

Pipeline companies that accept crude oil for transportation specify a maximum TAN in their quality specifications, typically 0.5 or 1.0 mg KOH/g for conventional crude pipelines. Bitumen blend pipelines may accept higher TAN (up to 2.0 mg KOH/g in some blend specifications) because the pipelines are designed with higher wall thickness and corrosion allowances. These TAN limits protect the pipeline from internal corrosion, particularly in sections where produced water settles out of the crude (the bottom of the pipe at low-flow conditions) and naphthenic acids contact steel in the presence of water, creating an aqueous corrosion mechanism in addition to the high-temperature dry-oil mechanism seen in refineries.

Producers of high-TAN crudes who want to access pipelines with strict TAN limits must either blend their production with low-TAN crude to meet specification, treat the crude chemically to neutralize the naphthenic acids (using caustic NaOH washing, which converts naphthenic acids to water-soluble sodium naphthenates that are removed with the produced water), or accept a commercial discount at an alternative pipeline receiving station that has a higher TAN limit. In Alberta, the vast majority of oil sands bitumen production moves through the pipeline system as dilbit blends that meet the TAN specification through the dilution effect of the low-TAN condensate diluent, even though the bitumen fraction itself is high-TAN.

The acid number is formally called the total acid number (TAN) and is sometimes informally called the neutralization number. Related terms include naphthenic acid (the cycloaliphatic carboxylic acids that are the primary contributors to high TAN in crude oils; responsible for corrosion in refinery distillation units and for naphthenate scale formation in production facilities), naphthenic acid corrosion (the direct acid dissolution attack on carbon steel by naphthenic acids at temperatures between 230 and 380°C in refinery crude distillation units; the primary corrosion mechanism associated with high-TAN crude processing), ASTM D664 (the American Society for Testing and Materials standard test method for total acid number by potentiometric titration with KOH in alcoholic solution; the industry-standard method for measuring TAN in crude oil and petroleum products), high-acid crude (a crude oil with TAN above 1.0 mg KOH/g, requiring additional corrosion management at refineries and typically traded at a discount to benchmark crudes; includes Alberta oil sands bitumen and several West African and South American crude streams), and naphthenate scale (deposits of calcium or iron naphthenate formed when naphthenic acids in high-TAN crude react with calcium or iron ions in produced water; common in wellbores and surface production facilities and difficult to remove with conventional acid scale treatments).

How a TAN Exceedance in an Oil Sands Upgrader Feed Caused Unplanned Corrosion Inspections

An Alberta oil sands upgrader was receiving diluted bitumen from a blend of in-situ SAGD producers. The bitumen's TAN had been running at 2.8 to 3.2 mg KOH/g in regular monthly quality measurements, within the upgrader's feed specification of up to 3.5 mg KOH/g. The feed stream was diluted with condensate to a dilbit TAN of approximately 1.1 mg KOH/g before entering the atmospheric crude distillation unit (ADU).

Over a three-month period, two new SAGD producers came online and their higher-TAN bitumen (averaging 4.2 mg KOH/g) was blended into the feed without a corresponding increase in condensate diluent volume. The blend TAN increased to 1.6 to 1.8 mg KOH/g, a modest absolute increase but 45 to 65% above the ADU's design basis. The higher TAN was not flagged in the blend management system because the alerting threshold had been set at the feed specification limit of 3.5 mg KOH/g for unblended bitumen, not at the dilbit TAN limit for the ADU.