Acid Number: Definition, TAN, and Naphthenic Acid Corrosion
The acid number is a standardized laboratory measurement that quantifies the total concentration of acidic components dissolved in a crude oil or petroleum product. Expressed in milligrams of potassium hydroxide per gram of sample (mg KOH/g), the acid number represents the amount of potassium hydroxide required to neutralize all acidic species present in a one-gram oil specimen, titrated to a neutral endpoint of pH 7. In the upstream and refining industries, the acid number is most commonly referred to as the Total Acid Number (TAN), and the two terms are used interchangeably throughout technical literature, regulatory filings, and commercial crude oil trading contracts. The primary standard governing this measurement is ASTM D664, which uses potentiometric titration to detect the titration endpoint electrochemically, enabling precise quantification even in dark or opaque crude oils where a colorimetric endpoint would be difficult to observe.
Key Takeaways
- The acid number (TAN) measures all acidic species in crude oil in mg KOH/g; values above 0.5 mg KOH/g are considered elevated, and values above 1.0 mg KOH/g classify the crude as high-acid.
- Naphthenic acids are the dominant acidic component in most high-TAN crudes, with molecular weights ranging from approximately 150 to 500 Daltons; they cause severe corrosion in atmospheric distillation columns between 230 and 400 degrees Celsius (450 to 750 degrees Fahrenheit).
- High-TAN crudes typically trade at a discount of USD 1 to 5 per barrel relative to benchmark grades, reflecting the additional refinery capital expenditure and operating costs required to process them safely.
- ASTM D664 (potentiometric titration) is the dominant standard for crude oil TAN; ASTM D974 (colorimetric indicator titration) applies to lighter, more transparent products such as lube base oils and aviation fuels.
- Mitigation strategies include materials selection (SS 316L, duplex stainless steel, Hastelloy C276), chemical corrosion inhibitors, low-temperature blending with sweet crudes, and hydrogen treatment to convert naphthenic acids to hydrocarbons.
How the Acid Number Is Determined
The ASTM D664 potentiometric titration procedure begins with dissolving a weighed oil sample, typically one gram, in a solvent mixture of toluene, isopropyl alcohol, and a small quantity of water. A standardized potassium hydroxide solution of known concentration is then added in precise increments using an automated burette. A glass electrode and reference electrode immersed in the solution continuously measure electrical potential. The titration proceeds until the potential reaches an inflection point corresponding to the neutralization of all acidic species, which is mathematically identified from the first derivative of the potential-versus-volume curve. The volume of KOH solution consumed is then converted to milligrams of KOH per gram of sample using the solution's normality and the sample mass. Automated titrators now perform this entire sequence with reproducibility typically within plus or minus 0.05 mg KOH/g.
ASTM D974 offers an alternative colorimetric approach in which a p-naphtholbenzein indicator solution changes color at the neutralization endpoint. While D974 is simpler and requires less sophisticated equipment, it is unsuitable for dark crude oils because the color change cannot be reliably observed. ASTM D974 is therefore reserved for lighter petroleum products including lube oils, transformer oils, and aviation turbine fuels, where ASTM D3242 also specifies a closely related procedure. ISO 6619 is the international equivalent to ASTM D974 and is referenced in many non-US refinery contracts, particularly in Europe and the Middle East. For consistency across commercial crude oil transactions, ASTM D664 remains the industry-standard method, and TAN values reported in crude assays worldwide are almost universally generated by this potentiometric procedure.
The Total Base Number (TBN) is the conceptual complement to TAN. TBN, measured under ASTM D2896 or ASTM D4739, quantifies the alkaline reserve of a lubricant or oil in terms of the milligrams of hydrochloric acid equivalent that one gram of sample can neutralize. In engine oil monitoring, TBN depletion toward the TAN level signals the end of the oil's service life. In crude oil refining, operators occasionally track the TAN-to-TBN ratio across process streams to monitor the net acidic loading on equipment. The formation water associated with high-TAN crudes often contains dissolved naphthenic acid salts (naphthenate soaps), which contribute to emulsification problems at the crude oil-water interface and complicate produced water treatment.
Naphthenic Acids: Structure, Origin, and Corrosion Mechanism
Naphthenic acids are the predominant acidic species responsible for high TAN values in crude oils from certain geological basins. Chemically, they belong to a complex family of cyclopentane- and cyclohexane-ring carboxylic acids with the general formula CnH(2n+z)O2, where z is a negative even integer reflecting the degree of cyclization. Their molecular weights range from approximately 150 Daltons for simple monocyclic species to over 500 Daltons for polycyclic variants. This range, determined by techniques such as electrospray ionization mass spectrometry (ESI-MS) and gas chromatography-mass spectrometry (GC-MS), has important practical implications: lower-molecular-weight naphthenic acids are more volatile and tend to concentrate in the light distillate fractions of an atmospheric distillation column, while heavier species accumulate in atmospheric gas oil and vacuum gas oil cuts. The naphthenic acid content of a crude oil is a product of the original organic matter deposited in the source rock, the temperature and pressure history during maturation, and any in-reservoir biodegradation that preferentially degrades n-alkanes while leaving cyclic carboxylic acids enriched.
Naphthenic acid corrosion (NAC) occurs primarily in the atmospheric distillation column and associated transfer lines of a crude oil refinery, specifically within the temperature window of 230 to 400 degrees Celsius (450 to 750 degrees Fahrenheit). Below approximately 230 degrees Celsius, naphthenic acids are largely in the liquid phase and corrode at relatively slow rates. Above 400 degrees Celsius, they thermally decompose into hydrocarbons and carbon dioxide, effectively eliminating the corrosive species but also destroying any value they might have as petrochemical feedstocks. Within the critical window, naphthenic acids in the vapor phase contact metal surfaces and react directly with iron to form iron naphthenates, which are soluble in the hydrocarbon stream and are continuously carried away from the metal surface, preventing the formation of a protective scale. This is in contrast to hydrogen sulfide corrosion, where iron sulfide scale formation can partially passivate the metal surface. The absence of a protective layer means NAC rates are high and sustained, with documented corrosion rates exceeding 10 millimeters per year on carbon steel in severe cases. The highest-risk locations are the overhead condenser inlet lines, the atmospheric column feed zone, and the pump-around circuits in the 280 to 360 degrees Celsius range, where naphthenic acid vapor pressure and velocity combine to create impingement conditions.
The velocity-assisted mechanism of NAC means that turbulent flow zones, pipe bends, return bends, tee junctions, and pump impellers experience accelerated attack compared to straight pipe runs. Corrosion engineers use the McConomy curves, later refined by Couper and Gorman, to estimate carbon steel corrosion rates as a function of temperature and sulfur content at a given TAN level. Sulfur in crude oil partially mitigates NAC because hydrogen sulfide and mercaptans react with the metal surface to form iron sulfide films that partially retard naphthenic acid penetration. High-TAN, low-sulfur crudes such as Doba (Chad, TAN approximately 3 to 4 mg KOH/g) and Duri (Indonesia, TAN approximately 2 to 4 mg KOH/g) are therefore especially aggressive because they lack the sulfur-based passivation mechanism. Certain Californian heavy sour crudes also exhibit elevated TAN values alongside moderate sulfur content, and West African coastal crudes including some Angolan and Congolese grades carry TANs in the 0.8 to 2.0 mg KOH/g range that require careful management.