Properties such as Specific gravity, distillation profile, vapor pressure, Hydrogen sulfide content, and octane number of gasoline are affected by the light hydrocarbon content so that suitable cooling or pressure sampling methods must be used and care taken during the subsequent handling of the oil to avoid the loss of any volatile constituents. In addition, adequate records of the circumstances and conditions during sampling must be made. Elemental analysis of petroleum shows that the major constituents are carbon and hydrogen with smaller amounts of sulfur (0.1–8% w/w), nitrogen (0.1–1.0% w/w), and oxygen (0.1–3% w/w), and trace elements such as vanadium, nickel, iron, and copper present at the part per million (ppm) level. Of the non-hydrocarbon (heteroelements) elements, sulfur is the most abundant and often considered the most important by refiners. However, Nitrogen and the trace metals also have deleterious effects on refinery catalysts and should not be discounted because of relative abundance.

Density is an important property of petroleum products because petroleum and especially petroleum products are usually bought and sold on that basis or, if on a volume basis, then converted to mass basis via density measurements. The density (specific gravity) of a fuel is a measure of the mass per unit volume and can be determined directly with calibrated glass hydrometers..

Viscosity and pour point determinations are performed principally to ascertain the flow characteristics of petroleum at low temperatures. There are, however, some general relationships of crude oil composition that can be derived from pour point and viscosity data. Commonly, the lower the pour point of a crude oil the more aromatic it is, and the higher the pour point the more paraffinic it is. Viscosity is usually determined at different temperatures (e.g., 25°C/77°F, and 100°C/212°F) by measuring the time for a volume of liquid to flow under gravity through a calibrated glass capillary viscometer.

In the test, the time for a fixed volume of liquid to flow under gravity through the capillary of a calibrated viscometer under a reproducible driving head and at a closely controlled temperature is measured in seconds. The kinematic viscosity is the product of the measured flow time and the calibration constant of the viscometer. Conversion of the kinematic viscosity in centistokes (cSt) at any temperature to Saybolt Universal viscosity in Saybolt Universal seconds (SUS) at the same temperature and for converting kinematic viscosity in centistokes at 122 and 210°F to Saybolt Furol viscosity in Saybolt Furol seconds (SFS) at the same temperatures (ASTM D-2161) is avaibale through formulae. The viscosity index is a widely used measure of the variation in kinematic viscosity due to changes in the temperature of petroleum between 40°C and 100°C (104°F and 212°F). For crude oils of similar kinematic viscosity, the higher the viscosity index the smaller is the effect of temperature on its kinematic viscosity. The accuracy of the calculated viscosity index is dependent only on the accuracy of the original viscosity determination

The water and sediment- content of crude oil, like salt, results from production and transportation practices. Water, with its dissolved salts, may occur as easily removable suspended droplets or as an emulsion. The sediment dispersed in crude oil may be comprised of inorganic minerals from the production horizon or from drilling fluids and scale and rust from pipelines and tanks used for oil transportation and storage. Usually water is present in far greater amounts than sediment, but, collectively, it is unusual for them to exceed 1% of the crude oil on a delivered basis.

The salt content of crude oil is highly variable and results principally from production practices used in the field and, to a lesser extent, from its handling aboard the tankers bringing it to terminals. The bulk of the salt present will be dissolved in coexisting water and can be removed in desalters, but small amounts of salt may be dissolved in the crude oil itself. The hydrochloric acid evolved is extremely corrosive, necessitating the injection of a basic compound, such as ammonia, into the overhead lines to minimize corrosion damage. Salts and evolved acids can also contaminate both overhead and residual products, and certain metallic salts can deactivate catalysts. Thus knowledge of the content of salt in crude oil is important in deciding whether and to what extent the crude oil needs desalting. The salt content is determined by potentiometric titration in a nonaqueous solution in which the conductivity of a solution of crude oil in a polar solvent is compared with that of a series of standard salt solutions in the same solvent..

Sulfur is present in petroleum as sulfides, thiophenes, benzothiophenes, and dibenzothiophenes. In most cases, the presence of sulfur is detrimental to the processing because sulfur can act as catalytic poisons during processing. The sulfur content of petroleum is an important property and varies widely within the rough limits 0.1% w/w to 3.0% w/w. Compounds containing this element are among the most undesirable constituents of petroleum because they can give rise to plant corrosion and atmospheric pollution. Petroleum can evolve hydrogen sulfide during distillation as well as low-boiling sulfur compounds.

The acid number is the quantity of base, expressed in milligrams of potassium hydroxide per gram of sample, that is required to titrate a sample in this solvent to a green/green-brown end point, using p-naphtholbenzein indicator solution.The strong acid number is the quantity of base, expressed as milligrams of potassium hydroxide per gram of sample, required to titrate a sample in the solvent from its initial meter reading to a meter reading corresponding to a freshly prepared nonaqueous acidic buffer solution.

The flash point test is a guide to the fire hazard associated with the use of the fuel. The flash point can be determined by the Abel method (IP 170), except for high-flash kerosene, where the Pensky–Martens method (ASTM D-93, IP 34) is specified.

The freezing point of fuel is an index of the lowest temperature of its utility for the specified applications. Fuels used in aviation must have acceptable freezing point and low-temperature pumpability characteristics so that adequate fuel flow to the engine is maintained at high altitude; this is a requirement of aviation specifications. (ASTM D-910, ASTM D-1655). Maximum freezing point values are specified for all types of aviation fuel as a guide to the lowest temperature at which the fuel can be used without risk of the separation of solid hydrocarbons. The solidified hydrocarbons could lead to clogging of fuel lines or fuel filters and loss in available fuel load due to retention of solidified fuel in the tanks. The freezing point of the fuel (typically in the range –40 to –65°C, –40 to –85°F) must always be lower than the minimum operational fuel temperature. The freezing point specification is retained as a specification property to predict and safeguard high-altitude performance.