crude oils

8Crude OilsHarry N. Giles1

CRUDE OILS ARE A HIGHLY COMPLEX COMBINA-tion of hydrocarbons; heterocyclic compounds of nitrogen,oxygen, and sulfur; organometallic compounds; inorganicsediment; and water. Approximately 600 different hydrocar-bons have been positively identified in crude oil, and it islikely that thousands of compounds occur, many of whichprobably will never be identified. In a study sponsored bythe American Petroleum Institute (API), nearly 300 individ-ual hydrocarbons were identified in Ponca City, Oklahoma,crude oil [1,2]. Some 200 individual sulfur compounds wereidentified in a 20-year systematic study of four crude oils [3].Not only is the composition of crude oil highly complex, it isalso highly variable from field to field, and even within agiven field, it is likely to exhibit inhomogeneity from reser-voir to reservoir. Physical and chemical characterization ofthis complex mixture is further complicated for the analystby the fact that crude oils are not pure solutions but com-monly contain colloidally suspended components, dispersedsolids, and emulsified water.

Compared to refined products such as gasoline and avi-ation turbine fuel, there is relatively little in the literature onthe analysis and characterization of crude oils. Indeed, formany years, there were relatively few ASTM methods spe-cific to crude oils, although a number of ASTM methods hadbeen adapted for their analysis. This situation may haveresulted, at least in part, from the historical tendency ofrefinery chemists to independently develop or modify analyt-ical methods specific to their needs and, subsequently, forthe methods to become company proprietary. In recentyears, the unique problems associated with sampling andanalysis of crude oils have received more attention, and moremethods for determining selected constituents and character-istics of crude oils have been standardized.

A series of articles [49] illustrate the diversity of crudeoil assay practices employed by major refiners in the UnitedStates and Austria. The dissimilarity of published results [10]and as provided by a number of companies on their Websites [11] is a reflection of this independent development ofanalytical schemes, even though standardized approaches tocrude oil analysis have been published [1215]. Despite thecomplexity of crude oil composition and the diversity of ana-lytical methodology, probably more crude oil analyses areroutinely performed on a daily basis using inherently similarmethods than are analyses on any single refined petroleumproduct except, possibly, gasoline.

The overriding issue when performing comprehensivecrude oil assays is economics. Crude oils are assayed todetermine (1) the slate of products that can be producedwith a given refinerys process technology; (2) the processing

difficulties that may arise as a result of inherent impuritiesand contaminants; and (3) the downstream processing andupgrading that may be necessary to optimize yields of high-value, specification products. Today, analytical data are typi-cally stored in an electronic database that can be accessedby computer models that generate refinery-specific eco-nomic valuations of each crude oil or crude slate, that is, amixture of crude oils processed together. Linear program-ming (LP) models are available from several commercialvendors, but a number of companies have developed theirown models to meet the needs of their specific refineryconfigurations.

Analyses are also performed to determine whether eachbatch of crude oil received at the refinery gate meets expect-ations. Does the crude receipt match the database assay sothat the projected economic valuations and operational strat-egies are valid? Has any unintentional contamination or pur-poseful adulteration occurred during gathering, storage, ortransport of the crude oil that may increase the processingcost or decrease the value of the refined products? Theinformation needed to answer these questions is often refin-ery specifica function of the refinerys operating con-straints and product slate.

To obtain the desired information, two different analyti-cal schemes are commonly used, namely, an inspectionassay and a comprehensive assay. Inspection assays usuallyinvolve determination of a few key whole crude oil proper-ties such as API gravity, sulfur content, and pour pointprincipally as a means of determining if major changes in acrude oil streams characteristics have occurred since thelast comprehensive assay was performed. Additional analysesmay be performed to help ensure that quality of the cargoor shipment received is that which is expected; to ascertainthe quantity of impurities such as salt, sediment, and water;and to provide other critical refinery-specific information.Inspection assays are routinely performed on all shipmentsreceived at a terminal or refinery. The comprehensive assay,on the other hand, is complex, costly, and time consumingand is normally performed only when a new field comes onstream, or when the inspection assay indicates that signifi-cant changes in the streams composition have occurred.Except for these circumstances, a comprehensive assay of aparticular crude oil stream may not be updated for severalyears.

Moreover, many major pipeline companies require acomprehensive assay when accepting a new crude oil streamfor transportation in their system on a common streambasis. Thereafter, an inspection assay is used for checkingthe quality of shipments.

1 PetroStorTech LLC, Arlington, VA.106

MNL1-EB/May 2010

Copyright 2010 by ASTM International www.astm.org

INSPECTION ASSAYSInspection assays comprise a limited number of tests gener-ally restricted to the whole crude oil. Based on publisheddata, there is little agreement as to what constitutes aninspection assay. As the data are primarily for intra-companyuse, there is little driving force for a standard scheme. At abare minimum, API gravity, sulfur content, and sedimentand water are usually determined, although it is useful toalso know the pour point, which provides some basic percep-tion of the crude oils fluidity and aromaticity. A moredetailed inspection assay might consist of the following tests: APIgravity (or density or relative density), total sulfur content, pourpoint, viscosity, salt content, total acid number (neutralizationnumber), and water and sediment content. Individual refinersmay substitute or add tests, for example, trace metals or organichalides, that may be critical to their operations. Coupling theresults from these few tests of a current crude oil batch with thearchived data from a comprehensive assay, the process engineerwill be able to estimate generally the product slate that the crudewill yield and any extraordinary processing problems that maybe encountered.

In the early 1990s, the API formed the Ad Hoc Crude OilQuality Task Force. The report of this task group recommendsa set of crude oil quality testing procedures that, if adopted bya shipper or refiner, would help ensure the quality of crude oilfrom the wellhead to the refinery [16]. These proceduresinclude tests for API gravity, sediment and water, organohalidecompounds, salt, sulfur, and neutralization number, amongothers. While not a standard, the report is an important aid tomembers of the petroleum industry in protecting the qualityof common stream crude petroleum from contamination byforeign substances or crude petroleum of unspecified makeup.It is also a useful guide for an inspection program using mostlystandardized procedures widely accepted in the industry formonitoring the quality of mercantile commodity.

It is important to note that, in the following discussionof test methods, crude oil may not be included in the titleor even in the scope. Many test methods have, however,been adapted to and are widely used and accepted for crudeoil analysis.

API GravityAccurate determination of the gravity of crude oil is necessaryfor the conversion of measured volumes to volumes at the stand-ard temperature of 15.56C (60F) using ASTM D1250, Petro-leum Measurement Tables. API gravity is a special function ofrelative density (specific gravity) represented by the following:

API gravity; degrees 141:5specific gravity 60=60F

131:5 1No statement of reference temperature is required, as 60Fis included in the definition.

Gravity is also a factor reflecting the quality of crude oils.Generally, the heavier (lower the API gravity) the crude oil, thegreater is the quantity of heavier components that may bemore refractory and require greater upgrading or more severecracking to produce salable products. Conversely, the lighterthe crude oil the greater the quantity of distillable products.

The relative density (specific gravity) or density of acrude oil may also be reported in analyses. Relative densityis the ratio of the mass of a given volume of liquid at a spe-cific temperature to the mass of an equal volume of pure

water at the same or a different temperature. Both referencetemperatures must be explicitly stated. Density is simplymass per unit volume at a specified temperature.

API gravity, or density or relative density, can be deter-mined easily using one of two hydrometer methods [ASTMD287, Test Method for API Gravity of Crude Petroleum andPetroleum Products (Hydrometer Method), or ASTM D1298,Test Method for Density, Relative Density (Specific Gravity),or API Gravity of Crude Petroleum and Liquid PetroleumProducts by Hydrometer Method]. Many laboratories arenow using an instrumental method (ASTM D5002, TestMethod for Density and Relative Density of Crude Oils byDigital Density Analyzer) rather than the hydrometer meth-ods. A third hydrometer method (ASTM D6822, Test Methodfor Density, Relative Density, and API Gravity of Crude Petro-leum and Liquid Petroleum Products by ThermohydrometerMethod) is applicable to field applications where limited lab-oratory facilities are available.

Sulfur ContentThe sulfur content of a crude oil, which may vary from lessthan 0.1 to over 5 mass percent, is one of its most importantquality attributes. Sulfur compounds contribute to corrosionof refinery equipment and poisoning of catalysts, cause cor-rosiveness in refined products, and contribute to environ-mental pollution as a result of emission of sulfur oxidesfrom combustion of fuel products. Sulfur compounds maybe present throughout the boiling range of crude oils,although, as a rule, they are more abundant in the heavierfractions. In some crude oils, thermally reactive sulfur com-pounds can decompose on heating to produce hydrogen sul-fide, which is highly toxic and very corrosive. Consequently,in reporting the hydrogen sulfide content of a crude oil, it isimportant to distinguish between that which is dissolved andthat which is evolved on heating or distillation. The mercap-tans usually present in a crude oil can impart a foul odor,depending on the species. Butyl mercaptan, a compoundnaturally present in many crude oils, is the odorant com-monly used in natural gas. The fetid smell in the secretionejected by skunks is also due to this compound.

Until relatively recently, one of the most widely usedmethods for determination of total sulfur content has beencombustion of a sample in oxygen to convert the sulfur tosulfur dioxide, which is collected and subsequently titratediodometrically or detected by nondispersive infrared. This iscommonly referred to as the Leco technique, but in itsstandard form is ASTM D1552, Test Method for Sulfur inPetroleum Products (High-Temperature Method). An evenolder method involving combustion in a bomb with subse-quent gravimetric determination of sulfur as barium sulfate[ASTM D129, Test Method for Sulfur in Petroleum Products(General Bomb Method)] is not as accurate as the high-temperature method, possibly because of interference fromthe sediment inherently present in crude oil.

These older techniques are rapidly being replaced byinstrumental methods. Among these are ASTM D4294, TestMethod for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy, and ASTMD2622, Test Method for Sulfur in Petroleum Products byX-Ray Spectrometry. ASTM D4294 has slightly better repeat-ability and reproducibility than the high-temperature methodand is adaptable to field applications; however, this methodcan be affected by some commonly present interferences

CHAPTER 8 n CRUDE OILS 107

such as halides. Of the two methods, ASTM D2622 has betterprecision and the capability of correcting for interferencesbut is currently limited to laboratory use, and the equipmentis more expensive. Sediment and water commonly present incrude oil samples will interfere in sulfur determination byboth of the X-ray methods. These should be removed fromthe sample by centrifugation or settling prior to analysis, butcare must be taken that sample integrity is not compromised.

Hydrogen sulfide and mercaptans are commonly deter-mined by non-aqueous potentiometric titration with silvernitrate (UOP 163, Hydrogen Sulfide and Mercaptan Sulfurin Liquid Hydrocarbons by Potentiometric Titration). Hydro-gen sulfide is highly reactive, however, and unless precau-tions are taken in the collection and preservation ofsamples, results will not be representative. A test kit has beendeveloped that is very useful for rapidly determining hydro-gen sulfide concentration in liquid samples in the field [17].This kit has an accuracy of about 20 % for hydrogensulfide.

Salt ContentThe salt content of crude oil is highly variable and resultsprincipally from production practices used in the field and,to a lesser extent, from its handling aboard tankers bringingit to terminals. The bulk of the salt present will be dissolvedin coexisting free water and can be removed in desalters, butsmall amounts of salt may be dissolved in the crude oilitself. Salt may be derived from reservoir or formationwaters or from other waters used in secondary recoveryoperations. Aboard tankers, ballast water of varying salinitymay also be a source of salt contamination.

Salt in crude oil may be deleterious in several ways.Even in small concentrations, salts will accumulate in stills,heaters, and exchangers, leading to fouling that requiresexpensive cleanup. More important, during flash vaporiza-tion of crude oil, certain metallic salts can be hydrolyzed tohydrochloric acid according to the following reactions:

2 NaClH2O! HClNa2O 2MgCl2 H2O! 2 HClMgO 3

The hydrochloric acid evolved is extremely corrosive, neces-sitating the injection of a basic compound, such as ammo-nia, into the overhead lines to minimize corrosion damage.Salts and evolved acids can also contaminate both overheadand residual products, and certain metallic salts can deacti-vate catalysts. A thorough discussion of the effects of salt oncrude processing is included in a manual on impurities inpetroleum [18].

For many years, the salt content has been routinelydetermined by comparing the conductivity of a solution ofcrude oil in a polar solvent to that of a series of standardsalt solutions in the same solvent [ASTM D3230, Test Methodfor Salts in Crude Oil (Electrometric Method)]. This testmethod provides an approximate measure of the chloridecontent of the crude oil being tested based on measurementof its conductivity. The chloride content is obtained by refer-ence to a calibration curve prepared using a given mixtureof salts. As conductivity varies with varying salt composition,unless the composition of salts in the sample being tested isthe same as the calibration mixture, results will be affected.Also, other conductive materials present in the crude oilsample will affect results. These factors contribute to the rel-atively poor precision of the method. ASTM D6470, Test

Method for Salt in Crude Oils (Potentiometric Method), isless affected by salt composition and has considerably betterprecision than the older method. Regardless of the methodused, it is necessary to use other methods, such as atomicabsorption, inductively coupled argon plasma spectropho-tometry, or ion-chromatography to determine the composi-tion of the salts present.

Water and SedimentThe water and sediment content of crude oil, like salt, resultsprincipally from production and transportation practices.Water, with its dissolved salts, may occur as easily removablesuspended droplets or as an emulsion. The sediment dis-persed in crude oil may be comprised of inorganic mineralsfrom the production horizon or from drilling fluids, as wellas from scale and rust from pipelines and tanks used for oiltransportation and storage. Usually water is present in fargreater amounts than sediment, but, collectively, it isunusual for them to exceed 1 % (v/v) of the crude oil on adelivered basis. Like salt, water and sediment can foul heat-ers, stills, and exchangers and can contribute to corrosionand to deleterious product quality. Also, water and sedimentare principal components of the sludge that accumulates instorage tanks and must be disposed of periodically in anenvironmentally acceptable manner.

Further, water bottoms in storage tanks can promotemicrobiological activity, and, if the system is anaerobic, pro-duction of corrosive acids and hydrogen sulfide can result.This is not usually a problem with crude oils, as stocks arenormally rotated on a regular basis. Nevertheless, anaerobicdegradation of crude oil stocks and production of hydrogensulfide has been known to happen, and the operator mustbe aware of the potential for this to occur and the analystmust take this into consideration in evaluating results.

Knowledge of the water and sediment content is alsoimportant in accurately determining net volumes of crudeoil in sales, taxation, exchanges, and custody transfers.When a significant amount of free water is present inmarine cargo, identification of its probable source shouldbe a major consideration. Guidelines that include basic sam-pling, testing, and analytical procedures and interpretationand presentation of results for this process have been pub-lished [19].

A number of test methods exist for the determination ofwater and sediment in crude oil. Centrifugal separation ofthe water and sediment [ASTM D4007, Test Method forWater and Sediment in Crude Oil by the Centrifuge Method(Laboratory Procedure)] is rapid and relatively inexpensive,but, almost invariably, the amount of water detected is lowerthan the actual water content. A more accurate method forsediment entails extraction with hot toluene in a refractorythimble (ASTM D473, Test Method for Sediment in CrudeOils and Fuels Oils by the Extraction Method). A somewhatless time-consuming method of determining sedimentinvolves dissolving a sample in hot toluene and filtering thesolution under gravity through a membrane filter (ASTMD4807, Test Method for Sediment in Crude Oil by Mem-brane Filtration). The use of toluene in laboratories is com-ing under increasing scrutiny by safety and health groups,however, and a ban on its use is not inconceivable.Improved techniques for measuring water content includeheating under reflux conditions with a water immiscible sol-vent that distills as an azeotrope with the water (ASTM

108 SIGNIFICANCE OF TESTS FOR PETROLEUM PRODUCTS n 8TH EDITION

D4006, Test Method for Water in Crude Oil by Distillation),potentiometric titration (ASTM D4377, Test Method forWater in Crude Oils by Potentiometric Karl Fischer Titra-tion), or the more generally preferred coulometric titration(ASTM D4928, Test Method for Water in Crude Oils by Cou-lometric Karl Fischer Titration). The latter two Karl Fischermethods include a homogenization step designed to redis-perse any water that has separated from the crude oil whilethe sample has been stored.

FluidityPour Point and ViscosityPour point and viscosity determinations of crude oils are per-formed principally to ascertain their handling characteristics atlow temperatures. There are, however, some general relation-ships about crude oil composition that can be derived frompour point and viscosity data. Commonly, the lower the pourpoint of a crude oil, the more naphthenic or aromatic it is, andthe higher the pour point, the more paraffinic it is. There arenumerous exceptions to this rule-of-thumb, and other data mustbe used to verify a crude oils character. Viscosity is also a func-tion of the aromaticity or paraffinicity of the sample. Thosecrude oils with a greater concentration of paraffins generallyhave a higher viscosity than crude oils having a relatively largeproportion of aromatic and naphthenic compounds.

Pour point is determined by cooling a preheated sampleat a specified rate and examining its flow characteristics atintervals of 3C. ASTM D97, Test Method for Pour Point ofPetroleum Products, is the most widely used procedure forthis measurement, even though crude oils are not mentionedin the methods scope. An alternative procedure specificallyfor testing the pour point of crude oils is described in ASTMD5853, Test Method for Pour Point of Crude Oils.

Viscosity is determined by measuring the time for a vol-ume of liquid to flow under gravity through a calibratedglass capillary viscometer [ASTM D445, Test Method forKinematic Viscosity of Transparent and Opaque Liquids(and the Calculation of Dynamic Viscosity)]. While the pre-ferred unit of kinematic viscosity is millimeter squared persecond (mm2/s), many older analyses report it in centistokes(cSt). These units are equivalent, with 1 mm2/s equaling 1cSt. At one time the petroleum industry measured viscosityby means of the Saybolt viscometer, and expressed values inunits of Saybolt Universal Seconds (SUS) or Saybolt FurolSeconds (SFS). This practice is now largely obsolete in theindustry. ASTM D2161, Practice for Conversion of KinematicViscosity to Saybolt Universal Viscosity or to Saybolt FurolViscosity, establishes equations that may be used for calculat-ing kinematic viscosities from SUS and SFS data that appearin older literature. By determining viscosity at two tempera-tures such as 25 and 40C, viscosity at any other temperatureover a limited range may be interpolated or extrapolatedusing viscosity-temperature charts (ASTM D341, Viscosity-Temperature Charts for Liquid Petroleum Products). It mustbe kept in mind that these charts are not linear. Also, the low-est temperature at which viscosity is determined must be sev-eral degrees higher than the pour point. Otherwise, the crudeoil will not exhibit Newtonian behavior.

Characterization FactorProbably the most widely used index of composition is theCharacterization or Watson K-Factor [20], which was origi-nally defined as the cube root of the average molal boilingpoint in F absolute (Rankine) temperature divided by the

specific gravity, at 60/60F. It has conveniently been relatedto viscosity and API gravity (UOP Method 375, Calculation ofUOP Characterization Factor and Estimation of MolecularWeight of Petroleum Oils). Typically, paraffin base crude oilshave K 12.0, with lower values indicating crude oils of amore aromatic or naphthenic character [21]. These valuesprovide a general rule-of-thumb on product yields; the paraf-fin base crude oils will give the highest gasoline yields, whilethe aromatic base feedstocks will be the most refractory andrequire a greater degree of upgrading.

Trace ElementsA number of trace elements have been detected in crude oil,with nickel and vanadium commonly being the most abundant.Until recently, however, relatively little systematic analyticalwork has been carried out on other trace elements. With height-ened environmental awareness and susceptibility of many cata-lysts to poisoning or deactivation by trace metals, more work isbeing done on determining their presence in crude oils. Pub-lished reports indicate that over 30 trace metals definitivelyoccur in crude oils [22,23]. An extensive review of the literaturepublished through 1973 provides information on the occur-rence and concentration of 45 trace elements [24]. Using highlysophisticated techniques such as neutron activation analysis,and with the greatly improved sensitivity of modern detectors,it is likely that even more elements will be found, but probablyin subparts-per-billion concentrations. Knowledge of the traceelement constituents in crude oil is important because they canhave an adverse effect on petroleum refining, product quality,and the environment. Among the problems associated withtrace elements are catalyst poisoning in the refinery and exces-sive atmospheric emissions in combustion of fuels. Elementssuch as iron, arsenic, and lead are catalyst poisons. Vanadiumcompounds can cause refractory damage in furnaces, andsodium compounds have been found to cause superficialfusion on fire brick [25]. Some organometallic compounds arevolatile, which can lead to contamination of distillate fractions[26] and a reduction in their stability or malfunctions of equip-ment when they are combusted. Concentration of the nonvola-tile organometallics in heavy products such as premium cokecan have a significant impact on price, marketability, and use.Knowledge of trace element concentrations is also useful inexploration in correlating production from different wells andhorizons in a field [27].

A number of trace metals are of considerable interestbecause of their potential impact on the environment, resultingfrom atmospheric emissions when fuels are burned or fromdischarge of process streams or disposal of wastes. In supportof the North Sea Action Plan to reduce emissions, a detailedstudy of crude oils imported into the Netherlands was con-ducted [28]. It was found that cadmium, zinc, and copper werenot indigenous to the crude oils but were the result of contami-nation with associated water or particles, or both, from the pro-ducing wells. Chromium was found to be indigenous for themost part and associated with the hydrocarbon matrix. Someinorganic chromium was thought to be present as a contami-nant. The study was unable to determine the origin of arsenicfound in the crude oils, but it was considered to probably be acontaminant. The intention to study mercury was abandonedbecause a reliable analysis technique was not found.

Two metals of considerable environmental concern aremercury and selenium, both of which occur naturally incrude oil at varying concentrations. Mercury is of concern


as both an air and water pollutant, and selenium is of con-cern as a water pollutant.

There is substantial evidence indicating that mercury canoccur in crude oil as volatile, dissolved, and particulate (sus-pended) species, all of which differ considerably in theirbehavior. Supporting the presence of volatile species, elemen-tal mercury has been found condensed in cooler regions inrefinery distillation towers and in cryogenic heat exchangersthat liquefy petroleum gases. Further, replicate laboratoryanalyses on the same sample have found decreases in con-centration over time [29]. Mercury has also been found insludge that accumulates in strategic stockpiles of crude oil,clearly indicating the occurrence of particulate or suspendedspecies [30]. Finally, mercury can be present in various petro-leum distillation fractions across a broad boiling range.

Selenium has become a priority pollutant because of its hightoxicity to aquatic wildlife. In refineries, it partitions into waste-water streams and can be discharged from treatment plants intothe environment where it rapidly bioaccumulates. As with mer-cury, selenium can be present in different species that behave dif-ferently and complicate identification and remediation.

A number of trace metals are now customarily included incrude oil analyses. Among these are calcium, copper, iron, mer-cury, nickel, selenium, sodium, and vanadium. The suite of ele-ments determined will be dictated by refinery processes,product slate, regulation, and environmental considerations.Several analytical methods are available for the routine determi-nation of many trace elements in crude oil. Some of these allowdirect aspiration of the samples (diluted in a solvent) instead ofthe time-consuming sample preparation procedures such as wetashing (acid decomposition), or flame or dry ashing (removal ofvolatile/combustible constituents). Among the techniques usedfor trace element determinations are flameless and flameatomic absorption (AA) spectrophotometry (ASTM D5863, TestMethod for Determination of Nickel, Vanadium, Iron, andSodium in Crude Oils and Residual Fuels by Flame AtomicAbsorption Spectrometry), and inductively coupled argonplasma spectrophotometry [ASTM D5708, Test Method forDetermination of Nickel, Vanadium, and Iron in Crude Oils andResidual Fuels by Inductively-Coupled Plasma (ICP) AtomicEmission Spectrometry]. A modified version of ASTM D5185,Test Method for Determination of Additive Elements, Wear Met-als, and Contaminants in Used Lubricating Oils and Determina-tion of Selected Elements in Base Oils by Inductively CoupledPlasma Atomic Emission Spectrometry, is being used by manylaboratories for the determination of elements such as lead andphosphorus in crude oils. ICP has an advantage over AA becausea number of elements can be determined simultaneously;although detection limits by AA are often better. X-ray fluores-cence spectrophotometry is also sometimes used, althoughmatrix effects can be a problem. The method to be used is gen-erally a matter of individual preference.

Many advances have been made in techniques for traceand ultra-trace sample preparation and elemental analysisincluding atomic absorption spectrometry, inductively coupledplasma emission and mass spectrometry, isotope dilution massspectrometry, and other multihyphenated methods. A numberof these are discussed in ASTM STP 1468 [31].

Vapor PressureVapor pressure is an important physical property of crude oilsimpacting shipping, storage, and refinery-handling practices.The greater the vapor pressure of a crude oil, the greater is the

potential for atmospheric emission of hydrocarbons and othervolatile compounds such as hydrogen sulfide. With the increas-ingly more stringent environmental limitations on emission ofthese compounds, it is important that the vapor pressure beknown so that crude oil stocks can be stored and handled inan appropriate manner. ASTM D323, Test Method for VaporPressure of Petroleum Products (Reid Method), and ASTMD5191, Test Method for Vapor Pressure of Petroleum Products(Mini Method), have been used for determining this property.Although the latter method is not scoped for crude oil, it isused by many laboratories for this determination. The Reidvapor pressure differs from the true vapor pressure of the sam-ple under test due to some small sample vaporization and thepresence of water vapor and air in the sample chamber usedin the test. The latter technique also does not take into accountdissolved water in the sample in determining total pressure.The measured total vapor pressure can be converted to a dryvapor pressure equivalent by use of a correlation equation. Anewer test methodASTM D6377, Test Method for Determina-tion of Vapor Pressure of Crude Oil: VPCRx (ExpansionMethod)covers determination for vapor-liquid ratios of 4:1 to0.02:1. The former ratio can be related to values determinedby ASTM D323. The latter mimics closely the situation of an oiltanker and approaches the true vapor pressure.

ASTM Manual 51 Distillation and Vapor Pressure Mea-surement in Petroleum Products includes detailed discussionof the several ASTM test methods used to measure vaporpressure of crude oil, that is, ASTM D323, D5191, and D6377[32]. This will provide the analyst a better understanding ofthe details of each method and how they apply to determina-tion of this parameter. A separate, complementary chapterprovides a more in-depth discussion of the importance ofcrude oil vapor pressure measurements as they relate todetermining regulatory compliance.

Total Acid NumberTotal acid number, as determined by ASTM D664, TestMethod for Acid Number of Petroleum Products by Potentio-metric Titration, provides an indication of the organic acidcontent of a crude oil. It will also indicate the presence ofremnant inorganic acids such as hydrochloric and hydro-fluoric that may have been used in production well workoveroperations. Collectively, these acids contribute to increasedrates of corrosion in the refinery and can contribute to insta-bility in refined products. The method does not differentiateacid species, such as carboxylic, naphthenic, or inorganic, anddoes not provide any indication of relative strength. While nogeneral correlation is known between acid number and thecorrosive tendency of oils toward metals, knowledge of theacid number is important in planning for injection of neutral-izing agents in refinery streams or reducing the acid contentto an acceptable level by other means.

Carbon ResidueCarbon residue is a useful measure of the amount of mate-rial left after evaporation and pyrolysis and provides someindication of the relative coke-forming propensity of crudeoil. The residue formed is not composed entirely of carbonbut is a coke, the composition of which can be changed byfurther pyrolysis. Two methods have historically been usedfor determination of carbon residue. These are ASTM D189,Test Method for Conradson Carbon Residue of PetroleumProducts, and ASTM D524, Test Method for Ramsbottom


Carbon Residue of Petroleum Products. No exact correlationof the results obtained by these two test methods exists,although an approximate correlation has been derived. Anewer test method, ASTM D4530, Test Method for Determina-tion of Carbon Residue (Micro Method), can be correlated toTest Method D189 and offers the advantages of better controlof test conditions, smaller samples, and less operator attention.

Other TestsOther properties that are generally determined on a morelimited basis include those listed in the sections that follow.

TOTAL NITROGEN CONTENTNitrogen compounds can contaminate refinery catalysts and,increasingly, are of concern to refiners. They also tend to bethe most difficult class of compounds to hydrogenate. Thenitrogen content remaining in the product from a hydro-treater is a measure of the effectiveness of the hydro-treatingprocess. Three test methods are available for the determina-tion of total nitrogen. They are ASTM D3228, Test Methodfor Total Nitrogen in Lubricating Oils and Fuel Oils by Modi-fied Kjeldahl Method; ASTM D4629, Test Method for TraceNitrogen in Liquid Petroleum Hydrocarbons by Syringe/InletOxidative Combustion and Chemiluminescence Detection;and ASTM D5762, Test Method for Nitrogen in Petroleumand Petroleum Products by Boat-Inlet Chemiluminescence.

ORGANIC HALIDESOrganic halide compounds are not known to occur naturallyin crude oils, and their presence commonly results from con-tamination by solvents used in cleaning operations at produc-tion sites and in pipelines and tanks. These compounds arepotentially damaging to refinery processes. For example,hydrochloric acid can be produced in hydrotreating orreforming reactors, following which the highly corrosive acidcan accumulate in condensing regions of the refinery. Largeor unexpected concentrations of the resulting acids cannotbe effectively neutralized, and damage can result. Organichalide species can also poison catalysts in reformers andadversely affect gasoline yields. Total organic halide contentof the naphtha fraction can be effectively determined usingASTM D4929, Test Method for Determination of OrganicChloride Content in Crude Oil. It is imperative that the sam-ple be distilled as described in the test method to eliminatepotential interference by inorganic salts.

ASPHALTENESAsphaltenes are the organic molecules of highest molecularmass and carbon-hydrogen ratio normally occurring in crudeoil. They may give problems during storage and handling ifthe suspension of these molecules is disturbed through excessstress or incompatibility. Their composition normally includesa disproportionately high quantity of the sulfur, nitrogen, andmetals present in crude oil. ASTM D6560, Test Method forDetermination of Asphaltenes (Heptane Insolubles) in CrudePetroleum and Petroleum Products, covers a procedure fortheir determination. ASTM D3279, Test Method for n-HeptaneInsolubles, is similar in scope to D6560 and is useful in quan-tifying the asphaltene content of crude oils.

ASHAsh present in crude oil results from the presence of non-combustible extraneous solids such as dirt, pipeline scale,

and rust. Normally there is a close correlation between acrude oils ash content and its sediment content. In the useof crude oil as a fuel, it is important to know its ash content,as this can be related directly to particulate emissions. ASTMD482, Test Method for Ash from Petroleum Products, coversthe determination of this property.

METHANOLMethanol, as with organic halides, does not occur naturallyin crude oils but is introduced artificially to prevent forma-tion of gas hydrates. These large matrixes of natural gas andwater can block or impede flow in gas pipelines. Use ofmethanol as a hydrate inhibitor occurs mostly in productionof crude oils from deep waters such as the Outer Continen-tal Shelf of the Gulf of Mexico, offshore West Africa, and inareas of the North Sea. For crude oil produced from theGulf of Mexico, methanol contamination commonly occursafter production restarts following hurricanes. As the metha-nol is water miscible, it gets carried with water present inthe crude oil to the refinery where it comes out in the watereffluent from the desalter unit. When it reaches the waste-water treatment system, it can drastically upset the balanceof the system. The bacteria used in the plant to digest oilycomponents prefer the methanol, leaving hydrocarbons andsome other toxic substances untreated. Large incursions ofmethanol can lead to a bug kill effectively deactivating thesystem. Either of these situations can result in discharge ofpollutants and environmental excursions that exceed permit-ted levels.

Currently, there is no standard test method for deter-mining methanol in crude oils containing water. ASTMD7059, Test Method for Determination of Methanol in CrudeOil by Multidimensional Gas Chromatography, is applicableonly to crude oils containing a maximum of 0.1 % (v/v)water. As such, it is not applicable to analysis of most pro-duction quality crude oil streams that commonly contain0.25 to 1.0 % (v/v) water. Several instrument manufacturershave worked on development of suitable analytical methods.A prototype, on-line gas chromatographic system for real-time measurement of methanol in a crude oil stream wastested by a crude oil pipeline company at one of its onshoreGulf of Mexico terminals, but the system did not have thenecessary capabilities or ruggedness. In the absence of astandard test method, methanol can be determined by wash-ing a sample with water, then analyzing the eluate by gaschromatography. This method is time consuming and doesnot allow for continuous monitoring of a stream. The latteris an important consideration, as methanol is usually dis-posed of in batches from offshore operations rather than ona continuous basis.

Boiling Point DistributionBoiling point distribution provides an insight into the com-position of crude oil and an estimation of the quantity ofproducts likely to be yielded in refinery processes. Simu-lated distillation using gas chromatography can be used torapidly determine this parameter without the need for aconventional potstill distillation, which is a lengthy processand requires a relatively large volume of sample. ASTMD2887, Test Method for Boiling Range Distribution ofPetroleum Fractions by Gas Chromatography, originallyapproved in 1973, was the first standardized gas chromato-graphic method for determining boiling range distribution


of petroleum. It is, however, restricted to petroleum prod-ucts and fractions in the range of 55 to 538C, which limitsits application to crude oils. ASTM D5307, Test Method forDetermination of the Boiling Range Distribution of CrudePetroleum by Gas Chromatography, covers determinationof the boiling range distribution of water-free crude oil, butstill only through 538C, which corresponds to n-C43. Mate-rial boiling above 538C is reported as residue. ASTMD7169, Test Method for Boiling Point Distribution of Sam-ples with Residues Such as Crude Oils and Atmosphericand Vacuum Residues by High Temperature Gas Chroma-tography, a method commonly abbreviated HTSD, extendsthe boiling range distribution through a temperature of720C. This temperature corresponds to the elution of n-C100.This extended range is important to the refinery engineer,because a number of heavy crude oils available in todaysmarket have a substantial amount of residue boiling wellbeyond 538C.

Further discussion on application of gas chromatographyto determination of boiling point distribution can be found inASTM Manual 51, cited earlier [32]. This includes importantconsiderations such as instrument requirements and columnselection and a comparison to physical distillation.

Determination of boiling point distribution by HTSD isuseful for rapidly obtaining information on the potentialmass percent yield of products. These data provide refinersthe ability to quickly evaluate crude oils and to select thosewith economic advantages and more favorable refining mar-gins [33]. The information it provides can be input to LPmodels and used in establishing operations conditions in the

refinery. Data on the boiling point distribution also serve asa rapid method for screening for the presence of diluents orresiduum, constituting what is commonly referred to asdumb-bell crude.

Gas chromatographic simulated distillation does not,however, provide any material for quality assessments. Thisrequires that samples be fractionated by conventional pot-still distillation methods described later in this chapter.

The inspection assay tests discussed earlier are unques-tionably not exhaustive but are the ones most commonlyused. These tests will provide the refiner with data on acrude oils handling characteristics, some of the impuritiesthat are present, evidence of spiking, and a general idea ofthe products that may be recoverable.

A summary of these inspection test methods is providedin Table 1. These tests will not, however, provide the dataessential to determining whether a given crude oil or blendof crude oils will yield an economically attractive productslate. This requires that a comprehensive assay be performed.

COMPREHENSIVE ASSAYIn addition to the whole crude oil tests performed as part ofthe inspection assay, a comprehensive or full assay requiresthat the crude be fractionally distilled and the fractions charac-terized by appropriate tests. This is necessary so that therefiner can assess the quantity and quality of products recover-able from a given crude oil and determine if that product slateeconomically satisfies the market requirements of a particularrefinery. Refiners tailor a comprehensive assay to their individ-ual needs, and the number of cuts or fractions taken may varyfrom as few as 4 to 24 or more. The following ten fractionsprovide the basis for a moderately thorough evaluation:

Commonly, from 5 to 50 L of crude oil will be needed for acomprehensive assay, depending on the number of cuts tobe taken and the tests to be performed on the fractions.Fractionation of the crude oil begins with a true boilingpoint (TBP) distillation using a fractionating column havingan efficiency of 14 to 18 theoretical plates and operated at areflux ratio of 5:1 [ASTM D2892, Test Method for Distillationof Crude Petroleum (15-Theoretical Plate Column)]. The TBPdistillation may be used for all fractions up to a maximumcut point of about 350C atmospheric equivalent tempera-ture (AET) provided reduced pressure is used to avoid crack-ing. Beyond an AET of 350C, it is necessary to continue thedistillation at further reduced pressures under conditions

TABLE 1Crude Oil Inspection AssayProperties

PropertyASTM RefereeTest Method

API, relative density, or specific gravity D1298 or D5002

Pour point D97 or D5853

Nitrogen, total, mass percent D5762

Sulfur, total, mass percent D4294

Viscosity, cSt @ 25C and 40C D445

Water, volume percent D4928

Sediment, mass percent D473

Salt, ppm D6470

Total acid number, mg KOH/g D664

Organic chlorides, ppm D4929

Hydrogen sulfide and mercaptans, ppm UOP 163

Vapor pressure, kPa @ 37.8C D323 or D6377

Trace metals, ppm D5708 or D5863

Carbon residue, mass percent D4530

Asphaltenes, mass percent D6560

Methanol, ppm Gas chromatography

Boiling range distribution D7169

C2C4 GasC579C Light naphtha79121C Medium naphtha121191C Heavy naphtha191277C Kerosene277343C Distillate fuel oil343455C Light vacuum gas oil (LVGO)455566C Heavy vacuum gas oil (HVGO)343C Atmospheric (long) residuum566C Vacuum (short) residuum


that provide approximately a one-theoretical plate fractiona-tion. ASTM D5236, Test Method for Distillation of HeavyHydrocarbon Mixtures (Vacuum Potstill Method), enablesthe distillation to be continued to a temperature of up toabout 565C AET at a pressure of 0.013 kPa, provided signifi-cant cracking does not occur. The maximum achievable AETis dependent on the heat tolerance of the charge. An oldermethod, ASTM D1160, Test Method for Distillation of Petro-leum Products at Reduced Pressure, is useful only up to amaximum liquid temperature of approximately 400C at apressure of 0.13 kPa (640C AET). Figure 1 graphicallydepicts typical TBP distillation curves for a heavy (22API)and a light (38API) crude oil.

A detailed discussion of the three ASTM methods com-monly used for a true boiling point distillation is provided inthe ASTM MNL 51 cited earlier in the discussion on vaporpressure [32]. This includes field of application, importantparameters, and precision and accuracy, as well as a com-parison of ASTM D2892 and D5236. ASTM D1160 has nowlargely been replaced by ASTM D5236 for high vacuum dis-tillation of crude oil residues.

Wiped-wall or thin-film molecular stills can also be usedto separate the higher boiling fractions under conditionsthat minimize cracking. In these units, however, cut pointscannot be directly selected, because vapor temperature inthe distillation column cannot be measured accurately underoperating conditions. Instead, the wall (film) temperature,pressure, and feed rate that will produce a cut equivalent toa D1160 or D5236 fraction with a given end point are deter-mined from in-house correlations developed by matchingyields between the wiped-wall distillation and the D1160 orD5236 distillation. ASTM D7169 should be useful in deter-mining cut points of the higher boiling fraction materialrecovered by wiped-wall distillation. Despite this indirectapproach, wiped-wall stills are often used because they allow

higher end points to be attained than with either D1160 orD5236 and can easily provide large quantities of material forcharacterization.

Following fractionation of the crude oil, each of the frac-tions is analyzed to determine one or more of its physical orchemical characteristics depending on the needs of the refiner.In the following discussion, the properties or constituents gener-ally measured in a detailed analysis of each of the given ten frac-tions are listed. All of the various tests that could be performedon each of the fractions are too numerous to be included here.Table 2 summarizes this comprehensive assay format and indi-cates representative test methods for determining the proper-ties. As with Table 1, the methods listed are those generallyaccepted as referee methods for determination of the property.

Numerous standard test methods are available for thedetermination of the properties and constituents of the distil-late and residual fractions described. These test methods willnot be enumerated in the following discussion as they aredescribed in detail in the other chapters of this manual andelsewhere [3436]. Although not listed in the table or succeed-ing discussion, volume and mass percent yields are an integralpart of the analysis. These provide critical information on thequantity of product yields, allow calculation of mass balances,and permit the analyst or refiner to reformat data using LPmodels and empirically derived correlations to obtain charac-teristics of fractions suitable to their individual needs.

GasTypically, the gas or debutanization fraction is analyzed byhigh-resolution gas chromatography for quantitative determi-nation of individual C2 to C4 and total C5 hydrocarbons.Relative density (specific gravity) can be calculated from thecompositional analysis.

Naphtha FractionsDensity or specific gravity, total sulfur, mercaptan sulfur,hydrogen sulfide, and organic halides are typically determinedon these fractions. Because these fractions, and especially thelight naphtha fraction, are important both as a petrochemicalfeedstock and as a gasoline blending component or reformerfeedstock, it is likely that they would also be analyzed by high-resolution gas chromatography for quantitative determinationof their paraffin, isoparaffin, aromatic, and naphthene (cyclo-paraffin) components (PIAN analysis) (ASTM D5134, TestMethod for Detailed Analysis of Petroleum Naphthas throughn-Nonane by Capillary Gas Chromatography). Through judi-cious selection of columns and operating conditions, some lab-oratories have extended this method to n-dodecane (bp 216C).

Octane numbers would also be determined for these frac-tions if they were to be included as a gasoline-blending compo-nent. Historically, octane numbers are determined using specialengines that require relatively large volumes of sample. Today,many companies are now using semi-micro methods that requireconsiderably less sample than the engine test methods for deter-mination of octane numbers [37]. Other laboratories use PIANdata to calculate octane numbers [5]. For the heavy naphtha frac-tion, aniline point would also normally be determined.

Included in the information that can be derived from thePIAN analysis are the concentrations of benzenebenzene pre-cursors (compounds that ultimately form benzene in a refin-erys reforming unit), ethyl benzene, toluene, and xylene (B-E-T-X). These data are important because of environmental regu-lations limiting the maximum concentration of benzene in

0

100

200

300

400

500

600

0 10 20 30 40 50 60 70 80 90 100

Volume Percent Distilled

Tem

per

atu

re,

C

Gases

Naphthas

Kerosine

Distillate Fuel Oil

Vacuum Gas Oils

Residuum

(a) (b)

Fig. 1True boiling point (TBP) distillation curves for (a) a heavy(22API) crude oil and (b) a light (38API) crude oil.


LIVE GRAPHClick here to view

TABLE 2Crude Oil Comprehensive Assay Format

Property

ASTMRepresen-tativeTest

MethodsWholeCrude

C2C4Gases

C579CLight

Naphtha

79121CMediumNaphtha

121191CHeavyNaphtha

191277CKerosine

277343CDistillateFuel Oil

343455CLight VGO

455566CHeavyVGO

343 C Atmos-pheric

Residuum

566C VacuumResiduum

Volume and mass percentyields

D2892andD5236

X X X X X X X X X X

API, density, specificgravity

D5002 X X X X X X X X X X

Sulfur, total, masspercent

D4294 X X X X X X X X X X

Sediment, mass percent D473 X

Water, volume percent D4928 X

Salt, mass percent D6470 X

Nitrogen, total, masspercent

D5762 X X X X X X X

Nitrogen, basic, masspercent

D2896 X X X X

Carbon residue, masspercent

D4530 X X X X X

Pour point D5853 X X X X X X

Metals: Ni, V, Fe, Cu D5708 X X X

Organic chlorides, total,ppm

D4929 X X X X X

UOP K factor UOP 375 X

Vapor Pressure, kPa @37.8C

D323 orD6377

X

Acid number, mg KOH/g D664 X X X X X X X

H2S and mercaptans, ppm UOP 163 X X X X X

Paraffins, isoparaffins,aromatics, naphthenes(PIAN)

D5134 B-T-E-X X X X X

114SIG

NIFIC

ANCEOFTESTS

FORPETR

OLEU

MPR

ODUCTS

n8TH

EDITIO

N

Viscosity, cSt, @ 25C D445 X X

40C X X X

55C X X X X

80C X X X X

100C X

120C

High temp. sim.distillation

D7169 X

Hydrogen and carbon,mass percent

D5291 X X X X

Refractive index @ 20C D1218 X X

Research and motoroctane numbers

Calcula-tion fromPIANdata

X X X

Asphaltenes, masspercent

D6560 X X X

Aniline point D611 X X X X X

Cetane index D976 X X X

Naphthalenes, volumepercent

D1840 X X

Smoke point, mm D1322 X X

Freezing point D2386 X

Cloud point D5773 X X X X

Penetration D5 X

Softening point D36 X

CHAPTER

8n

CRUDEOILS

115

reformulated gasoline and because of the importance of thesecompounds as petrochemical feedstocks and intermediates.

KeroseneTypically, density or specific gravity, total sulfur, mercaptansulfur, hydrogen sulfide, organic halides, aniline point, totalacid or neutralization number, naphthalene content, smokepoint, total nitrogen, viscosity, and pour, cloud, and freezingpoints would be determined for this fraction and a cetaneindex calculated. Other tests that might be performed,depending on the intended end use of the fraction, are flashpoint, corrosiveness, and thermal stability.

As discussed earlier in Sulfur Content, thermally reac-tive sulfur compounds such as mercaptans may be presentin crude oils. On heating or distillation, these can decom-pose to form hydrogen sulfide, giving rise to its presence inthe naphtha and kerosene fractions.

Distillate Fuel OilTests of the distillate fuel oil fraction, which includes mate-rial used to produce aviation turbine fuel, normally includedetermination of density or specific gravity, total sulfur, ani-line point, total acid number, naphthalene content, smokepoint, total nitrogen, viscosity, cloud, freeze, and pour points,and calculation of cetane index. Thermal stability and corro-siveness may also be determined in more thorough evalua-tions. Measurement of refractive index is also useful incorrelative methods, especially in LP models, for determina-tion of the gross composition of this fraction.

Vacuum Gas Oil FractionsDensity or specific gravity, total sulfur, total nitrogen, anilinepoint, viscosity, acid number, cloud and pour points, and car-bon residue would normally be determined on these frac-tions. Cetane index would be determined on the light vacuumgas oil if the material is to be used as diesel fuel oil blendingstock. If the heavy gas oil fraction is to be used as catalyticcracker feedstock, asphaltenes would also be determined.Hydrogen and carbon content would also be determined onfractions to be used as catalytic cracker feedstock. Lube stockevaluations would include determination of wax content.Basic nitrogen is also typically determined on these fractions.In general, however, the ratio of basic to total nitrogen is onthe order of 0.3:1 for many crude oils and virgin stocks. Italso appears that the types of nitrogen compounds present invarious crude oils are essentially the same, although theactual amounts may vary considerably [38]. Consequently, formost assays it is sufficient to determine total nitrogen.

ResiduumTests of the residuum fractions usually include density orspecific gravity, total sulfur, total and basic nitrogen, acidnumber, viscosity, trace metals, asphaltenes, and carbon resi-due. Hydrogen/carbon ratio and pour point determinationson the atmospheric (long) and vacuum (short) residua arealso important. Increasingly, refiners are minimizing produc-tion of material that formerly went into heavy fuels such asNo. 6 and bunker oil as markets for these diminish.

Determination of the properties of asphalt, such as penetra-tion (ASTM D5, Test Method for Penetration of BituminousMaterials), softening point [ASTM D36, Test Method for Soften-ing Point of Bitumen (Ring-and-Ball Apparatus)], and viscosity,would also be included in some assays. These tests were,

however, developed in an era of less traffic and significantlylower pavement loadings and are no longer suitable for evaluat-ing asphalt to be used as a binder. Newer Performance Gradetests such as Dynamic Shear Rheometer, Rolling Thin FilmOven, and Direct Tension Test have been developed [39].

Assay SummaryIn the preceding discussion, the tests listed for each fractionand for the whole crude oil assay are not exhaustive but areillustrative of those used to evaluate quality. As noted earlier,refiners tailor their analytical scheme to their particularcrude oil and product slates, although one refiner is reportedto have said The best crude oil assay is a 100,000 bbl runthrough my refinery [40]. While this opinion carries somevalidity, the assay tests presented here provide data that aresufficient for most refiners to evaluate crude oil streams.

With the proliferation of computer LP models and theirassociated assay libraries [9], many refiners no longer needto perform comprehensive assays as frequently as in the past.Often, an inspection assay is all that is required for them toplan for changes in processing that will be necessitated byvarying levels of impurities or small changes in crude oilcomposition resulting from changes in the production com-mingled to make up the crude oil stream. Most important,an inspection assay can be completed much more rapidlythan a comprehensive assay and requires considerably lessmaterial. Collectively, these can result in savings in analyststime and in shipping and handling expenses.

The quality of cargoes arriving at refineries may not con-form to what is known or expected for that stream. This canbe the result, among other causes, of new production comingon-stream and being commingled with existing production,or field maintenance. The analyst or refiner can use theFlash Assay Tool [41] to update an existing comprehensiveassay on the stream in question with a minimum of data. Thetool uses HTSD and various whole crude properties such asAPI gravity or density and total sulfur content to adjust theolder assay. The new assay, together with a refinery LPmodel, can then be used to make quick decisions on purchas-ing and running a challenged (opportunity) crude, for exam-ple. The flash assay can also be used to indicate whenanother full assay should be run. With the proliferation ofnew streams and with new production being added into old,a flash assay can result in considerable cost and time savings.

Moreover, todays trend is toward automated, real-timeanalysis using on-line detectors to the extent permitted byavailable instrumentation. Some of this instrumentation hasthe capability to provide data suitable for custody transferdetermination of crude oil properties, but this is currentlyquite limited. It seems likely, however, that significant advan-ces in this area will be accomplished in the near future, fur-ther removing the laboratory analyst from characterizationof crude oil feedstocks.

REFEREE TEST METHODSWhen two or more test methods are available for determin-ing a property, one is customarily designated as the refereeor primary method in testing protocols. This provides forresolving disputes in cases where two methods yield differ-ent results on the same material. The methods listed inTable 1 are those generally accepted as referee methods fordetermination of the property. In some cases, two test meth-ods are listed for the same property, as their respective


scopes differ or the methods provide equivalent results. Inthese cases, it is important that the purpose of the analysisand the nature of the material are clearly understood inselecting a suitable referee method.

SAMPLINGThe importance of adhering to a rigorous sampling protocolto ensure that samples are representative of the bulk mate-rial cannot be overemphasized. Representative samples arerequired for the determination of chemical and physicalproperties used to establish standard volumes and compli-ance with contractual specifications. Maintaining composi-tional integrity of these samples from the time of collectionuntil they are analyzed requires care and effort.

Moreover, it is critically important that the sampling proce-dure does not introduce any contaminant into the sample orotherwise alter the sample so that subsequent test results areaffected. Procedures for collection and handling of samples forhydrogen sulfide (H2S) determination are especially criticalbecause of the highly reactive nature and volatility of this com-pound. Appendix A provides recommended procedures suita-ble for collection and handling of samples for determination ofH2S in crude oil. These were developed by the U.S. Departmentof Energys Strategic Petroleum Reserve in support of its crudeoil assay program and underwent rigorous field and laboratorytesting [42]. With proper handling, samples do not exhibit lossof their H2S for a minimum of 10 days.

ASTM D4057, Practice for Manual Sampling of Petroleumand Petroleum Products, provides procedures for manuallyobtaining samples from tanks, pipelines, drums, barrels, andother containers. This practice addresses, in detail, the variousfactors that need to be considered in obtaining a representa-tive sample. It must be kept in mind that, in many liquid man-ual sampling applications, the material to be sampled containsa heavy component, such as free water, which tends to sepa-rate from the main component. Unless certain conditions canbe met to allow for this, an automatic sampling system asdescribed in ASTM D4177, Practice for Automatic Sampling ofPetroleum and Petroleum Products, is recommended.

ASTM D5854, Practice for Mixing and Handling of Liq-uid Samples of Petroleum and Petroleum Products, coversthe handling, mixing, and conditioning procedures that arerequired to ensure that a representative sample is deliveredfrom the primary sample container or receiver into the ana-lytical test apparatus or into intermediate containers. Thispractice also provides a guide for selecting suitable contain-ers for crude oil samples for various analyses.

ASTM D5842, Practice for Sampling and Handling ofFuels for Volatility Measurements, covers procedures andequipment for obtaining, mixing, and handling representa-tive samples of volatile fuels. While directed to productssuch as gasoline and reformulated fuels, the guidance pro-vided is useful in sampling and handling of crude oils.

Chain-of-custody procedures are a necessary element ina program to ensure ones ability to support data and con-clusions adequately in a legal or regulatory situation. ASTMD4840, Guide for Sample Chain-of-Custody Procedures, con-tains a comprehensive discussion of potential requirementsfor a sample chain-of-custody program and describes theprocedures involved. The purpose of these procedures is toprovide accountability for and documentation of sampleintegrity from the time samples are collected until theirdisposal.

CRUDE OIL AS FUELCrude oil has been used directly as a fuel for power genera-tion in a number of applications for more than 100 years.Among the earliest documented uses was as fuel for theCleveland City Cable Railway power plant in Cleveland,Ohio, in 1891 [43]. In 1892, it was reported there are somesuch progressive brick manufacturers in Chicago, who useneither coal nor wood in the drying or burning of their clayproducts. Crude oil is the fuel which they employ [44]. In1900, crude oil was used to power a railroad locomotive in atrial run in Corsicana, Texas. A history of Anheuser Busch,the American brewing giant, mentions that Adolphus Buschobtained the American rights to build diesel engines in 1897and that the companys first engine was installed in theAnheuser Busch power plant in 1898. While not statingexplicitly that crude oil was used to fuel this engine, the his-tory states as now is well known, the Diesel engine operatesvery economically, using crude oil as fuel [45].

In 1915, the New International Encyclopedia stated,nearly all crude oil can be used by fuel (for ships). If it con-tains very little sulphur or asphalt, it is suitable for heavy oilengines of the Diesel type. The article went on to state thatcrude oil is not, however, much used for either of these pur-poses and the reasons are the presence of the more vola-tile oils renders storage dangerous [46].

In 1975, crude oils with a wide range of properties wereinvestigated for direct use as fuel in U.S. Army high-speeddiesel engines [47]. Results of this study indicated that, withproper selection and pretreatment, crude oils are feasible foremergency use.

In recent years, crude oil has been used as fuel underboilers, in gas turbines used for standby power generation,and in diesel engines worldwide. Since 1993, crude oil hasreplaced other sources of energy to fire cement kilns inCuba. One of two heating systems in the Republic of Mace-donia uses crude oil as fuel. In 2004, China purchased threediesel engines from a Finnish company for installation onone of its offshore production platforms specifically to gen-erate electricity using crude oil from the oilfields produc-tion as fuel [48]. In 2006, Japan used on the order of90,000100,000 barrels per day of crude oil to fire some ofits thermal power plants [49]. And, contrary to the admoni-tion in the 1915 New International Encyclopedia articleabout crude oils dangers, a number of tanker operatorshave, at times, surreptitiously and unlawfully diverted someof their cargo to power their ships. These incidents have notbeen without disastrous consequences, and fires and explo-sions have occurred.

Cost and availabilityespecially in remote operationalareasare certainly factors influencing the selection of crude oilover conventional burner, diesel, and gas turbine fuels. Other fac-tors must also be considered, among them safety, environmentalemissions, and the impact use of crude oil will have on the per-formance and maintenance of engines, turbines, and boilers.

No specifications have been established for crude oil tobe used in these applications, but certain properties criticalto the operation of burners, engines, and turbines must betaken into consideration. Among these are flash point, sul-fur, ash content, pour point and viscosity, wax content, car-bon residue, and metals contentespecially vanadium,nickel, and sodium. As crude oils usually have relatively lowflash points, their use as a fuel has an associated fire hazardand inherent risk of explosion necessitating that storage


facilities be appropriately configured. Furthermore, crudeoils selected for use as burner fuels must have suitable fluid-ity properties to ensure they are pumpable and can be aspi-rated in the burner or turbine. Moreover, the crude oilshould have low ash and sulfur contents. These are impor-tant environmental considerations from the standpoints offly ash (particulates) and sulfur dioxide emissions. Theasphaltic residuum from burning of crude oils can build upon heat transfer surfaces, reducing their efficiency, and canclog burners. Crude oils to be used for gas turbines mustalso have low concentrations of trace metals to ensure thatturbine blades are not adversely affected.

The standard test methods described elsewhere in thischapter for characterizing crude oils as refinery feedstocksare equally applicable to determining its use as a fuel.

CRUDE OIL COMPATIBILITYThe blending of compositionally different crude oils and crudeoil with condensate can result in significant problems in trans-portation, storage, and refining. This is usually manifestedby agglomeration or flocculation of waxes or asphaltenes, orboth. These can accumulate and clog tubular componentssuch as pipelines and heat exchangers or contribute to sludgebuildup in tanks, requiring costly and time-consuming cleanupand equipment downtime.

The problem has been recognized for many years, but nostandard method has been developed that reliably predictswhether particular blends will be incompatible, quantify theextent to which waxes and asphaltenes will accumulate, ordetermine when onset of incompatibility will begin once com-ponents are mixed. This latter is complicated by the fact thatconsiderable empirical evidence indicates there can be aninduction period of 3 or more days prior to onset.

Historically, two test methods used for testing compati-bility of residual fuel oil mixtures have been applied tocrude oil blends: ASTM D4740, Test Method for Stability andCompatibility of Residual Fuels by Spot Test, and ASTMD4870, Test Method for Determination of Total Sedimentin Residual Fuels. Other test methods, which range fromsimple to complex, include modified Shell Spot test [50],Asphaltene Stability Index [51], and Oil CompatibilityModel [52].

Two automated instrumental test methods seem promis-ing for determining stability and compatibility of crude oils.ASTM D7112, Test Method for Determining Stability andCompatibility of Heavy Fuel Oils and Crude Oils by HeavyFuel Oil Stability Analyzer (Optical Detection), is a procedureinvolving titration and optical detection of precipitatedasphaltenes. ASTM D7157, Test Method for Determination ofIntrinsic Stability of Asphaltene-Containing Residues, HeavyFuel Oils, and Crude Oils (n-Heptane Phase Separation; Opti-cal Detection), is a procedure for quantifying the intrinsicstability of the asphaltenes in an oil using an optical device.

FUTURE NEEDS IN CRUDE OILCHARACTERIZATIONThe average quality of crude oil being processed in refin-eries is becoming higher in sulfur and heavier [53]that is, agreater content of heavy ends or residuum. With the grow-ing demand for transportation fuels, the refiner is faced withmounting pressure to make better use of the bottom of thebarrelthe residuum that formerly went into low-qualityproducts such as No. 6 and bunker fuel oils. Diminishing

worldwide demand for these latter fuels is exacerbating theneed to use this material to produce other products, espe-cially lighter fuels. Moreover, as environmental restrictionsincreasingly limit sulfur and aromatics in transportation andburner fuel oils, refiners are facing new challenges to econom-ically produce a marketable slate of products from heavier,higher-sulfur feedstocks. These challenges generally requirenew or expanded processing and treatment technology at therefinery. This, in turn, translates into the need for new analyti-cal test methods in the laboratory to adequately evaluate feed-stocks and monitor product quality.

Existing analytical methods may not, however, be suita-ble for characterizing many of todays crude oil streams. Thescope of these methods may not be sufficiently broad tocover the range in quality of some of the heavier and highersulfur crude oils and nonconventional streams such as bitu-men and synthetic crude oil derived from Canadian oilsands and Venezuelan heavy oils. Consequently, at a mini-mum, it may be necessary to conduct new interlaboratoryround robin studies to validate the precision statements.With the consolidations within the industry and the growingdemands being placed on the analyst, this may not bepracticable.

The Canadian Crude Quality Technical Association hasused the extensive experience of its members to compile amanual of Heavy Oil and Bitumen Analytical Methods [54].At the end of 2008, this manual provided a review of existingtest methods for eight parameters commonly used in assess-ing quality of heavy oils and bitumen and discussed theircapabilities and limitations. When available, precision dataobtained from round robin studies on heavy oils and bitu-men are included. The analytical sections in this manual arenot a substitute for test methods specific to heavy oils andbitumen, but they do help users to make informed decisionson methods selection, sample preparation, test modifica-tions, and interpretation of resultant data.

Sulfur reduction processes are sensitive to both amountand structure of the sulfur compounds being removed. Teststhat can provide information about both are becomingincreasingly important. A number of laboratories have com-bined gas chromatography with sulfur-selective detectors toprovide data on the boiling range distribution of the sulfurcompounds and probable molecular types. In addition, gaschromatography detectors that provide selectivity for otherconstituents of interest, such as nitrogen and organometal-lics, are also commercially available and being increasinglyused for characterization.

The supply of high-TAN crude oils, that is those with a TAN>1.0, is increasing substantially on a global basis. To adequatelyassess and plan the effective refinery processing of these, it isimportant to know the acid species present. Naphthenic acidsin particular can be especially detrimental throughout a refin-ery. A number of crude oils today contain high concentrationsof calcium that will contribute to formation of egregious naph-thenic acid soaps. These soaps can cause formation of highlystable emulsions that can be carried through to wastewatertreatment plants. Naphthenic acids can be very corrosive, but itis important to know their species as they behave differentlydepending on the various conditions of temperature, flowvelocity, and metallurgy existing within a refinery. ASTM D664,which is used almost universally for determining the acid con-tent of a crude oil, provides no information on either the acidspecies present or their relative strength. A rapid and reliable


method for characterizing the components contributing to theacidity of a crude oil as well as their relative strength is needed.

Upgrading the bottom of the barrel involves convert-ing moreideally allof the residuum into a more salable,higher-valued product (100 % residuum conversion). What-ever the means to this end, improved characterization meth-ods are necessary for process design, crude oil evaluation,and operational control. Characterization methods thatdefine the boiling range and the hydrocarbon type distribu-tion of heavy residuum are of growing importance. High-temperature, gas chromatography simulated distillation hasbeen used to obtain cut point data up to an atmosphericequivalent boiling point temperature of 740C [55].

The distributions of hydrocarbon types in gas oil andheavier materials are important in evaluating them as feed-stocks for further processing. Some older mass spectromet-ric methods for determining hydrocarbon types are beingupdated for use with modern quadrupole mass spectrome-ters, either with batch inlets or with gas chromatographicinlets (GC/MS). Another technique that has been successfullyapplied for determining hydrocarbon types in these materi-als involves the use of high-performance liquid chromatogra-phy (HPLC), which can provide information comparable tothe mass spectrometric methods. Standardized HPLC techni-ques are now being used to determine aromatic hydrocar-bon types in middle distillate and aviation fuels.

With the large volumes of crude oil being moved intodays markets, and with the growing availability of oppor-tunity or challenged crude oils, comes increasing pressure todetermine key properties in less time and with a high degreeof confidence in the results. While opportunity crudes maybe financially attractive to the crude oil buyer, they can be aproblem to the refiner. They may be high-TAN or containexcessive levels of certain contaminants. Their product yieldsand qualities may be unknown or undesirable. For example,excessive residuum yields can overload a coker, and the cokeproduced may not be of the quality needed to satisfy theexisting market. With the need for rapid turnaround ofstocks and the relatively limited storage available in mostrefineries, these streams may be processed before conven-tional analyses are complete.

Rapid, automated instrumental methods of analysis con-tinue to be the option of choice in responding to thesedemands. Laboratories are constantly seeking to reduce anal-ysis time, improve the quality of test results, and eliminatedependency on time-consuming manual methods of analysis.Advances in technology are helping to meet the analyticalchallenges of the industry.

Predictive methods that can rapidly provide accuratephysiochemical and boiling range data are the holy grailof the crude oil analyst. A number of systems have been pro-posed but all have limitations that constrain their usefulness.Molecular modeling can be used to provide the degree ofcharacterizations necessary, but it involves tedious samplepreparation, lengthy component separation, use of advancedanalytical instrumentation, and development of a large data-base containing reference material [15].

In the absence of these predictive methods, refiners andanalysts are fortunate to have at their disposal LP programswith their built-in correlations and ability to recut data totheir specific needs. Ultimately, however, they still must relyon a comprehensive assay to validate output from computermodels.

APPENDIX A: PROCEDURES FOR COLLECTIONOF SAMPLES FOR H2S DETERMINATIONThese procedures have been found suitable for collection ofsamples for determination of H2S in crude oil [41]. Prior tocollecting either high density polyethylene (HDPE) or float-ing piston cylinder samples, thoroughly flush the samplingpoint and all connections.

HDPE bottles1 L capacity. Prepare the bottles by placingabout 10 g of dry ice into each. Place the cap on the bottle andtighten loosely. Shake the bottle vigorously, and periodicallyloosenbut do not remove the capto relieve excess pressure.Continue this process until the dry ice has evaporated. Once thedry ice has evaporated, tighten the cap and set aside until the bot-tle is needed for sampling. Do not overpressure the bottles. If thebottles are not relieved of pressure buildup, they may explode.

Bottles may be prepared up to 2 days in advance ofwhen they will be needed. It is advisable to prepare at leastone extra bottle in case one leaks.

When ready to collect the sample, remove the bottle cap.There must be an audible hiss indicating the presence of car-bon dioxide (CO2) overpressure. If not, use another bottle.Slowly fill the bottle using a polytetrafluoroethylene (PTFE)tube extending to the bottom. When the bottle is full to thetop of the shoulder, that is, just below the threads, squeezethe bottle at the center just enough to cause a small amount(a few drops) of oil to spill over the lip of the bottle. Screwthe cap tightly onto the bottle and seal with plastic tape. Keepthe bottle refrigerated or on ice. If shipping is necessary,package samples with dry ice and in accordance with Inter-national Air Transport Association (IATA) regulations.

Samples collected in this manner, when kept cold, maybe used for determination of H2S for up to 10 days follow-ing their collection.

Floating piston cylinders (Sulfinert-treated). Prior touse, cylinders should have a back-pressure at least 100 psigreater than that of the pipeline from which samples are tobe collected. Argon should be used as back-pressure gas, andnot nitrogen or helium. No further preparation is necessary.Make connections to the pipeline with Sulfinert-treatedstainless steel or high pressure PTFE tubing. Slowly open thevalve nearest the pipeline and check for leaks. Next, slowlyopen the bleed valve on the cylinder and bleed at least 250mL to waste to purge the system and displace air. Then,slowly open the third valve and gradually reduce the backpressure until it approaches that of the pipeline. Once theindicator rod begins to move, continue to slowly bleed theback-pressure until the tip of the indicator rod is withinapproximately 1 cm of the red end cap. Several minutesshould be allowed for this process in order to maintain a sin-gle phase in the cylinder. Tighten all valves, and then discon-nect from the pipeline. Replace all plugs using PTFE tape.

Floating piston cylinders do not need to be refrigerated.

ASTM and UOP Standards

ASTM UOP Title

D5 Penetration of Bituminous Materials

D36 Softening Point of Bitumen (Ring-and-Ball Apparatus)

D97 Pour Point of Petroleum Products


ASTM UOP Title

D129 Sulfur in Petroleum Products (GeneralBomb Method)

D189 Conradson Carbon Residue of PetroleumProducts

D287 API Gravity of Crude Petroleum andPetroleum Products (Hydrometer Method)

D323 Vapor Pressure of Petroleum Products(Reid Method)

D341 Viscosity-Temperature Charts for LiquidPetroleum Products

D445 Kinematic Viscosity of Transparent andOpaque Liquids (and the Calculation ofDynamic Viscosity)

D473 Sediment in Crude Oils and Fuel Oils bythe Extraction Method

D482 Ash from Petroleum Products

D524 Ramsbottom Carbon Residue of Petro-leum Products

D664 Acid Number of Petroleum Products byPotentiometric Method

D1160 Distillation of Petroleum Products atReduced Pressure

D1250 Petroleum Measurement Tables

D1298 Density, Relative Density (Specific Grav-ity), or API Gravity of Crude Petroleumand Liquid Petroleum Products byHydrometer Method

D1552 Sulfur in Petroleum Products (High-Temperature Method)

D2161 Conversion of Kinematic Viscosity to Say-bolt Universal Viscosity or to SayboltFurol Viscosity

D2622 Sulfur in Petroleum Products by X-RaySpectrometry

D2887 Boiling Range Distribution of PetroleumFractions by Gas Chromatography

D2892 Distillation of Crude Petroleum (15-Theo-retical Plate Column)

D3228 Total Nitrogen in Lubricating Oils andFuel Oils by Modified Kjeldahl Method

D3230 Salts in Crude Oil (Electrometric Method)

D3279 n-Heptane Insolubles

D4006 Water in Crude Oil by Distillation

D4007 Water and Sediment in Crude Oil by theCentrifuge Method (LaboratoryProcedure)

D4057 Manual Sampling of Petroleum andPetroleum Products

D4177 Automatic Sampling of Petroleum andPetroleum Products

ASTM UOP Title

D4294 Sulfur in Petroleum Products by Energy-Dispersive X-Ray FluorescenceSpectrometry

D4377 Water in Crude Oil by PotentiometricKarl Fischer Titration

D4530 Determination of Carbon Residue (MicroMethod)

D4629 Trace Nitrogen in Liquid PetroleumHydrocarbons by Syringe/Inlet OxidativeCombustion and Chemiluminescence

D4740 Cleanliness and Compatibility of ResidualFuels by Spot Test

D4807 Sediment in Crude Oil by MembraneFiltration

D4840 Sampling Chain-of-Custody Procedures

D4870 Determination of Total Sediment inResidual Fuels

D4928 Water in Crude Oil by Coulometric KarlFischer Titration

D4929 Determination of Organic ChlorideContent in Crude Oil

D5002 Density and Relative Density of CrudeOils by Digital Density Analyzer

D5134 Detailed Analysis of Petroleum Naphthasthrough n-Nonane by Capillary GasChromatography

D5185 Determination of Additive Elements,Wear Metals, and Contaminants in UsedLubricating Oils and Determination ofSelected Elements in Base Oils byInductively-Coupled Plasma AtomicEmission Spectrometry (ICP-AES)

D5191 Vapor Pressure of Petroleum Products(Mini Method)

D5236 Distillation of Heavy HydrocarbonMixtures (Vacuum Pot Still Method)

D5291 Instrumental Determination of Carbon,Hydrogen, and Nitrogen in PetroleumProducts and Lubricants

D5307 Determination of the Boiling RangeDistribution of Crude Petroleum by GasChromatography

D5708 Determination of Nickel, Vanadium, andIron in Crude Oils and Residual Fuels byInductively-Coupled Plasma (ICP) AtomicEmission Spectrometry

D5762 Nitrogen in Petroleum and PetroleumProducts by Boat-InletChemiluminescence

D5842 Sampling and Handling of Fuels for Vol-atility Measurement

D5853 Pour Point of Crude Oils


References[1] Rossini, F. D., Hydrocarbons in Petroleum, J. Chem. Educ.,

Vol. 37, 1960, pp. 554561.[2] Mair, B. J., Annual Report for the Year Ending, June 30, 1967,

American Petroleum Institute Research Project 6, Carnegie Insti-tute of Technology, Pittsburgh, PA, 1967.

[3] Rail, H. T., Thompson, C. J., Coleman, H. J., and Hopkins, R. L.,Sulfur Compounds in Oil, Bulletin 659, U.S. Department ofthe Interior, Bureau of Mines, 1972.

[4] Csoklich, C., Ebner, B., and Schenz, R., Modern CrudeOil PracticesAustrias OEMV, Oil Gas J., March 21, 1983,pp. 8690.

[5] ODonnell, R. J., Modern Crude Oil PracticesStandard Oil ofCalifornia Companies, Oil Gas J., March 21, 1983, pp. 9093.

[6] McNelis, F. B., Modern Crude Oil PracticesExxon Organ-izations, Oil Gas J., March 21, 1983, pp. 9497.

[7] Wampler, R. J., and Kirk, E. L., Modern Crude Oil PracticesGulf Companies, Oil Gas J., March 21, 1983, pp. 98104.

[8] Nelson, G. V., Schierberg, G. R., and Sequeira, A., ModernCrude Oil PracticesThe Texaco System, Oil Gas J., March 21,1983, pp. 108, 112, 116, 118120.

[9] McCleskey, G., and Joffe, B. L., Modern Crude Oil PracticesPhillips Petroleum Co., Oil Gas J., March 21, 1983, pp. 124,126127.

[10] Aalund, L. R., Guide to Export Crudes for the 80s1 to 13,Oil Gas J., April 11, May 2, 23, June 6, 20, July 4, 25, Aug. 22,Sept. 5, Oct. 24, Nov. 7, 21, Dec. 12, 19, 1983.

[11] Crude oil assay, Wikipedia, The Free Encyclopedia, 12 Septem-ber 2008, http://en.wikipedia.org/wiki/Crude_oil_assay.

[12] ODonnell, J., Crude Oils, Criteria for Quality of PetroleumProducts, J. P. Allison, Ed., John Wiley, New York, 1973, pp.1021.

[13] Smith, N. A. C., Smith, H. M., Blade, O. C., and Garton, E. L.,The Bureau of Mines Routine Method for the Analysis ofCrude Petroleum 1. The Analytical Method, Bulletin 490, U.S.Department of the Interior, Bureau of Mines, 1951.

[14] Ali, M. A., Full Range Crudes, Analytical Methodology of,Encyclopedia of Analytical Chemistry, R. A. Meyers, Ed., Vol. 8,pp. 67096726, John Wiley and Sons Ltd., Chichester, 2000.

[15] Watts, M. R., and Roussis, S. G., Crude Assay, Practical Advan-ces in Petroleum Processing, C. S. Hsu and P. R. Robinson, Eds.,pp. 103116, Springer, New York, 2006.

[16] Protecting Crude Oil Quality, a report of the API Ad HocCrude Oil Quality Task Force, American Petroleum Institute,Washington, DC, February 1993.

[17] Neihof, R. A., Hydrogen Sulfide Analyzer with Protective Bar-rier. U.S. Patent No. 5,529,841, U. S. Patent and TrademarkOffice, Washington, DC, June 25, 1996.

[18] Impurities in Petroleum, Petrolite Corporation, Houston, 1958.[19] Manual of Petroleum Measurement Standards Chapter 17.3

Guidelines for Identification of the Source of Free Waters Asso-ciated with Marine Petroleum Cargo Movements, First Edition,American Petroleum Institute, Washington, DC, 1992.

[20] Watson, K. M., Nelson, E. F., and Murphy, G. B.,Characterization of Petroleum Fractions, Ind. Eng. Chem.,Vol. 27, 1935, pp. 14601464.

[21] Nelson, W. L., Which Base of Crude Oil Is Best? Oil Gas J.,Jan. 8, 1979, pp. 112113.

[22] Valkovic, V., Trace Elements in Petroleum, The Petroleum Pub-lishing Co., Tulsa, OK, 1978.

[23] Yen, T. F., Ed., The Role of Trace Metals in Petroleum, AnnArbor Science Publishers, Inc., Ann Arbor, MI, 1975.

[24] Jones, P., Trace Elements and Other Elements in Crude Oil: ALiterature Review, unpublished manuscript, The British Petro-leum Co., Ltd., BP Research Center, Sunbury, UK, September1975.

[25] Jones, M. C. K., and Hardy, R. L., Petroleum Ash Componentsand Their Effect on Refractories, Ind. Eng. Chem., Vol. 44,1952, pp. 26152619.

[26] Woodle, R. A., and Chandler, W. B., Jr., Mechanisms of Occur-rence of Metals in Petroleum Distillates, Ind. Eng. Chem., Vol.44, 1952, pp. 25912596.

[27] Dreyfus, S., Origin and Nature of Trace Metals in Crude Oil,Crude Oil Quality Group, March 6, 2008, New Orleans, LA,www.coqg.org Meeting Archives.

[28] Dekkers, C., and Daane, R., Metal Contents in Crudes MuchLower than Expected, Oil Gas J. March 1, 1999, pp. 4451.

[29] Wilhelm, S. M., Kirchgessner, D. A., Liang, L., and Kariher, P. H.Sampling and Analysis of Mercury in Crude Oil, R. A. K.Nadkarni, Ed., Elemental Analysis of Fuels and Lubricants:Recent Advances and Future Prospects, STP 1468, ASTM Inter-national, West Conshohocken, PA, 2005.

[30] Long, S. E., Kelly, W. R., Mann, J. L. and Giles,

crude oils

Documents

crude slate

characterization of

composition of crude

crude oil analyses

crude oilsharry

giles1crude oils

comprehensivecrude oil

slate of products