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Based on the configuration, the most common types of separator are horizontal, vertical, and spherical, Large horizontal gas–oil separators are used almost exclusively in processing well fluids in the Middle East, where the gas–oil ratio of the producing fields is high. Multistage GOSPs normally consists of three or more separators.
The following is a brief description of some separators for some specific applications. In addition, the features of what is known as ‘‘modern’’ GOSP are highlighted.
These units are used to separate and measure at the same time the well fluids. Potential test is one of the recognized tests for measuring the quantity of both oil and gas produced by the well in 24 hours period under
steady state of operating conditions. The oil produced is measured by a flow meter (normally a turbine meter) at the separator’s liquid outlet and the cumulative oil production is measured in the receiving tanks.
An orifice meter at the separator’s gas outlet measures the produced gas. Physical properties of the oil and GOR are also determined. Equipment for test units.
Safe and environmentally acceptable handling of crude oils is assured by treating the produced crude in the GOSP and related crude-processing facilities. The number one function of the GOSP is to separate the associated gas from oil. As the water content of the produced crude increases, field facilities for control or elimination of water are to be
added. This identifies the second function of a GOSP. If the effect of corrosion due to high salt content in the crude is recognized, then modern desalting equipment could be included as a third function in the GOSP design.
One has to differentiate between ‘‘dry’’ crude and ‘‘wet’’ crude. The former is produced with no water, whereas the latter comes along with water. The water produced with the crude is a brine solution containing salts (mainly sodium chloride) in varying concentrations.
The input of wet crude oil into a modern GOSP consists of the following:
1. Crude oil.
2. Hydrocarbon gases.
3. Free water dispersed in oil as relatively large droplets, which will separate and settle out rapidly when wet crude is retained in the vessel.
4. Emulsified water, dispersed in oil as very small droplets that do not settle out with time. Each of these droplets is surrounded by a thin film and held in suspension.
5. Salts dissolved in both free water and in emulsified water.
The functions of a modern GOSP could be summarized as follows:
1. Separate the hydrocarbon gases from crude oil.
2. Remove water from crude oil.
3. Reduce the salt content to the acceptable level [basic sediments and water]
It should be pointed out that some GOSPs do have gas compression and refrigeration facilities to treat the gas before sending it to gas processing plants. In general, a GOSP can function according to one of the following process operation:
1. Three-phase, gas–oil–water separation .
2. Two-phase, gas–oil separation
3. Two-phase, oil–water separation
6. Electrostatic coalescence
To conclude, the ultimate result in operating a modern three-phase separation plant is to change ‘‘wet’’ crude input into the desired outputs.
Controllers and Internal Components of Gas–Oil Separators
Gas–oil separators are generally equipped with the following control devices and internal components.
Liquid Level Controller
The liquid level controller (LLC) is used to maintain the liquid level inside the separator at a fixed height. In simple terms, it consists of a float that exists at the liquid–gas interface and sends a signal to an automatic diaphragm motor valve on the oil outlet. The signal causes the valve to open or close, thus allowing more or less liquid out of the separator to maintain its level inside the separator.
Pressure Control Valve
The pressure control valve (PCV) is an automatic backpressure valve that exists on the gas stream outlet. The valve is set at a prescribed pressure. It will automatically open or close, allowing more or less gas to flow out of the separator to maintain a fixed pressure inside the separator.
Pressure Relief Valve
The pressure relief valve (PRV) is a safety device that will automatically open to vent the separator if the pressure inside the separator exceeded the design safe limit.
The function of the mist extractor is to remove the very fine liquid droplets from the gas before it exits the separator. Several types of mist extractors are available:
1. Wire-Mesh Mist Extractor: These are made of finely woven stainless-steel wire wrapped into a tightly packed cylinder of about 6 in. thickness. The liquid droplets that did not separate in the gravity settling section of the separator coalesce on the surface of the matted wire, allowing liquid-free gas to exit the separator. As the droplets size grows, they fall down into the liquid phase. Provided that the gas velocity is reasonably low, wire-mesh extractors are capable of removing about 99% of the 10-mm and larger liquid droplets. It should be noted that this
type of mist extractor is prone to plugging. Plugging could be due to the deposition of paraffin or the entrainment of large liquid droplets in the gas passing through the mist extractor (this will occur if the separator was not properly designed). In such cases, the vane-type mist extractor, described next, should be used.
2. Vane Mist Extractor: This type of extractor consists of a series of closely spaced parallel, corrugated plates. As the gas and entrained liquid droplets flowing between the plates change flow direction, due to corrugations, the liquid droplets impinge on the surface of the plates, where they coalesce and fall down into the liquid collection section.
3. Centrifugal Mist Extractor: This type of extractor uses centrifugal force to separate the liquid droplets from the gas.
Although it is more efficient and less susceptible to plugging than other extractors, it is not commonly used because of its performance sensitivity to small changes in flow rate.
Once degassed and dehydrated–desalted, crude oil is pumped to gathering facilities to be stored in storage tanks. However, if there are any dissolved gases that belong to the light or the intermediate hydrocarbon groups it will be necessary to remove these gases
along with hydrogen sulfide (if present in the crude) before oil can be stored. This process is described as a ‘‘dual process’’ of both stabilizing and sweetening a crude oil.
In stabilization, adjusting the pentanes and lighter fractions retained in the stock tank liquid can change the crude oil gravity. The economic value of the crude oil is accordingly influenced by stabilization. First, liquids can be stored and transported to the market more profitably than gas. Second, it is advantageous to minimize gas losses from light crude oil when stored.
This chapter deals with methods for stabilizing the crude oil to maximize the volume of production as well as its API gravity, against two important constraints imposed by its vapor pressure and the allowable hydrogen sulfide content.
To illustrate the impact of stabilization and sweetening on the quality of crude oil, the properties of oil before and after treatment are compared as follows:
(a) Before treatment
Water content: up to 3% of crude in the form of emulsions and from 3% to 30% of crude as free water
Salt content: 50,000–250,000 mg/L formation water Gas: dissolved gases in varying amounts depending on the
gas–oil ratio (GOR)
Hydrogen Sulfide: up to 1000 ppm by weight
(b) After treatment (dual-purpose operation): Sour wet crude must be treated to make it safe and environmentally acceptable for storage, processing, and export. Therefore, removing water and salt, is mandatory to avoid corrosion; separation of gases and H2S will make crude oil safe and environmentally acceptable to handle.
Water content (B.S.&W.): 0.3% by volume, maximum
Salt content: 10–20 lbs salt (NaCl) per 1000 barrels oil (PTB)
Vapor pressure: 5–20 psia RVP (Reid vapor pressure)
H2S: 10–100 ppmw
Crude oil is considered ‘‘sweet’’ if the dangerous acidic gases are removed from it. On the other hand, it is classified as ‘‘sour’’ if it contains as much as 0.05 ft3 of dissolved H2S in 100 gal of oil. Hydrogen sulfide gas
is a poison hazard because 0.1% in air is toxically fatal in 30 min.
Additional processing is mandatory—via this dual operation—in order to release any residual associated gases along with H2S present in the crude. Prior to stabilization, crude oil is usually directed to a spheroid for storage in order to reduce its pressure to very near atmospheric.
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the traditional process for separating the crude oil–gas mixture to recover oil consists of a series of flash vessels
[gas–oil separation plant (GOSP)] operating over a pressure range from roughly wellhead pressure to nearly atmospheric pressure. The crude oil discharged from the last stage in a GOSP or the desalter has a vapor pressure equal to the total pressure in the last stage. Usually, operation of this system could lead to a crude product with a RVP in the range of 4 to 12 psia. Most of the partial pressure of a crude comes from the low-boiling compounds, which might be present only in small quantities—in particular hydrogen sulfide and low-molecular-weight hydrocarbons such as methane and ethane.
Now, stabilization is directed to remove these low-boiling compounds without losing the more valuable components. This is particularly true for hydrocarbons lost due to vent losses during storage.
In addition, high vapor pressure exerted by low-boiling-point hydrocarbons imposes a safety hazard. Gases evolved from an unstable crude are heavier than air and difficult to disperse with a greater risk of explosion.
The stabilization mechanism is based on removing the more volatile components by (a) flashing using stage separation and (b) stripping operations.
As stated earlier, the two major specifications set for stabilized oil are as follows:
The Reid vapor pressure (RVP)
Hydrogen sulfide content
Based on these specifications, different cases are encountered:
Case 1: Sweet oil (no hydrogen sulfide); no stabilization is needed. For this case and assuming that there is a gasoline
plant existing in the facilities (i.e., a plant designed to recover pentane plus), stabilization could be eliminated, allowing the stock tank vapors to be collected [via the vapor recovery unit (VRU)] and sent directly to the gasoline plant,
Case 2: Sour crude; stabilization is a must. For this case, it is assumed that the field facilities do not include a gasoline plant.
It can be concluded from the above that the hydrogen sulfide content in the well stream can have a bearing effect on the method of stabilization.
Therefore, the recovery of liquid hydrocarbon can be reduced when the stripping requirement to meet the H2S specifications is more stringent than that to meet the RVP specified. Accordingly, for a given production facility, product specifications must be individually determined for maximum economic return on any investment.
Stabilization by Stripping
The stripping operation employs a stripping agent, which could be either energy or mass, to drive the undesirable components (low-boiling-point hydrocarbons and hydrogen sulfide gas) out of the bulk of crude oil. This
approach is economically justified when handling large quantities of fluid and in the absence of a VRU. It is also recommended for dual-purpose operations for stabilizing sour crude oil, where stripping gas is used for stabilization. Stabilizer-column installations are used for the stripping operations.
Crude Oil Sweetening
Apart from stabilization problems of ‘‘sweet’’ crude oil, ‘‘sour’’ crude oils containing hydrogen sulfide, mercaptans, and other sulfur compounds present unusual processing problems in oil field production facilities. The presence of hydrogen sulfide and other sulfur compounds in the well stream impose many constraints. Most important are the following: Personnel safety and corrosion considerations require that H2S concentration be lowered to a safe level.
Brass and copper materials are particularly reactive with sulfur compounds; their use should be prohibited.
Sulfide stress cracking problems occur in steel structures.
Mercaptans compounds have an objectionable odor.
Along with stabilization, crude oil sweetening brings in what is called a ‘‘dual operation,’’ which permits easier and safe downstream handling and improves and upgrades the crude marketability.
Three general schemes are used to sweeten crude oil at the production facilities:
1. Stage vaporization with stripping gas. This process—as its name implies—utilizes stage separation along with a stripping agent.
Hydrogen sulfide is normally the major sour component having a vapor pressure greater than propane but less than ethane. Normal stage separation will, therefore, liberate ethane and propane from the stock tank liquid along with hydrogen sulfide.
Stripping efficiency of the system can be improved by mixing a lean (sweet) stripping gas along with the separator liquid between each separation stage.
The effectiveness of this process depends on the pressure available at the first-stage separator (as a driving force), well stream composition, and the final specifications set for the sweet oil.
2. Trayed stabilization with stripping gas. In this process, a tray stabilizer (nonreflux) with sweet gas as a stripping agent is used Oil leaving a primary separator is fed to the top tray of the column countercurrent to the stripping sweet gas. The tower bottom is flashed in a low-pressure stripper. Sweetened crude is sent to stock tanks, whereas vapors collected from the top of the gas separator and the tank are normally incinerated. These vapors cannot be vented to the atmosphere because of safety considerations. Hydrogen sulfide is hazardous and slightly heavier
than air; it can collect in sumps or terrain depressions.
This process is more efficient than the previous one. However, tray efficiencies cause a serious limitation on the
column height. For an efficiency of only 8%, 1 theoretical plate would require 12 actual trays. Because trays are spaced about 2 ft apart, columns are limited to 24–28 ft high, or a maximum of two theoretical trays.
3. Reboiled trayed stabilization. The reboiled trayed stabilizer is the most effective means to sweeten sour crude oils. A typical Its operation is similar to a stabilizer with stripping gas, except that a reboiler generates the stripping vapors flowing up the column rather than using a stripping gas. These vapors are more effective because they possess energy momentum due to elevated temperature.
Because hydrogen sulfide has a vapor pressure higher than propane, it is relatively easy to drive hydrogen sulfide from the oil. Conversely, the trayed stabilizer provides enough vapor/liquid contact that little pentanes plus are lost to the overhead.
Paraffin control products prevent crude oil precipitation of paraffin wax deposits in production risers, subsea tie-backs, or any other production tubular or transportation pipeline.
Paraffin – Asphaltenes and Inhibitors
Some formulation products are wax crystal modifiers that prevent paraffin formation by interfering with the bonding of aliphatic wax molecules. Composed of branched chain polymers, these modifiers bond to the wax crystal lattice at an active growing site but prevent further growth and interfere with deposition by disrupting the lattice structure.
Although the paraffins remain unstable in solution, they are prevented from growing crystals of adequate size to block production lines; hence production is not impeded even for temperatures below the wax appearance temperature (WAT).
Wax crystal modifiers are applied continuously in the production stream for uninterrupted paraffin control. In pumping wells with low to moderate fluid levels, frequent batch treatments can approximate a continuous injection treatment. Similarly, a continuous supply of chemical can be provided by feedback from a formation squeeze treatment. Paraffin Deposition…
Crude oil is a complex substance formed under high pressure and temperature from vegetable and/or animal organic materials. A broad spectrum of organic chemical components exist in light, paraffinic and heavy oils. These include wax up to C60, esters, organic acids, asphaltenes and napthalenes. Depending on the makeup of these components, the crude oil will have its own characteristics, including specific gravity, wax content, pour point, color, etc.
Crude oil can cause a series of problems:
• Wax deposition
• Viscous gels at low temperatures (from heavy oils)
• Deposition of asphaltenes
Paraffin consists of straight and branched chain hydrocarbons of varying lengths; they are part of the chemical family called alkanes. Paraffin wax molecules contain between 20 to 80 or more carbon atoms in their chain and have a definite melting point. Paraffin waxes often make up 60-90% of a wax deposit. Soft deposits are composed of molecules containing from CI, to C,5 carbon atoms, their melting points are below 150·F. The high molecular weight waxes are referred as microcrystalline waxes and are similar
in chemical structure to the normal paraffin waxes but have a much higher melting point. (150 to 212·F).
Paraffins are aliphatic hydrocarbon waxes that are present in most crude oils. They precipitate from a crude oil at the point where the temperature falls below the WAT.
These deposits reduce the internal diameter of tubulars and pipelines, restrict or block valves, and impede other production equipment to reduce capacity and, in the worst case, stop production. Factors Influencing Paraffin Deposition:
• Paraffin wax is primarily a solid – liquid phase equilibrium phenomenon; the lowering of temperature is the significant driving force for precipitation. Crude oil is made up of many different properties and freeze points. As the temperature falls below the freeze point of a hydrocarbon, it falls out of solution. The harder waxes deposit first, followed by the softer waxes as the temperature drops.
• Hydrocarbon density – paraffin waxes are increasingly soluble in lighter gravity, low molecular weight hydrocarbons.
• Solution gas – as oil losses light ends it becomes more dense, and paraffin solubility decreases. The light end losses usually occur at pressure drops, which cause the release of the volatile hydrocarbons, which are good solvents for paraffin wax.
• Rough surfaces provide sharp edges, which promote the deposition and agglomeration of wax. Suspended solids also provide surfaces for wax to adhere to and start accumulating.
• Water cut – as the water cut increases in a system it affects the temperature, water carries and retains more heat than oil does. The water reduces the tendency for wax to deposit by increased velocity and water wetting surfaces.
Asphaltenes are probably the least understood deposits occurring in the oilfield. They are a complex organic material that are thought to be arranged in stacked, multi-ring structures. They contain nitrogen, oxygen’ and sulfur atoms within the repeating unit.
Asphaltenes have a wide variety of potential structures and vary from reservoir to reservoir. Asphaltenes are not truly soluble in most crude oils. They exist as 35 to 40 micron sized platelets
and are maintained in suspension by materials called maltenes and resins. These smaller similar
suspending molecules are soluble and act in what has been described as a micelle-type
arrangement to keep the asphaltic products in suspension. When stabilizing influences are
removed the asphaltic particles coalesce into larger groups, called flocs, which separate from
the oil. Asphaltene precipitation will occur with the addition of low molecular weight alkanes,
like pentane, hexane, and heptane, and are soluble in aromatic hydrocarbons, like xylene and toluene.
Factors Influencing Asphaltene Deposition
• Rich gas flooding causes destabilization by lowering the carbon to hydrogen ratio. Stripping gas from the oil has been shown to improve the solubility of the asphaltenes.
• The lowering of pH interrupts solution equilibrium and can cause a destabilization of the asphaltene. This may be caused by CO² mineral acid or naturally occurring organic acid. This can cause asphaltene to deposit in the well bore and pumps.
• Mixing of crude and/or condensate streams can cause a shift in pH or change the ratio of light hydrocarbons. Another example is the mixing of a paraffinic oil or condensate with an asphaltenic one.
• Incompatible organic chemicals, like isopropyl alcohol, methyl alcohol, acetone, and even some glycol, alcohol or surfactant based mutual solvents that do not have an aromatic component can selectively wet or attract maltenes and resins and cause the precipitation of asphaltenes.
•The effect of pressure drop and shear on asphaltene behavior may be to shift the tendency to
precipitate asphaltene, similar to a change in equilibrium. Turbulence also has impact on increasing asphaltene precipitation. Asphaltene deposits are frequently found downstream of chokes, liner
slots, valves, and vessels.
•Temperature drop – this may have more to do with indirect destabilization of the solubility of
maltenes and resins or may cause paraffin precipitation, which traps some asphaltenes as it solidifies.
Temperature can also be affected by pressure drop.
Paraffin / Asphaltene Comparison Paraffin
• Straight and branched chains
• Definite melting point
• Cloud point indicates crystal initiation
• Soluble in crude oil
• Pour Point – no flow of oil due to wax
• Carbon number’s C12 to C66+ Asphaltene
• Friable solids
• No definite melting point
• Swell and pop when heated
• Aromatic rings
• Decompose to coke material
• Stabilized by resins and maltenes
• Not soluble in crude oil
• Contain nitrogen, oxygen and sulphur
Impact of Paraffin / Asphaltene Deposition
The impact of paraffin/asphaltene deposition is very severe and it can increase operating costs as well as
reduce well and system productivity. Examples of the impact are as follows:
• Plugging of perforations and near well bore damage resulting in a decline in reservoir productivity.
• Increased lifting costs from down hole pump maintenance, etc.
• Pressure increases in flow lines and wells resulting in higher operating costs.
Deposition and plugging of production tanks resulting in a difficulty of meeting BS &W requirements.
• Pipeline blockage and increased transmission costs.
Wax is present in most crude oils, usually in quantities of less than 5%, but even this much can still cause problems. Wax can be detected by normal analytical methods (IP) and usually represents that fraction of the oil with a carbon number higher than 18. Wax is formed when the oil is cooled as a result of being produced from the well.
• Subsea pipelines
• Heat exchange
• Joule effect
• Gas lift (change in solubility)
The wax crystals are formed at a specific temperature (wax appearance point), and then they become so big that they deposit on the surface and block the pipes or process equipment.
Deposit Identification Paraffin
• If it melts above l22’F
• If it floats on water
• If it dissolves in hot xylene Asphaltene
• If it doesn’t melt but dissolves in
• hot xylene.
• Solids (scale, iron sulfide, sand,
• mud, etc.)
• If it doesn’t melt
• If it doesn’t dissolve in hot xylene
• If it sinks in water
this section is for petroleum books such as petroleum production – petroleum fields – petroleum engineers – sludge treatment – H2S – Oil spills and many other books related to oil and natural gas industry.
Nitrogen – less than 1% (basic compounds with amine groups)
Oxygen – less than 1% (found in organic compounds such as carbon dioxide, phenols, ketones, carboxylic acids)
Metals – less than 1% (nickel, iron, vanadium, copper, arsenic)
Salts – less than 1% (sodium chloride, magnesium chloride, calcium chloride)
Crude oil is the term for “unprocessed” oil, the stuff that comes out of the ground. It is also known as petroleum. Crude oil is a fossil fuel, meaning that it was made naturally from decaying plants and animals living in ancient seas millions of years ago — most places you can find crude oil were once sea beds. Crude oils vary in color, from clear to tar-black, and in viscosity, from water to almost solid.
Crude oils are such a useful starting point for so many different substances because they contain hydrocarbons. Hydrocarbons are molecules that contain hydrogen and carbon and come in various lengths and structures, from straight chains to branching chains to rings.
There are two things that make hydrocarbons exciting to chemists:
Hydrocarbons contain a lot of energy. Many of the things derived from crude oil like gasoline, diesel fuel, paraffin wax and so on take advantage of this energy.
Hydrocarbons can take on many different forms. The smallest hydrocarbon is methane (CH4), which is a gas that is a lighter than air. Longer chains with 5 or more carbons are liquids. Very long chains are solids like wax or tar. By chemically cross-linking hydrocarbon chains you can get everything from synthetic rubber to nylon to the plastic in Tupperware. Hydrocarbon chains are very versatile!
The major classes of hydrocarbons in crude oils include:
general formula: CnH2n+2 (n is a whole number, usually from 1 to 20)
m straight- or branched-chain molecules
can be gasses or liquids at room temperature depending upon the molecule
Petroleum, meaning literally “rock oil,” is the term used to describe a myriad of hydrocarbon-rich fluids that have accumulated in subterranean reservoirs. (also called crude oil) varies dramatically in color, odor, and flow properties that reflect the diversity of its origin.
Petroleum products are any petroleum-based products that can be obtained by refining and comprise refinery gas, ethane, liquefied petroleum gas (LPG), naphtha, gasoline, aviation fuel, marine fuel, kerosene, diesel fuel, distillate fuel oil, residual fuel oil, gas oil, lubricants, white oil, grease, wax, asphalt, as well as coke.
Crude oils are complex mixtures of these hydrocarbons. Oils containing primarily paraffin hydrocarbons are called paraffin-based or paraffinic. Traditional examples are Pennsylvania grade crude oils. Naphthenic-based crudes contain a large percentage of cycloparaffins in the heavy components. Examples of this type of crude come from the United States midcontinent region. Highly aromatic crudes are less common but are still found around the world.
Crude oils tend to be a mixture of paraffins, naphthenes, aromatics, with paraffins and naphthenes the predominant species. Resins and asphaltenes may also be present in crude oil. Resins and asphaltenes are the colored and black components found in oil and are made up of relatively high-molecular weight, polar, polycyclic, aromatic ring compounds. Pure asphaltenes are nonvolatile, dry, solid, black powders, while resins are heavy liquids or sticky solids with the same volatility as similarly sized hydrocarbons. High-molecular-weight resins tend to be red in color, while lighter resins are less colored. Asphaltenes do not dissolve in crude oil but exist as a colloidal suspension. They are soluble in aromatic compounds such as xylene, but will precipitate in the presence of light paraffinic compounds such as pentane. Resins, on the other hand, are readily soluble in oil.
Petroleum products are highly complex chemicals, and considerable effort is required to characterize their chemical and physical properties with a high degree of precision and accuracy. Indeed, the analysis of petroleum products is necessary to determine the properties that can assist in resolving a process problem as well as the properties that indicate the function and performance of the product in service.
Crude petroleum and the products obtained there from contain a variety of compounds, usually but not always hydrocarbons. As the number of carbon atoms in, for example, the paraffin series increases, the complexity of petroleum mixtures also rapidly increases. Consequently, detailed analysis of the individual constituents of the higher boiling fractions becomes increasingly difficult, if not impossible.
Additionally, classes (or types) of hydrocarbons were, and still are, determined based on the capability to isolate them by separation techniques. The four fractional types into which petroleum is subdivided are paraffins, olefins, naphthenes, and aromatics (PONA). Paraffinic hydrocarbons include both normal and branched alkanes, whereas olefins refer to normal and branched alkenes that contain one or more double or triple carbon-carbon bonds. Naphthene (not to be confused with naphthalene) is a term specific to the petroleum industry that refers to the saturated cyclic hydrocarbons (cycloalkanes). Finally, the term aromatics includes all hydrocarbons containing one or more rings of the benzenoid structure.
Although not directly derived from composition, the terms light and heavy or sweet and sour provide convenient terms for use in descriptions. For example, light petroleum (often referred to as conventional petroleum) is usually rich in low-boiling constituents and waxy molecules whereas heavy petroleum contains greater proportions of higher-boiling, more aromatic, and heteroatom-containing (N-, O-, S-, and metal containing) constituents. Heavy oil is more viscous than conventional petroleum and
requires enhanced methods for recovery. Bitumen is near solid or solid and cannot be recovered by enhanced oil recovery methods.
onventional (light) petroleum is composed of hydrocarbons together with smaller amounts of organic compounds of nitrogen, oxygen, and sulfur and still smaller amounts of compounds containing metallic constituents, particularly vanadium, nickel, iron, and copper. The processes by which petroleum was formed dictate that petroleum composition will vary and be site specific, thus leading to a wide variety of compositional differences.
The term site specific is intended to convey that petroleum composition will be dependent on regional and local variations in the proportion of the various precursors that went into the formation of the protopetroleum as well as variations in temperature and pressure to which the precursors were subjected.
Thus the purely hydrocarbon content may be higher than 90% by weight for paraffinic petroleum and 50% by weight for heavy crude oil and much lower for tar sand bitumen. The nonhydrocarbon constituents are usually concentrated in the higher-boiling portions of the crude oil. The carbon and hydrogen content is approximately constant from crude oil to crude oil even though the amounts of the various hydrocarbon types and of the individual isomers may vary widely. Thus the carbon content of various types of petroleum is usually between 83% and 87% by weight and the hydrogen content is in the range of 11–14% by weight.
General aspects of petroleum quality (as a refinery feedstock) are assessed by measurement of physical properties such as relative density (specific gravity – which affects on Oil Price), refractive index, or viscosity, or by empirical tests such as pour point or oxidation stability that are intended to relate to behavior in service. In some cases the evaluation may include tests in mechanical rigs and engines either in the laboratory or under actual operating conditions.
Measurements of bulk properties are generally easy to perform and, therefore, quick and economical. Several properties may correlate well with certain compositional characteristics and are widely used as a quick and inexpensive means to determine those characteristics. The most important properties of a whole crude oil are its boiling-point distribution, its density (or API gravity), and its viscosity. The boiling-point distribution, boiling profile, or distillation assay gives the yield of the various distillation cuts, and selected properties of the fractions are usually determined.
It is a prime property in its own right that indicates how much gasoline and other transportation fuels can be made from petroleum without conversion.
Density and viscosity are measured for secondary reasons.
The former helps to estimate the paraffinic character of the oil, and the latter permits the assessment of its undesirable residual material that causes resistance to
flow. Boiling-point distribution, density, and viscosity are easily measured and give a quick first evaluation of petroleum oil. Sulfur content, another
crucial and primary property of a crude oil, is also readily determined. Certain composite characterization values, calculated from density and
mid-boiling point, correlate better with molecular composition than density alone.
The acceptance of heavy oil and bitumen as refinery feedstocks has meant that the analytical techniques used for the lighter feedstocks have
had to evolve to produce meaningful data that can be employed to assist in defining refinery scenarios for processing the feedstocks. In addition,
selection of the most appropriate analytical procedures will aid in the predictability of feedstock behavior during refining. This same rationale can also be applied to feedstock behavior during recovery operations. Indeed,bitumen, a source of synthetic crude oil, is so different from petroleum that many of the test methods designed for petroleum may need modification.
References: 1. Petroleum & Gas Field Processing, H K. Abdel-Alal and Mohamed Aggour, King Fahd University of Petroleum & Minerals 2. Petroleum Engineering Handbook, L.W.Lake, Vol.1 “General Engineering”