Lubricating Oils Testing Methods


lubricating oilLubricating oil is used to reduce friction and wear between bearing metallic surfaces that are moving with respect to each other by separating the metallic surfaces with a film of the oil. Lubricating oil is distinguished from other fractions of crude oil by a high (>400°C/>750°F) boiling point

In the early days of petroleum refining, kerosene was the major product, followed by paraffin wax wanted for the manufacture of candles. Lubricating oils were at first by-products of paraffin wax manufacture.The preferred lubricants in the 1860s were lard oil, sperm oil, and tallow, but as the trend to heavier industry increased, the demand for mineral lubricating oils increased, and after the 1890s petroleum displaced animal and vegetable oils as the source of lubricants for most purposes.


The number of tests applied for product character and quality varies with the complexity of the product and the nature of the application. The more important tests, such as viscosity, flash point, and color are usually performed on every batch. Other tests may be on a statistical (or as-needed) basis dependent on data that can be presented in the graphical form of a fingerprint that is specific for the blend of components and additives in a particular formulation. Comparison of the fingerprint with a known standard can be used as a check on the composition.

  1. Acidity and Alkalinity

Unused and used petroleum products may contain acidic constituents that are present as additives or as degradation products formed during service, such as oxidation products (ASTM D-5770). The relative amount of these materials can be determined by titrating with bases.The acid number is used as a guide in the quality control of lubricating oil formulations. It is also sometimes used as a measure of lubricant degradation in service. Any condemning limits must be empirically established.

Thus the acid number is a measure of this amount of acidic substance in the oil, always under the conditions of the test. Because a variety of oxidation products contribute to the acid number and the organic acids vary widely in corrosion properties, the test cannot be used to predict corrosiveness of an oil under service conditions.

The acid number is the quantity of base, expressed in milligrams of potassium hydroxide per gram of sample, that is required to titrate a sample in this solvent to a green/green-brown end point with pnaphtholbenzein indicator solution (ASTM D-974, IP 139). However, many higher-molecular-weight oil products (dark-colored oils) that cannot be analyzed for acidity because of obscurity of the color-indicator end point can be analyzed by an alternate test method (ASTM D-664). The quality of the mineral oil products renders them suitable for determination of the acid number.

In a manner akin to the acid number, the base number (often referred to as the neutralization number) is a measure of the basic constituents in the oil under the conditions of the test.The base number is used as a guide in the quality control of oil formulation and is also used as a measure of oil degradation in service.

The neutralization number, expressed as the base number, is a measure of this amount of basic substance in the oil, always under the conditions of the test.The neutralization number is used as a guide in the quality control of lubricating oil formulations. It is also sometimes used as a measure of lubricant degradation in service; however, any condemning limits must be empirically established.

Samples of oil drawn from the crankcase can be tested to assess the reserve of alkalinity remaining by determining the total base number of the oil (ASTM D-664, ASTM D-2896, ASTM D-4739, IP 177, IP 276). Essentially, these are titration methods in which, because of the nature of the used oil, an electrometric instead of a color end point is used. The reserve alkalinity neutralizes the acids formed during combustion. This protects the engine components from corrosion. However, the different base number methods may give different results for the same sample.

Lubricating oil often contains additives that react with alkali to form metal soaps, and the saponification number expresses the amount of base that will react with 1 g of the sample when heated in a specific manner. In the test method (ASTM D-94, IP 136), a known weight of the sample is dissolved in methyl ethyl ketone or a mixture of suitable solvents and the mixture is heated with a known amount of standard alcoholic potassium hydroxide for between 30 and 90 min at 80°C (176°F). The excess alkali is titrated with standard hydrochloric acid, and the saponification number is calculated. The results obtained indicate the effect of extraneous materials in addition to the saponifiable material present.

  1. Ash

The ash formed by the combustion of lubricating oil (ASTM D-482,ASTM D-2415, IP 4) is, as defined for other products, the inorganic residue, free from carbonaceous matter, remaining after ignition in air of the residual

fuel oil at fairly high temperatures. The ash content is not directly equated to mineral content but can be converted to mineral matter content by the use of appropriate formulae.

  1. Asphaltene Content (Insoluble Constituents)

The asphaltene fraction (ASTM D-2006, ASTM D-2007, ASTM D-3279, ASTM D-4124, ASTM D-6560, IP 143) is the highest-molecular-weight most complex fraction in petroleum. Insofar as the asphaltene content gives

an indication of the amount of coke that can be expected during exposure to thermal conditions .there is little need for the application of the test to lubricating mineral oil. Use of the oil under stressful conditions where heat is generated may introduce the need to determine the amount of insoluble constituents precipitated by the addition of a low-boiling hydrocarbon liquid to mineral oil.

Pentane-insoluble constituents can be determined by membrane filtration (ASTM D-4055). In this method, a sample of oil is mixed with pentane in a volumetric flask, and the oil solution is filtered through a 0.8-mm membrane filter. The flask, funnel, and filter are washed with pentane to completely transfer any particulates onto the filter, after which the filter (with particulates) is dried and weighed to give the pentane-insoluble constituents as a percentage by weight of the sample.

The precipitation number is often equated to the asphaltene content, but there are several issues that remain obvious in its rejection for this purpose.

For example, the method to determine the precipitation number (ASTM D-91) advocates the use of naphtha for use with black oil or lubricating oil and the amount of insoluble material (as a % v/v of the sample) is the precipitating number. In the test, 10 ml of sample is mixed with 90 ml of ASTM precipitation naphtha (which may or may nor have a constant chemical composition) in a graduated centrifuge cone and centrifuged for 10 min at 600–700 rpm.The volume of material on the bottom of the centrifuge cone is noted until repeat centrifugation gives a value within 0.1 ml (the precipitation number). Obviously, this can be substantially different from the asphaltene content.

On the other hand, if the lubricating oil has been subjected to excessive heat, it might be wise to consider application of the test method for determining the toluene-insoluble constituents of tar and pitch (ASTM D-4072, ASTM D-4312). In these methods, a sample is digested at 95°C (203°F) for 25 min and then extracted with hot toluene in an alundum thimble. The extraction time is 18 h (ASTM D-4072) or 3 h (ASTM D-4312). The insoluble matter is dried and weighed. Combustion will then show whether the material is truly carbonaceous or it is inorganic ash from the metallic constituents (ASTM D-482, ASTM D-2415, ASTM D-4628, ASTM D-4927, ASTM D-5185, ASTM D-6443, IP 4).

Another method (ASTM D-893) covers the determination of pentaneand toluene-insoluble constituents in used lubricating oils. Pentaneinsoluble constituents include oil-insoluble materials, some oil-insoluble resinous matter originating from oil or additive degradation, or both. Tolueneinsoluble constituents can come from external contamination, fuel carbon, highly carbonized materials from degradation of fuel, oil, and additives, or engine wear and corrosion materials. A significant change in pentane- or toluene-insoluble constituents and insoluble resins indicates a change in oil that could lead to lubrication problems. The insoluble constituents measured can also assist in evaluating the performance characteristics of a used oil or in determining the cause of equipment failure.

Two test methods are used: Procedure A covers the determination of insoluble constituents without the use of coagulant in the pentane and provides an indication of the materials that can be readily separated from the oil-solvent mixture by centrifugation. Procedure B covers the determination of insoluble constituents in lubricating oil that contains detergents and uses a coagulant. In addition to the materials separated by using procedure

A, this coagulation procedure separates some finely divided materials that may be suspended in the oil. The results obtained by procedures A and B should not be compared because they usually give different values. The same procedure should be applied when comparing results obtained periodically on an oil in use, or when comparing results determined in different laboratories.

In procedure A, a sample is mixed with pentane and centrifuged, after which the oil solution is decanted and the precipitate is washed twice with pentane, dried, and weighed. For toluene-insoluble constituents, a separate sample of the oil is mixed with pentane and centrifuged. The precipitate is washed twice with pentane, once with toluene-alcohol solution, and once with toluene. The insoluble material is then dried and weighed. In procedure B, procedure A is followed except that instead of pentane, a pentanecoagulant solution is used.

  1. Carbonizable Substances (Acid Test)

The test for carbonizable substances with sulfuric acid is not usually applied to lubricating oil requirements. However, the need may arise and being aware of the availability of such a test is warranted. In this test method (ASTM D-565), a sample of the oil is treated with concentrated sulfuric acid under prescribed conditions and the resulting color is compared with a reference standard to determine whether it passes or fails the test. When the oil layer shows no change in color and when the acid layer is not darker than the reference standard colorimetric solution, the oil is reported as passing the test. A bluish haze or a slight pink or yellow color in the oil layer should not be interpreted as a change in color.The more fully refined the oil, the lighter the color of the acid layer.

However, with the introduction of ultraviolet absorption procedures (ASTM D-2008, ASTM D-2269), the test finds less use but still provides a useful method to determine possible contamination of lubricating oil with impurities transparent to both visible and ultraviolet light and hence not detectable by color or by ultraviolet absorption measurements (ASTM D-2008).

The test for carbonizable substances (ASTM D-565) should not be confused with the test methods for determining carbon residue (ASTM D-189, ASTM D-524, ASTM D4530, IP 13, IP 14, IP 398) (q.v.).

  1. Carbon Residue

Lubricating oil is not usually considered to be used under the extreme conditions under which coke is formed from, for example, fuel oil. Nevertheless, the tests that are applied to determine the carbon-forming propensity of fuel oil (and other petroleum products) are also available for application to lubricating oil should the occasion arise.

Thus the tests for the Conradson carbon residue (ASTM D-189, IP 13), the Ramsbottom carbon residue (ASTM D-524, IP 14), and the microcarbon carbon residue (ASTM D4530, IP 398) are often included in inspection data for fuel oil.

In the Conradson carbon residue test (ASTM D-189, IP 13), a weighed quantity of sample is placed in a crucible and subjected to destructive distillation for a fixed period of severe heating. At the end of the specified heating period, the test crucible containing the carbonaceous residue is cooled in a desiccator and weighed and the residue is reported as a percentage (% w/w) of the original sample (Conradson carbon residue). In the Ramsbottom carbon residue test (ASTM D-524, IP 14), the sample is weighed into a glass bulb that has a capillary opening and is placed into a furnace (at 550°C/1022°F).The volatile matter is distilled from the bulb, and the nonvolatile matter that remains in the bulb cracks to form thermal coke.

After a specified heating period, the bulb is removed from the bath, cooled in a desiccator, and weighed to report the residue (Ramsbottom carbon residue) as a percentage (% w/w) of the original sample. In the microcarbon residue test (ASTM D-4530, IP 398), a weighed quantity of the sample placed in a glass vial is heated to 500°C (932°F) under an inert (nitrogen) atmosphere in a controlled manner for a specific time and the carbonaceous residue [carbon residue (micro)] is reported as a percentage (% w/w) of the original sample.

The data produced by the microcarbon test (ASTM D-4530, IP 398) are equivalent to those by the Conradson carbon method (ASTM D-189, IP 13). However, the microcarbon test method offers better control of test conditions and requires a smaller sample. Up to 12 samples can be run simultaneously. This test method is applicable to petroleum and to petroleum products that partially decompose on distillation at atmospheric pressure and is applicable to a variety of samples that generate a range of yields (0.01% w/w to 30% w/w) of thermal coke.

Read Also Oil-Base and Synthetic-Base Muds

  1. Cloud Point

The cloud point is the temperature at which a cloud of wax crystal first appears in a liquid when it is cooled under conditions prescribed in the test method. This test method covers only petroleum oils that are transparent in layers 38 mm (1.5 in.) in thickness and have a cloud point below 49°C (120°F). The cloud point is an indicator of the lowest temperature of the utility of an oil for certain applications and it is usually higher than the pour point (ASTM D-97, ASTM D-5853, ASTM D-5949, ASTM D-5950,ASTM D-5985, IP 15).

The cloud point (ASTM D-2500, IP 219) of lubricating oil is the temperature at which paraffinic wax, and other components that readily solidify, begin to crystallize out and separate from the oil under prescribed test conditions. It is of importance to know when narrow clearances might be restricted by accumulation of solid material (for example, oil feed lines or filters).

Neither the cloud point nor the pour point should be confused or interchanged with the freezing point (ASTM D-D 2386, ASTM D-5901, ASTM D-5972, IP 16, IP 434, IP 435). The freezing point presents an estimate of minimum handling temperature and minimum line or storage temperature.

It is not a test for an indication of purity and has limited value for lubricating oil.

  1. Color

lubricating OilDetermination of the color of petroleum products is used mainly for manufacturing control purposes and is an important quality characteristic. In some cases the color may serve as an indication of the degree of refinement of the material. However, color is not always a reliable guide to product quality and should not be used indiscriminately in product specifications (ASTM D-156, ASTM D-1209, ASTM D-1500, ASTM D-1544, ASTM D- 6045, IP 17).

In one test (ASTM D-156) for the determination of color, the height of a column of the oil is decreased by levels corresponding to color numbers until the color of the sample is lighter than that of the standard. The color number immediately above this level is recorded as the Saybolt color of the oil, and a color number of +25 corresponds to water-mineral, whereas the minimum color intensity reading on this scale is expressed by +30, a value normally attained by mineral oils. In another test (IP 17), in which the measurements are performed with an 18-in. cell against color slides on a scale, a color of 1.0 or under is considered water-mineral and medicinal oils will normally be 0.5 or less. Conversion scales for different color tests are available (ASTM D-1500). Although sometimes found in insulating oil specifications, the color characteristic is of no technical significance. Pale oils are, as a general rule, more severely refined than dark oils of the same viscosity, and color (ASTM D- 1500, IP 17) is not a guide to stability. Deterioration of color after submission of the oil to an aging test is sometimes limited, but here again extent of oil deterioration can be much better measured by some other property such as acidity development or change in electrical conductivity (ASTM D- 2624, ASTM D-4308, IP 274). About the only point that can be made in favor of color measurement on new oil is that it can give an immediate guide to a change in supply continuity.

  1. Composition

The importance of composition of lubricating oils lies in the effect it has on their compatibility (ASTM D-2226). This can often be determined by studies of the composition. For example, molecular type analysis separates an oil into different molecular species. One molecular type analysis is the so-called clay-gel analysis. In this method, group separation is achieved by adsorption in a percolation column with selected grades of clay and/or silica gel as the adsorption media (ASTM D-1319, ASTM D-2007, IP 156).

Mass spectrometry can also be used for compositional studies of lubricating oil (ASTM D-3239). This test method covers the determination by high ionizing voltage, low-resolution mass spectrometry of 18 aromatic hydrocarbon types and three aromatic thiophene types in straight-run aromatic petroleum fractions boiling within the range from 205 to 540°C (400–1000°F). Samples must be nonolefinic, must not contain more than 1 mass % of total sulfur, and must not contain more than 5% nonaromatic hydrocarbons. The relative abundances of seven classes of aromatics in petroleum fractions are determined by using a summation of peaks most characteristic of each class. Calculations are carried out by the use of an inverted matrix derived from the published spectra of pure aromatic compounds.

The aromatic fraction needed for this analysis is obtained by using liquid elution chromatography (ASTM D-2549). Aromatic content is a key property of hydrocarbon oils insofar as the aromatic constituents can affect a variety of properties. An existing method using high-resolution nuclear magnetic resonance (ASTM D-5292) is applicable to a wide range of petroleum products that are completely soluble in chloroform and carbon tetrachloride at ambient temperature. The data obtained by this method can be used to evaluate changes in aromatic contents of hydrocarbon oils resulting from process changes. This test method is not applicable to samples containing more than 1% by weight olefinic or phenolic compounds. The hydrogen magnetic resonance spectra are obtained on sample solutions in either chloroform or carbon tetrachloride with a continuous wave or pulse Fourier transform high-resolution nuclear magnetic resonance spectrometer. Carbon magnetic resonance spectra are obtained on the sample solution in deutero-chloroform with a pulse Fourier transform high-resolution nuclear magnetic resonance spectrometer.

The total quantity of sulfur in a gear oil due to the base oil and the additives present can be determined by a bomb method (ASTM D-129, IP 61) in which the sulfur is assessed gravimetrically as barium sulfate.The copper

strip test (ASTM D-130, ASTM D-849, ASTM D-2649, IP 154) is used to simulate the tendency of the oil to attack copper, brass, or bronze. Because active sulfur is desirable for some extreme-pressure applications, a positive copper strip result can indicate that the formulation is satisfactory, but care is necessary in the interpretation of copper strip results because formulations of different chemical compositions may give different results and yet have similar performance in the intended application. Corrosion preventative properties are also measurable (ASTM D-4636).

The constituent elements (barium, calcium, magnesium, tin, silica, zinc, aluminum, sodium, and potassium) of new and used lubricating oils can also be determined (ASTM D-811). Corresponding methods for barium, calcium, and zinc in unused oils are available (IP 110, IP 111, and IP 117,

respectively. For new lubricating oils ASTM D-874/IP 163 can be used to check the concentration of metallic additives present by measuring the ash residue after ignition. This latter method is useful to check the quality of new oils at blending plants or against specifications.

The lead content of new and used gear oils can be determined by the chemical separation method (IP 120). However, there are a number of instrumental techniques that enable the results to be obtained very much more rapidly, among which are polarographic, flame photometric, and Xray fluorescence methods. Chlorine can be determined by a chemical method as silver chloride (ASTM D-808) or by a titration method (ASTM D-1317, IP 118).

Phosphorus can serve as a beneficial adjunct or as a deleterious agent. There are several test methods for the determination of phosphorus. In addition to the three test methods described here, reference should also be made to multielement analysis methods such as inductively coupled plasma atomic emission spectroscopy (ICPAES) (ASTM D-4951, ASTM D-5185) and X-ray fluorescence (XRF) (ASTM D-4927, ASTM D-6443) described above in this guide. Phosphorus can also be determined by a photometric procedure (IP 148) or by a test method (ASTM D-1091) in which the organic material in the sample is destroyed, phosphorus in the  sample is converted to phosphate ion by oxidation with sulfuric acid, nitric acid, and hydrogen peroxide, and the magnesium pyrophosphate is determined gravimetrically.

Another method (ASTM D-4047, IP 149) in which the phosphorus is converted to quinoline phosphomolybdate is also available The extent and nature of the contamination of a used automotive engine oil by oxidation and combustion products can be ascertained by determining the amounts of materials present in the lubricating oil that are insoluble in n-pentane and toluene (ASTM D-893).

In this test, a solution of the used lubricating oil in pentane is centrifuged, the oil solution is decanted, and the precipitate is washed, dried and weighed. Insoluble constituents (precipitate) are expressed as a percentage by weight of the original amount of used oil taken and include the resinous material resulting from the oxidation of the oil in service, together with the benzene-insoluble constituents. The latter are determined on a separate portion of sample that is weighed, mixed with pentane, and centrifuged. The precipitate is washed twice with pentane, once with benzene-alcohol solution, and once with benzene. The insoluble material is then dried and weighed to give the percentage of benzene insoluble constituents that contain wear debris, dirt, carbonaceous matter from the combustion products, and decomposition products of the oil, additives, and fuel.

Where highly detergent/dispersant oils are under test, coagulated pentane-insoluble constituents and coagulated benzene-insoluble constituents may be determined by using methods similar to those just described but employing a coagulant to precipitate the very finely divided materials that may otherwise be kept in suspension by the detergent/ dispersant additives.

Size discrimination of insoluble matter may be made to distinguish between finely dispersed, relatively harmless matter and the larger, potentially harmful particles in an oil (ASTM D-4055). The method uses filtration through membranes of known pore size. Membrane filtration techniques are increasingly being used.

The metallic constituents (barium, boron, calcium, magnesium, tin, silicon, zinc, aluminum, sodium, potassium, etc.) of new and used lubricating oils can be determined by a comprehensive system of chemical analysis (ASTM D-874, IP 163).

Turbine oil systems usually contain some free water as a result of steam leaking through glands and then condensing. Marine systems may also have salt water present because of leakage from coolers. Because of this, rust inhibitors are usually incorporated. The rust-preventing properties of turbine oils are measured by a method (ASTM D-665, IP 135) that uses synthetic seawater or distilled water in the presence of steel.The oil should also be noncorrosive to copper (ASTM D-130, IP 154).

The presence of water in turbine systems tends to lead to the formation of emulsions and sludge containing water, oil, oil oxidation products, rust particles, and other solid contaminants that can seriously impair lubrication.

The lubricating oil, therefore, should have the ability to separate from water readily and to resist emulsification during passage of steam into the oil until a predetermined volume has condensed, and the time required for separation is measured (IP 19). Alternatively, the rate of separation of oil that has been stirred with an equal volume of water is measured (ASTM D-1401).

These test methods are only approximate guides to the water-separating characteristics of modern inhibited turbine oils, and the results should be used in conjunction with experience gained of the particular service conditions encountered.

Although systems should be designed to avoid entertainment of air in the oil, it is not always possible to prevent this (ASTM D-892, IP 146). The formation of a stable foam (ASTM D-892, ASTM D-3519, ASTM D-3601, ASTM D-6082, IP 146) increases the surface area of the oil that is exposed to small bubbles of air, thus assisting oxidation. The foam can also cause loss of oil from the system by overflow. Defoaming agents are usually incorporated in turbine oils to decrease their foaming tendency.

Air release is also an important property if a soft or spongy governor system is to be avoided. A careful choice of type and amount of defoaming agent will provide the correct balance of foam protection and air release properties.

Dilution of an oil by fuel under low-temperature or short-distance stop start operation can occur frequently. Dilution of engine oil by diesel fuel can be estimated from gas chromatography (ASTM D-3524), and gasoline dilution can also be measured by gas chromatography (ASTM D-3525).

Low-temperature service conditions may also result in water vapor from combustion products condensing in the crankcase (ASTM D-95, IP 74).

  1. Density (Specific Gravity)

There are alternative but related means of expressing the weight of a measured volume of a product.

Both density (specific gravity) and API gravity measurements are used as manufacturing control tests and, in conjunction with other tests, are also used for characterizing unknown oils because they correlate approximately with hydrocarbon composition and, therefore, with the nature of the crude source of the oil (ASTM D-l298, IP 160).

For lubricating oil, the purpose of limiting density range is to provide a check on oil composition. In addition, a minimum density may offer some indication of solvent power as well as guarding against excessive paraffin content. In this respect, the inclusion of density in a mineral oil specification may duplicate the aniline point (ASTM D-611, IP 2) requirement.

The API gravity (ASTM D-287, IP 192) is also used for lubricating oil and is based on a hydrometer scale that may be readily converted to a relative density basis API gravity, deg = (141.5/sp gr 60/60°F) – 131.5

API density is also a critical measure reflecting the quality of lubricating oil.

  1. Flash Point and Fire Point

The flash point gives an indication of the presence of volatile components in an oil and is the temperature to which the oil must be heated under specified test conditions to give off sufficient vapor to form a flammable mixture with air.

The fire point is the temperature to which the product must be heated under the prescribed test conditions to cause the vapor-air mixture to burn continuously on ignition.The Cleveland open cup method (ASTM D-92, IP

36) can be used to determine both flash and fire points of lubricating oils, and the Pensky–Martens closed (ASTM D-93, IP 34) and open (IP 35) flash points are also widely used.

The flash and fire points are significant in cases where high-temperature operations are encountered, not only because of the hazard of fire but also as an indication of the volatility of an oil. In the case of used oils, the flash point is used to indicate the extent of contamination with more volatile oils or with fuels such as gasoline (ASTM D-3607). The flash point can also be used to assist in the identification of different types of base oil blend.

For used automotive engine oils that can be contaminated by a variety of materials, the presence of diesel fuel constituents, resulting from low temperature or short-distance stop-start operation, can be approximately estimated from measurements of the flash point of the oil (ASTM D-92, IP 36) that is appreciably lowered by small quantities of fuel. The presence of gasoline constituents can be measured by distillation (ASTM D-322, IP 23) or by infrared spectroscopy. Fire-resistant lubricating oil is used widely in the coal mining industry.

The use of such fluids also is expanding in the metal cutting and forming, lumber, steel, aluminum, and aircraft industries. A test is also available to evaluate the fire-resistant properties of lubricating oil under a variety of conditions (ASTM D-5306). Most tests involve dripping, spraying, or pouring the liquid into a flame or onto a hot surface of molten metal, but in this test the fluid is impregnated into ceramic fiber media and the linear flame propagation rate, used for the comparison of relative flammability is measured.

  1. Oxidation Stability

Oxidation results in the development of acidic products that can lead to corrosion and can also affect the ability of the oil to separate from water Oxidation can also lead to an increase in viscosity and the formation of sludge that can restrict oil paths, thus impairing circulation of the oil and interfering with the function of governors and oil relays. Correctly formulated turbine oils have excellent resistance to oxidation and will function satisfactorily for long periods without changing the system charge. Oxidation stability can be assessed by various tests (ASTM D-943, IP 114, IP 157) that use copper as well as iron as catalysts in the presence of water to simulate metals present in service conditions.

Although systems are usually designed to avoid entrainment of air in the oil, it is not always possible to prevent this, and the formation of a stable foam increases the surface area of the oil that is exposed to small bubbles of air, thus assisting oxidation. Defoaming agents are usually incorporated in turbine oils to decrease their foaming tendency, and this can be measured (ASTM D-892, IP 146). Air release is also an important property, and a careful choice of type and amount of defoaming agents is necessary to provide the correct balance of foam protection and air release properties.

  1. Pour Point

The pour point (ASTM D-97, IP 15) is the lowest temperature at which an oil will flow under specified test conditions, and it is roughly equivalent to the tendency of the oil to cease to flow from a gravity-fed system or from a container and is a guide to, but not an exact measure of, the temperature at which flow ceases under the service conditions of a specific system.

The pour point of wax-containing oils can be reduced by the use of special additives known as pour point depressants that inhibit the growth of wax crystals, thus preventing the formation of a solid structure. It is a recognized property of oil of this type that previous thermal history may affect the measured pour point. The test procedure (ASTM D-97, IP 15) also permits some measurement of the effect of thermal conditions on waxy oils.

The importance of the pour point to the user of lubricants is limited to applications where low temperatures are likely to influence oil flow. Obvious examples are refrigerator lubricants and automotive engine oils in cold climates. Any pump installed in outside locations where temperatures periodically fall below freezing should utilize lubricants with a pour point below those temperatures or the borderline pumping temperature can be

  1. Thermal Stability

The panel coking test, when used in conjunction with other tests, can be used to assess the deposit-forming tendencies due to thermal instability, and the available alkalinity of these oils can be measured (ASTM D-66, IP 177 IP 276).

  1. Viscosity

The viscosity of lubricating oil is a measure of its flow characteristics. It is generally the most important controlling property for manufacture and for selection to meet a particular application. The viscosity of a mineral oil changes with temperature but not normally with high stress and shear rate (ASTM D-5275,ASTM D-5481,ASTM D-5684,IP 294), unless specific additives that may not be shear stable are included to modify the viscosity temperature characteristics. Explosions can also result when lubricating oil is in contact with certain metals under high shear conditions (ASTM D-3115).

Thus for base oils, the rate of flow of the oil through a pipe or capillary tube is directly proportional to the pressure applied.This property is measured for most practical purposes by timing the flow of a fixed amount of oil through a calibrated glass capillary tube under gravitational force at a standard temperature and is known as the kinematic viscosity of the oil (ASTM D-445, IP 71). The unit of viscosity used in conjunction with this method is the centistoke (cSt), but this may be converted into the other viscosity systems (Saybolt, Redwood, Engler) by means of conversion formula. At very high pressures, the viscosity of mineral oils increases considerably with increase in pressure, the extent depending on the crude source of the oil and on the molecular weight (ASTM D-2502, ASTM D-2878) of the constituent components.

Because the main objective of lubrication is to provide a film between load-bearing surfaces, the selection of the correct viscosity for the oil is aimed at a balance between a viscosity high enough to prevent the lubricated surfaces from contacting and low enough to minimize energy losses through excessive heat generation caused by having too viscous a lubricant (ASTM D-2422, BS-4231).

The standard viscosity temperature charts (ASTM D-341) are useful for estimating viscosity at the various temperatures that are likely to be encountered in service.

The viscosity of automotive engine oil is the main controlling property for manufacture and for selection to meet the particular service condition using the American Society of Automotive Engineers (SAE) viscosity classification.

The higher-viscosity oils are standardized at 210°F (99°C), and the lighter oils that are intended for use in cold weather conditions are standardized at 0°F (–18°C). The principal difference between the requirements of gas and other internal combustion engine oils is the necessity to withstand the degradation that can occur from accumulation of oxides of nitrogen in the oil that are formed by combustion.The condition of gas engine oils in large engines can be followed by measuring oil viscosity increase (ASTM D-66, ASTM D-97, IP 177, IP 139) to determine changes in the neutralization value resulting from oxidation. In addition, analytical techniques such as infrared spectroscopy and membrane filtration can be used to check for nitration of the oil and buildup of suspended carbonaceous material.

The viscosity index is an empirical number that indicates the effect of change of temperature on the viscosity of an oil. Multigrade motor oils do not behave as Newtonian oils, and the improved viscosity-temperature characteristics of multigrade oils enables, for example, an oil to be formulated to have mixed characteristics (ASTM D-2602, ASTM D-3829).

The viscosity index is important in applications in which an appreciable change in temperature of the lubricating oil could affect the operating characteristics of the equipment. Automatic transmissions for  passenger vehicles

are an example of this, where high-viscosity-index oils with improvers are used to minimize differences between a viscosity low enough to permit a sufficiently rapid gear shift when starting under cold conditions and a viscosity adequate at the higher temperatures encountered in normal running. Paraffinic oils have the lowest rate of change of viscosity with temperature (highest viscosity index), whereas the naphthenic/aromatic oils have the highest rate of change (lowest viscosity index) (ASTM D-567, ASTM D-2270, IP 73, IP 226).

The viscosity index of multigrade automotive engine oils is typically in the range of 130–190, whereas monograde oils are usually between 85 and The improved viscosity-temperature characteristics of multigrade oils enables, for example, an SAE 20W/50 oil to be formulated that spans SAE 20W viscosity characteristics at low temperatures and SAE 40 to 50 characteristics at the working temperature.

However, multigrade oils do not behave as Newtonian fluids and this is primarily due to the presence of polymeric viscosity index improvers. The result is that the viscosity of multigrade oils is generally higher at –18°C (0°F) than is predicted by extrapolation from 38°C (100°F) and 99°C (210°F) data, the extent of the deviation varying with the type and amount of viscosity index improver used. To overcome this, the SAE classification is based on a measured viscosity at –18°C (0°F) using a laboratory test apparatus known as a cold cranking simulator (ASTM D-2602).

  1. Volatility

The volatility of lubricating oil is not usually an issue for multitesting. Nevertheless, tests are available so that specification and purity checks can be made (ASTM D-5480). A method that is used to determine pitch volatility (ASTM D-4893) might also be used, on occasion, to determine the nonvolatility of lubricating oil. In the method, an aluminum dish containing about 15 g of accurately weighed sample is introduced into the cavity of a metal block heated and maintained at 350°C (662°F). After 30 min, during which the volatiles are swept away from the surface of the sample by preheated nitrogen, the residual sample is taken out and allowed to cool down in the desiccator.

Nonvolatility is determined by the sample weight remaining and is reported as percent w/w residue. A test is also available for the determination of engine oil volatility at 371°C (700°F), which is actually a requirement in some lubricant specifications (ASTM D-6417). This test method can be used on lubricant products not within the scope of other test methods with simulated distillation methodologies (ASTM D-2887). Applicability of this test method is limited to samples with an initial boiling point higher than 126°C. This test method may be applied to both lubricant oil base stocks and finished lubricants containing additive packages.

In the test, a sample aliquot diluted with a viscosity-reducing solvent is introduced into the gas  hromatographic system, which uses a nonpolar open tubular capillary gas chromatographic column for eluting the hydrocarbon components of the sample in the order of increasing boiling point. The column oven temperature is raised at a reproducible linear rate to effect separation of the hydrocarbons. Quantitation is achieved with a flame ionization detector.The sample retention times are compared with those of known hydrocarbon mixtures, and the cumulative corrected area of the sample determined to the 371°C (700°F) retention time is used to calculate the percentage of oil volatilized at 371°C (700°F).

  1. Water and Sediment

Knowledge of the water content of petroleum products is important in refining, purchase and sale, and transfer of products and is useful in predicting the quality and performance characteristics of the products. The Karl Fischer test method ASTM D-6304) can be applied to the direct determination of water in lubricating oil. In this method, the sample injection in the titration vessel can be done volumetrically or gravimetrically.

The instrument automatically titrates the sample and displays the result at the end of the titration. Viscous samples can be analyzed by using a water vaporizer accessory that heats the sample in the evaporation chamber, and the vaporized water is carried into the Karl Fischer titration cell by a dry, inert carrier gas.

Sediment in lubricating oil can lead to system malfunction in critical applications, and determination of the amount of sediment is a necessity. In the test method (ASTM D-2273), a 100-ml sample of oil is mixed with 50ml of ASTM precipitation naphtha and is heated in a water bath at 32–35°C (90–95°F) for 5 min. The centrifuge tube containing the heated mixture is centrifuged for 10 min at a rate of between 600 and 700 relative centrifuge force (rcf). After the mixture is decanted carefully, the procedure is repeated with another portion of naphtha and oil. The final reading of sediment is recorded. This test method is not applicable in cases in which precipitated oil-soluble components will appreciably contribute to the sediment yield.

Insoluble material may form in lubricating oil in oxidizing conditions, and a test method is available (ASTM D-4310) to evaluate the tendency of lubricating oil to corrode copper catalyst metal and to form sludge during oxidation in the presence of oxygen, water, and copper and iron metals at an elevated temperature.This test method is a modification of another test method (ASTM D-943) in which the oxidation stability of the same kind of oils is determined by following the acid number of the oil. In the test method (ASTM D-4310), an oil sample is contacted with oxygen in the presence of water and iron-copper catalyst at 95°C (203°F) for 100 h. The weight of the insoluble material is determined gravimetrically by filtration of the oxidation tube contents through a 5-mm-pore size filter disk. The total amount of copper in the oil, water, and sludge phases is also determined.

1. Handbook of Petroleum Product Analysis – JAMES G. SPEIGHT.
2. Petroleum Production Engineering Handbook – PEH.

Three-Phase Oil–Water–Gas Separators




in general, to the separation of any gas–liquid system such as gas–oil, gas–water, and gas–condensate systems. In almost all production operations, however, the produced fluid stream consists of
three phases: oil, water, and gas.
Generally, water produced with the oil exists partly as free water and partly as water-in-oil emulsion. In some cases, however, when the water– oil ratio is very high, oil-in-water rather than water-in-oil emulsion will form. Free water produced with the oil is defined as the water that will settle and separate from the oil by gravity. To separate the emulsified water, however, heat treatment, chemical treatment, electrostatic treatment, or a combination of these treatments would be necessary in addition to gravity settling.Therefore, it is advantageous to first separate the free water from the oil to minimize the treatment costs of the emulsion.
Along with the water and oil, gas will always be present and, therefore, must be separated from the liquid. The volume of gas depends largely on the producing and separation conditions. When the volume of gas is relatively small compared to the volume of liquid, the method used to separate free water, oil and gas is called a free-water knockout. In such a case, the separation of the water from oil will govern the design of the vessel. When there is a large volume of gas to be separated from the liquid (oil and water), the vessel is called a three-phase separator and either the gas capacity requirements or the water–oil separation constraints may govern the vessel design. Free-water knockout and three-phase separators are basically similar in shape and components. Further, the same design
concepts and procedures are used for both types of vessel.

read also Gas - Oil Separators

Three-phase separators may be either horizontal or vertical pressure vessels similar to the two-phase separators However, three-phase separators will have additional control devices and may have additional internal components. In the following sections, the two types of separator (horizontal and vertical) are described and the basic design equations are developed.

Horizontal Three Phase Separators

Three-phase separators differ from two-phase separators in that the liquid collection section of the three-phase separator handles two immiscible liquids (oil and water) rather than one. This section should, therefore, be
designed to separate the two liquids, provide means for controlling the level of each liquid, and provide separate outlets for each liquid. figure above show schematics of two common types of horizontal three-phase separators. The difference between the two types is mainly in the method of controlling the levels of the oil and water phases. An interface controller and a weir provide the control. The design of the second type , normally known as the bucket and weir design, eliminates the need for an interface controller.
The operation of the separator is, in general, similar to that of the two-phase separator. The produced fluid stream, coming either directly from the producing wells or from a free-water knockout vessel, enters the separator and hits the inlet diverter, where the initial bulk separation of the gas and liquid takes place due to the change in momentum and difference in fluid densities. The gas flows horizontally through the gravity settling section (the top part of the separator) where the entrained liquid droplets, down to a certain minimum size (normally 100 mm), are separated
by gravity. The gas then flows through the mist extractor, where smaller entrained liquid droplets are separated, and out of the separator through the pressure control valve, which controls the operating pressure of the
separator and maintains it at a constant value. The bulk of liquid, separated at the inlet diverter, flows downward, normally through a downcomer that directs the flow below the oil–water interface. The flow of the liquid through the water layer, called water washing, helps in the coalescence and separation of the water droplets suspended in the continuous oil phase. The liquid collection section should have sufficient volume to allow enough time for the separation of the oil and emulsion from the water. The oil and emulsion layer forming on top of the water is
called the oil pad. The weir controls the level of the oil pad and an interface controller controls the level of the water and operates the water outlet valve. The oil and emulsion flow over the weir and collect in a separate compartment, where its level is controlled by a level controller that operates the oil outlet valve.
The relative volumes occupied by the gas and liquid within the separator depend on the relative volumes of gas and liquid produced. It is a common practice, however, to assume that each of the two phases occupies 50% of the separator volume. In such cases, however, where the produced volume of one phase is much smaller or much larger than the other phase, the volume of the separator should be split accordingly between the phases. For example, if the gas–liquid ratio is relatively low, we may design the separator such that the liquid occupies 75% of the separator volume and the gas occupies the remaining 25% of the volume. The operation of the other type of horizontal separator differs only in the method of controlling the levels of the fluids. The oil and emulsion flow over the oil weir into the oil bucket, where its level is controlled by a simple level controller that operates the oil outlet valve.

read also Two-Phase Gas - Oil Separation

The water flows through the space below the oil bucket, then over the water weir into the water collection section, where its level is controlled by a level controller that operates the water outlet valve. The level of the liquid in the separator, normally at the center, is controlled by the height of the oil weir. The thickness of the oil pad must be sufficient to provide adequate oil retention time. This is controlled by the height of the water weir relative to that of the oil weir.

Vertical Three-Phase Separators 

3 phase vertical separatorthe horizontal separators are normally preferred over vertical separators due to the flow geometry that promotes
phase separation. However, in certain applications, the engineer may be forced to select a vertical separator instead of a horizontal separator despite the process-related advantages of the later. An example of such applications is found in offshore operations, where the space limitations on the production platform may necessitate the use of a vertical separator.
The produced fluid stream enters the separator from the side and hits the inlet diverter, where the bulk separation of the gas from the liquid takes place. The gas flows upward through the gravity settling sections which are designed to allow separation of liquid droplets down to a certain minimum size (normally 100 mm) from the gas. The gas then flows through the mist extractor, where the smaller liquid droplets are removed. The gas leaves the separator at the top through a pressure control valve that controls the separator pressure and maintains it at a constant value.
The liquid flows downward through a downcomer and a flow spreader that is located at the oil–water interface. As the liquid comes out of the spreader, the oil rises to the oil pad and the water droplets entrapped in the oil settle down and flow, countercurrent to the rising oil phase, to collect in the water collection section at the bottom of the
separator. The oil flows over a weir into an oil chamber and out of the separator through the oil outlet valve. A level controller controls the oil level in the chamber and operates the oil outlet valve. Similarly, the water out of the spreader flows downward into the water collection section, whereas the oil droplets entrapped in the water rise, countercurrent to the water flow, into the oil pad. An interface controller that operates the water outlet valve controls the water level.

The use of the oil weir and chamber in this design provides good separation of water from oil, as the oil has to rise to the full height of the weir before leaving the separator. The oil chamber, however, presents some problems. First, it takes up space and reduces the separator volume needed for the retention times of oil and water. It also provides a place for sediments and solids to collect, which creates cleaning problems and may hinder the flow of oil out
of the vessel. In addition, it adds to the cost of the separator.Liquid–liquid interface controllers will function effectively as long as there is an appreciable difference between the densities of the two liquids.

In most three-phase separator applications, water–oil emulsion forms and a water–emulsion interface will be present in the separator instead of a water–oil interface. The density of the emulsion is higher than that of the
oil and may be too close to that of the water. Therefore, the smaller density difference at the water–emulsion interface will adversely affect the operation of the interface controller. The presence of emulsion in the separator takes up space that otherwise would be available for the oil and/or the water. This reduces the retention time of the oil and/or water and, thus results in a less efficient oil–water separation. In most operations where the presence of emulsion is problematic, chemicals known as deemulsifying agents are injected into the fluid stream to mix with the
liquid phase. Another method that is also used for the same purpose is the addition of heat to the liquid within the separator. In both cases, however, the economics of the operations have to be weighted against the technical constraints.

Separation Theory 
in general, valid for three-phase separators. In particular, the equations developed for separation of liquid
droplets from the gas phase, which determined the gas capacity constraint, are exactly the same for three-phase separators.
Treatment of the liquid phase for three-phase separators is, however, different from that used for two-phase separators. The liquid retention time constraint was the only criterion used for determining the liquid capacity of two-phase separators. For three-phase separators, however, the settling and separation of the oil droplets from water and of the water droplets from oil must be considered in addition to the retention time constraint. Further, the retention time for both water and oil, which might be different, must also be considered.
In separating oil droplets from water, or water droplets from oil, a relative motion exists between the droplet and the surrounding continuous phase. An oil droplet, being smaller in density than the water, tends to move vertically upward under the gravitational or buoyant force, that the droplet settling velocity is inversely proportional to the viscosity of the continuous phase. Oil viscosity is several magnitudes higher than the water viscosity. Therefore,
the settling velocity of water droplets in oil is much smaller than the settling velocity of oil droplets in water. The time needed for a droplet to settle out of one continuous phase and reach the interface between the two phases depends on the settling velocity and the distance traveled by the droplet. In operations where the thickness of the oil pad is larger than the thickness of the water layer, water droplets would travel a longer distance to reach the water–oil interface than that traveled by the oil droplets. This, combined with the much slower settling velocity of the water droplets, makes the time needed for separation of water from oil longer than the time needed for separation of oil from water. Even in operations with a very high water–oil ratio, which might result in having
a water layer that is thicker than the oil pad, the ratio of the thickness of the water layer to that of the oil pad would not offset the effect of viscosity. Therefore, the separation of water droplets from the continuous oil phase would always be taken as the design criterion for three-phase separators.
The minimum size of the water droplet that must be removed from the oil and the minimum size of the oil droplet that must be removed from the water to achieve a certain oil and water quality at the separator exit depend largely on the operating conditions and fluid properties. Results obtained from laboratory tests conducted under simulated field conditions provide the best data for design. The next best source of data could be obtained from nearby fields. If such data are not available, the minimum water droplet size to be removed from the oil is taken as 500 mm.
Separators design with this criterion have produced oil and emulsion containing between 5% and 10% water. Such produced oil and emulsion could be treated easily in the oil dehydration facility.

Retention Time

Another important aspect of separator design is the retention time, which determines the required liquid volumes within the separator. The oil phase needs to be retained within the separator for a period of time that is sufficient for the oil to reach equilibrium and liberates the dissolved gas.
The retention time should also be sufficient for appreciable coalescence of the water droplets suspended in the oil to promote effective settling and separation. Similarly, the water phase needs to be retained within the separator for a period of time that is sufficient for coalescence of the suspended oil droplets. The retention times for oil and water are best determined from laboratory tests; they usually range from 3 to 30 min, based on operating conditions and fluid properties. If such laboratory data are not available, it is a common practice to use a retention time of 10 min
for both oil and water.

1. Oil and gas Production Handbook.
2. Oil and Gas Field Processing – King Fahd University of Petroleum and Minerals.

Crude Oil Contracts

Oil Contract

Major traded oils

More than 170 different oils are traded on the market, but this section will discuss the three major oils that usually attract the most attention, both in the news and in the markets around the world. West Texas Intermediate (WTI) is a crude oil of extremely high quality and because of this property, it is possible to extract more gasoline from a single barrel compared with most other crude oils traded on the market. The WTI has an API 10 gravity of 39.6 degrees, which gives the oil the characteristic of “light”; moreover the concentration of 0.24 percent of sulfur makes it a “sweet” crude oil. Those qualities together with the extraction location, make the WTI the prime crude oil refined within the United States, which is the largest gasoline consuming country on the planet. The vast amount of the WTI crude oil is refined mainly in the Gulf Coast and in the Midwest regions. Because of its characteristic, the WTI crude oil, is usually priced higher than the other two main traded oil: respectively $5-7 per barrel higher than the OPEC basket and $1-2 more than the “Brent Blend”.

here is live WTI crude oil price:

Read also Crude Oil Price

Brent Blend
we always hear about Brent Crude Oil Price and Brent Blend in the news, so let us first define Brent Blend:
is a combination of different types of crude oils, which are extracted from 15 fields throughout the Nynas system, located in the North Sea, and the Scottish Brent. The “API Gravity” of this particular oil is 38.3 degrees: this characteristic makes it a “light” oil similar to the WTI, but not as much as the WTI. In the same way, the quantity of sulfur contained (0.37 percent), makes it a “sweet” crude oil, but not as “sweet” as the WTI. Brent Blend properties make this crude oil excellent for the production of gasoline and middle distillates, which are most used in North-West Europe. As for the WTI, the production of the Brent is in a declining trend, but remains one of the major benchmarks to analyze the price of crude oils both in Europe and in Africa. Usually the Brent Crude Oil price is approximately $4/barrel higher than the OPEC Basket price and $1-2 lower than the WTI.

here is live Brent Crude Oil Price:

OPEC Basket Oil price
This is a weighted average of prices for petroleum blends produced by OPEC countries. The basket is composed of 11 different types of crude oils from Algeria, Saudi Arabia, Nigeria, Venezuela, Ecuador, Iran, Iraq, Kuwait, Libya, Qatar, UAE and Angola. The acronym OPEC means “Organization of Petroleum-Exporting Countries” which is an organization that was created in 1960 to generate common policies for the production quotas and the sale prices among its members. Compared with the WTI and the Brent Blend, the OPEC oil contains a higher percentage of sulfur and therefore is not as “sweet” as these oils; moreover, the OPEC oil is not naturally “light” as the WTI or Brent. Because of these two reasons, the quantity of gasoline that is possible to extract from this oil is lower, thus the prices of OPEC oil are normally lower than the WTI or Brent.

Futures contracts
A futures contract is an agreement between two parties to buy or sell an asset at a certain time in the future for a certain price. Different from forward contracts, futures are traded on regulated exchange markets. In order to be traded on exchange, the contracts need to have standardized characteristics. Furthermore, because this mechanism does not allow the two parties to know each other, the exchange also provides a guarantee that the contract will be honored, acting as a clearing house. As already mentioned in the previous section, the largest exchange markets, on which the futures contracts are traded, are both the CME and CBOT. On these two exchanges and throughout markets all around the world, a very wide range of futures contracts with completely different underlying assets are traded. Examples of commodities, beside the above mentioned crude oil, are sugar, coffee, lumber, aluminum, gold, silver and copper. The financial asset category includes stocks, currencies, indices and treasury bonds.

 Specification of a future contract
The exchange, when creating new futures contracts, has to specify exactly the nature and the details of the agreement between the parties. Determined characteristics have to be examined, which include the grade (quality), the size of the contract (the amount of the asset that will be delivered), the location where the delivery will take place, and the exact date on which the delivery will be made. In some situations alternative options for the delivery locations or for the grade of the asset are possible, and are indicated on the contract. As a common rule, the party who is trading a shortposition (the party that agreed to sell the asset in the future at a prearranged price) has the faculty to choose the alternative that he prefers. When the party who has the short position is ready to deliver and thus has made a decision among the alternatives, the party has to communicate its selection to the exchanges through the issue of a notice. The main specifications defined by an exchange are:

The Asset
When a futures contract regards the commodities market this determination of the grade is fundamental for the proceeding of the transaction: within the market there are a wide range of different qualities of any commodities, thus it is important that the exchange determines the minimum grade that is acceptable. As an example the New York Cotton Exchange has stipulated the grade of its orange juice future contract as: “US Grade A, with Brix value of not less than 57 degrees, having a Brix value to acid ratio of not less than 13 to 1 nor more than 19 to 1, with factors of color and flavor each scoring 37 points or higher and 19 for defects, with a minimum score 94.
Another example by the random length lumber futures specified by the CME: “Each delivery unit shall consist of nominal 2 x4s of random lengths from 8 feet to 20 feet, gradestamped Construction and Standard, Standard and Better, or #1 and #2 however, in no case may the quantity of Standard grade or #2 exceed 50%. Each delivery unit shall be manufactured in California, Idaho, Montana, Nevada, Oregon, Washington, Wyoming, or Alberta or British Columbia, Canada, and contain lumber-produced from grade-stamped Alpine fir, Englemann spruce, hem-fir, lodgepole pine, and/or spruce pine fir.  For certain commodities there is also the possibility to deliver a range of grades of the asset, but, in this case, the price paid from the counterpart depends on the grades of the commodities chosen for the delivery. As an example, in the CBOT, the standard grade of a corn futures contract is the “Number 2 Yellow”, but substitutions are allowed, therefore the price has to be adjusted respecting the rules and procedures established by the exchange. Differently from the commodities, the financial assets that underlie the futures contracts are usually well defined and do not leave space for ambiguity. For example, it is not necessary to specify the grade of a currency. Although the futures contracts on the financial assets may always seem clear, there are some situations in which the determination of the prices become more complicated. In a Treasury bond the underlying asset is any US Treasury bond that has a maturity date longer than 15 years and that is not callable within 15 years. Because of the differing expiration of the T-bond from the futures contract on the same Treasury Bond, the exchanges have determined formulas that are utilized to adjust the price of the futures based on the coupon and maturity date of the bond delivered.

The Contract Size
The contract size determines the amount of the underlying asset that has to be delivered for a single contract. Finding the optimum amount for delivery is a key decision for each exchange. If the stabilized contract size is too large, then the traders who wanted to hedge small positions or make small speculation trades will not be able to operate on the exchange. On the other hand, having a too small contract size, will increase the overall cost of transaction, as the number of contracts that will be necessary to cover the same amount will rise. There is no a correct size of a contract, but it depends always on the user who takes part in the transaction. Whereas the values of some futures contracts are a few thousand dollars for some agricultural products, others can be much higher, such as the crude oil or more generally the financial futures that have a face values of over $100,000. In some exchanges, other types of contracts have been introduced in order to attract small investors. An example of those smaller contracts, called “mini”, is the E-Mini S&P500 Futures, which has a contract one-fifth the size of the regular S&P500 Futures.

Read Also Crude Oil Trading

Delivery Arrangements
The exchange has to determine the location where the delivery will take place. This specification is a factor of key importance for commodities that implicate significant transportation costs. For example, the CME specifies the delivery location of random-length lumber futures contracts as: “On track and shall either be unitized in double-door boxcars or, at no additional cost to the buyer, each unit shall be individually paper-wrapped and loaded on flatcars. Par delivery of hem-fir in California, Idaho, Montana, Nevada, Oregon, and Washington, and in the province of British Columbia.” If there is the possibility of alternative delivery locations, the price that the party selling the futures contracts receives will be adjusted according to the location chosen. For example, the corn futures contracts that are traded within the CBOT gives the possibility to the party with a short position to deliver the commodity in Chicago, Toledo, Burn Harbor or Saint Louis; although the commodity delivered is the same, but because of the price adjustment, the deliveries that are made in Toledo and Saint Louis will have a discount of $0.04 per bushel compared to the price traded in Chicago.

Delivery Months
Futures contracts based on the same underlying asset have different delivery months. The exchange has to determine the period (month) in which the operation of delivery can be executed. As a general rule on the futures contracts, the delivery can be made during the whole month. The delivery months are not fixed, but can vary on each contract. The delivery period and modality of the Light Sweet Crude Oil Futures at the CME/NYMEX is defined as:
(A) Delivery shall take place no earlier than the first calendar day of the delivery month and no later than the last calendar day of the delivery month.
(B) It is the short’s obligation to ensure that its crude oil receipts, including each specific foreign crude oil stream, if applicable, are available to begin flowing ratably in Cushing, Oklahoma by the first day of the delivery month, in accord with generally accepted pipeline scheduling practices.
(C) Transfer of title-The seller shall give the buyer pipeline ticket, any other quantitative certificates and all appropriate documents upon receipt of payment. The seller shall provide preliminary confirmation of title transfer at the time of delivery by telex or other appropriate form of documentation.
Although this chapter discusses about delivery methods and periods, most of the futures contracts do not lead to actual physical delivery. The traders usually decide to close their open positions before the expiration of the contract and thus before the delivery date. This operation can be done by entering into a trade with the opposite direction in respect to the original one. For example, a Chicago trader who sold a contract of crude oil on April 3, can close out his position by buying a contract (i.e. a long trade) of the same asset on May 3. In this case, the investor will register a profit or a loss depending of the difference of the futures prices between April 3 and May 3.

 Price Quotes
The futures contract prices are created in a way that is convenient to understand them. For example, the crude oil futures price at the CME is quoted as two-decimal places of dollar per barrel. Therefore the minimum movement that the price can have is $0.0117. The Natural Gas futures contract listed at CME is still quoted in dollars, but given its different nature, it is listed at dollar per mmBtu (British Thermal Units) and the minimum price variation is $0.0001 for MMBtu18 .

Price Limits and Position Limits
For the vast majority of futures contracts, the limits of the daily price movement are specified by the exchange. If the price increases and hits the upper limit set by the regulations, the contract is “limit up.” On the other side, if the price of the contract drops to the lower level, it is said to be “limit down.” Usually, when the price hits either the upper or the lower limit, the transactions of the day for that futures contract ceases. In some particular cases, however, the exchange can decide to change the limits and therefore not to end the trading day. The main purpose of the price limit is to preclude large price movements, which may be generated by the trading operations of speculators. On the other hand, the price limit can become a barrier that can artificially contain the pace of the price movement of the futures contracts, while the underlying asset may be moving (increasing or decreasing) its price at a faster pace. An example of price limit regulation on the crude oil Futures at the CME: “Initial Price Fluctuation Limits for All Contract Months. At the commencement of each trading day, there shall be price fluctuation limits in effect for each contract month of this futures contract of $10.00 per barrel above or below the previous day’s settlement price for such contract month. If a market for any of the first three (3) contract months is bid or offered at the upper or lower price fluctuation limit, as applicable, on Globex it will be considered a Triggering Event which will halt trading for a five (5) minute period in all contract months of the CL futures contract.  Position limits regulate the maximum amount of contracts that a single trader may hold. The main purpose of these limits is to avoid a single speculator excessively influencing the market.

1. Technical analysis trading strategy – Masaryk University Faculty of Economics and Administration.
2. Oil Market Basics – Office of Oil and Gas, Energy Information Administration.

Oil Trading

Oil Trading Books

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all you have to do, is to choose the required book then click on DOWNLOAD under the book’s name, and you will be redirected to the download link page, links are updated and monitored continuously, if you see any BROKEN LINK report it to our website team.

Crude Oil Trading Hedge Strategy

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What Drives Crude Oil Price?
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Energy Trading Risk Management 2008
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Energy Trading Risk Management 2009
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Generating Moving Average Trading Rules on the Oil Futures
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Global Implications of Lower Oil Prices
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How Oil Market Works?
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Next Generation Solution for Oil Trading and Risk Management
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Oil Contracts, How to Read and Understand them
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Oil Trading from bp
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Oil and Gas Trading Brochure

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Seven Secrets to Crude Oil Futures Trading Success
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Technical Analysis for Oil Trading Strategy
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Understanding Basis 

Understanding Crude Oil and Product Markets Primer Low 

Crude Oil Trading

Oil market overview
oil marketThis article gives an overview of the oil market and its dynamics. Furthermore, analyzes the types of oils, their characteristics and the factors that can influence the supply and demand and thus the price of the oil in the market.

The world crude oil market:
The oil industry is a global enterprise that employs millions of workers around the world and generates hundreds of millions of dollars. The oil sector, thus, is considered to be the largest in the world in terms of dollar value. In regions which house the major National Oil Companies, these corporations contribute significantly to the national GDP. The main products of the oil industry are constituted by fuel oil and gasoline (petroleum). Petroleum is one of the primary materials for the chemical industry: it is used for pharmaceutical products, plastics, solvents and fertilizers. Oil plays a key role in industrial production and therefore is a resource of critical importance for all the countries in the world. During the last decade, a growing negative sentiment against the oil industry has been emerging. Recent environmental disasters such as the BP oil spill (also referred to as the Deepwater Horizon Gulf Of Mexico Oil Spill) has given a negative spotlight on the whole oil industry. Moreover, the companies working in the oil and gas sector are being threatened by the increasing importance and attention given to renewable and alternative energies. Due to these phenomena, the government is putting pressure on these companies through increased legislations. Despite the increasing negative sentiment, the oil and gas industry is still extremely successful, and is experiencing a strong and rapid growth. It is estimated that the worldwide consumption of oil is 30 billion barrels per year, and this amount is mostly utilized by the developed countries. Moreover, oil also represents the major source of energy consumed around the globe and accounts for 32% in Europe, 35% in Asia, 40% in North America, 42% in Africa, and 51% in Middle East.

read also Crude Oil Price

Major oil futures exchanges Oil is one of the main commodities traded around the world. This section is focused on three among the major exchanges in which a large amount of oil futures contracts are traded.

The Chicago Mercantile Exchange (CME) was founded in 1895 in Chicago, Illinois, USA, and is one of the most important markets for derivate worldwide. Despite its importance, the CME is not the first American futures market as the Chicago Board of Trade ( CBOT ) was founded in 1848. In 2007 the CBOT was incorporated within the CME Group. In August 2008, the acquisition of the New York Mercantile Exchange (NYMEX) was completed. For a long time the only contracts traded on the CME had underlying assets as agricultural products such as grain, flour bacon etc. We have to wait until 1972 to witness the debut of the first “financial futures”. In that year, futures on seven currencies (British pound, Canadian dollar, German mark, French franc, Japanese yen, Mexican peso , Swiss franc) began to be traded. The development of financial markets in the following years led to an exponential growth of the tools available to operators. Between 1975 and 1977, the CBOT launched the first futures on interest rates. Particularly important was the debut of the contract on T- Bonds, the title of the US government, which quickly became the most traded futures in the world. The period between ’81 – ’82 was also crucial because the CME introduced the contract on Eurodollar deposits and then the first futures on a stock index , the S&P 500. In 1997, the CME opened its doors to private traders thanks to the invention of E-mini S&P 500 futures, contracts of smaller size than the standard, negotiated with margins also accessible to noninstitutional traders. Currently, the range of products traded at the CME Group ranges from futures and options on indices, currencies, interest rate, commodities and derivatives up to the economic indicators (e.g. inflation) and the evolvement of weather conditions. Exchanges at the CME take place in two ways. One being the classic system of “shouting”, in which specialized operators are physically present in the room for negotiation and exchange contracts through a set of codified hand gestures (impossible to do so by voice as this would be too chaotic).

This process was supplemented in 1992 with an online platform that allows traders to operate remotely via dedicated terminals .

The Intercontinental Exchange Group (ICE), is a complex network composed of clearing houses and exchanges created for financial and commodity markets. The group created in May 2000 is headquartered in Atlanta, Georgia and the ICE actually owns 23 exchanges and marketplaces all around the globe. This network, different from other marketplaces, operates completely as an electronic exchange, which connects firms and individuals looking to trade oil, electric-power, natural gas and general commodity derivatives. Moreover, the ICE also facilitates the exchange of emission (cap-and-trade) and OTC energy exchanges. In 2001 ICE acquired the International Petroleum Exchange (IPE), which is now called ICE Futures Europe. Furthermore, in 2007, the ICE also acquired the New York Board of Trade, that is now known as ICE Futures US.

The New York Mercantile Exchange (NYMEX) is arguably the largest market for the exchange of futures, as well as a major headquarters for the commercialization of energy and precious metals. Among other things, the exchange is also characterized by a major characteristic: the NYMEX stands out for its 135 years history of integrity and transparency in pricing. The transactions that take place here limit the risk of default by the counterparty. Trading relates to energy, metals, futures on environmental goods and some options relating to the system of e-commerce. The NYMEX refers to markets for the exchange of materials such as crude oil, diesel fuel, gasoline, natural gas, electricity, propane, uranium and other naturally occurring assets such as gold, silver, aluminum, platinum. Many varieties of options are available, including, options on the price differential between crude oil and its derived products (or so-called “crack spreads”), monthly futures contracts (better known in the U.S. as “calendar spreads”) and the European and Asian options . In essence the NYMEX offers products that ultimately aim to minimize the risk of default by the counterparty, as mentioned before . Usually, investors who choose to entrust their portfolio choices on the New York Mercantile Exchange are attracted by features such as excellent liquidity, the offering of stocks and bonds. The prices relative to prices in this market are often used as a reference by buyers from sellers who operate in the markets that exchange materials such as energy and precious metals.

Factors influencing the market
The worldwide oil market is strongly affected by several factors, which can have a dramatic effect on the spot price. This section presents ten main variables that can influence the market.

Read Also Crude Oil Contracts

 The Organization of the Petroleum Exporting Countries is a consortium composed of 13 nations: Algeria, Angola, Ecuador, Indonesia, Iran, Iraq, Kuwait, Libya, Nigeria, Qatar, Saudi Arabia, the United Arab Emirates and Venezuela. This organization is the largest single entity that can affect, through its choices, the world’s oil supplies. OPEC is accountable for more than 40% of the world’s production of oil. OPEC decides the policy of the member countries in order to meet the global oil consumption. This entity can strongly affect the price of the crude oil, just by changing the production levels among its members.

Supply and Demand
The amount of oil present in the inventories balances the supply and demand. When the production exceeds the amount of the demand, the surplus can be stored. In the opposite way, if the consumption exceeds the demand, inventories can be exploited in order to cover the incremental demand: the strong relationship between oil inventories and oil prices makes corrections in each direction possible. Non-OPEC suppliers produce almost 60% of the global oil and thus outpace the OPEC countries in terms of production by 50%. Despite this difference in production levels the non-OPEC countries do not have sufficient reserves to control the price, and therefore they have only the ability to respond to market fluctuations.

As already mentioned during the oil market overview, a vast part of the global oil reserves and production are controlled by companies strongly linked to the government. This means the world oil market is heavily affected by political decisions and so this market is far to be a competitive place. Moreover the variation in energy policy and taxation in oil-rich countries can also influence the world price of oil.

Political unrest
This is another factor that has always strongly affected the price of oil: if an oil-producing nation becomes politically unstable (e.g. Iranian Revolution in 1979), supplier markets react by increasing the prices of oil, so that the remaining supplies are still available to the highest bidder. The shortage in supply does not need be become real, only the perception of a possible decrease in production can drive the price up.

Production costs
Physical factors determine most of the costs of the oil production: from the location of reserves to the characteristics and the property of the oil found, and ultimately to the extraction procedures. Oil is a nonrenewable natural resource, therefore substantial investments are required for the discovery of new reserves and their development.

 Financial markets
Oil brokers work as an intermediary to match buyers with sellers of crude oil, one of the major contracts traded are the futures contracts. Futures give the possibility to buyers and sellers to hedge their position against possible oil price fluctuations that could affect their profitability. Oil producers sell oil futures to lock their price for a determined amount of time while the counterpart purchases oil futures in order to receive a future delivery of oil at a predetermined price.

Being a commodity, the seasonal cycles in weather influences the demand of oil. During the winter, the amount of heating oil consumed increases, while in the summer people use a larger amount of gasoline to travel. Although markets expect those increased demand periods, the oil prices still raise and level out with the changes of the season every year. Beside the seasonality effect, extreme weather conditions can physically affect the production of oil by damaging infrastructures, interrupting supply, and therefore inducing pricing spikes.

Speculators can influence the cost of crude oil by buying and selling futures contracts on the open market. This phenomena has a huge impact on the price due to particular requirements applied to these contracts. The speculator is not required to have the total sum required for the transaction, but just a small fraction of it (margin). These low margins requirements create a leverage effect. In recent years, it was believed that speculators were driving up the price of oil to the peak, in 2008, at more than $140/barrel. By the end of 2009, prices fell to $30/barrel as there was not a real demand supporting the inflated price level.

Exchange value of the dollar
Oil is bought and sold internationally using the US dollar currency. A depreciation of the dollar usually tends to raise the oil demand and increase the price of the oil. On the other hand, the appreciation of the dollar decreases the real income in consumer countries, therefore reducing the demand and the price of oil.

Non-OECD demand
While oil consumption in the Organization of Economic Cooperation and Development countries has declined during the last 10 years, the consumption in countries that are not part of the OECD has increased more than 40% during the same period. In particular the countries that registered the highest growth of consumption were China, India and Saudi Arabia.

1. Technical analysis trading strategy – Masaryk University Faculty of Economics and Administration.
2. Oil Market Basics – Office of Oil and Gas, Energy Information Administration.

Removing H2S from Oil

Sulfur compounds exist in various light oils made from petroleum. Such as mercaptan, hydrogen sulfide, which cause foul odors and deteriorate the finished products. In addition, due to their acidity, they are corrosive to metals, which is harmful for storage and usage of oil products. Therefore, it is necessary to remove them.
In the refining industry, an aqueous base such as sodium hydroxide or ammonia is employed fulfilling the purpose. Although its effectiveness and the low cost of fresh caustic are the reasons for its widespread use, the aqueous base especially sodium hydroxide always causes some problems. Such as spending many caustic materials, and discarding lots of hazardous waste. So environmental agencies around the world have tightened the regulations aimed at controlling its disposal. Solid bases merge as an ideal alternative to the aqueous bases to overcome the environmental and economic problems. The report concerning solid base is mostly concentrate in mercaptan oxidation, these solid bases selected from the group consisting of magnesium, nickel, zinc, copper, aluminum, iron oxides and mixtures thereof. However the report concerning solid base on removal of hydrogen sulfide was hardly consulted.
This paper reports the effect of factors of preparation for the solid base on removal of hydrogen sulfide at ambient temperature.
Thus selecting the optimum factor of preparation for the solid base on the removal of hydrogen sulfide in light oil.
2.1 Preparation of solid base
Activated carbon marked by DV-01was used as supporter in this study. The activated carbon was calcined at high temperature for 6h, then impregnated with a aqueous solution of some alkalic materials at ambient temperature. The saturated activated carbon was filtrated in vacuum for period of time, then dried period of time at special
Experimental Oil
Petroleum ether(boiling point 90—120℃) was used as experimental oil with 800—1000μg/g hydrogen sulfide
Capability test of solid base for the removal of hydrogen sulfide
1g solid base was loaded in a 200ml flask, to this flask 100ml experimental oil was added, then the solution was electromagnetism stirred at ambient temperature with protection of nitrogen, the stirred speed was 350rpm. The hydrogen sulfide concentration in light oil was analyzed with period by the method of GB/T1792-88.

Materials calculation
The adsorption quantity of solid base for hydrogen sulfide as follows: Xg = (C0-Ct)•ρV•10-3/M
Xg: the adsorption quantity of the solid base for hydrogen sulfide mg/g
C0: Preliminary concentration of hydrogen sulfide μg/g
Ct: concentration of hydrogen sulfide at t hour μg/g
ρ、V: density, vol. of oil g/ml, ml
M: the quality of the used solid base g

The effect of different chemical components of solid base on the removal of H2S
With different alkalic materials, six kinds of solid base were prepared and the removal capacities for H2S were tested. , the SB15 solid base for absorption of hydrogen sulfide has the highest capacity.
The solid base adsorption for hydrogen sulfide has a competitive between physical adsorption and chemical adsorption.
The removal capacity for hydrogen sulfide of the solid base was the sum of physical adsorption and chemical adsorption. Different solid base has different surface area and chemical center, so the capacity for hydrogen sulfide removal is alternatively. SB15 has the best chemical components.

The effect of solid base vacuum filtration time on the removal of H2S
Experiments examine the effect of time of vacuum filtration during preparation of the solid base for the removal of hydrogen sulfide. The activated carbon was impregnated with the optimum concentration of aqueous, then the loaded activated carbon was vacuum filtrated by different time, thereby making A series of solid bases.

the adsorption capacity of the solid base for hydrogen sulfide firstly increased and then decreased with the increase of the vacuum filtration time during the preparation of the solid base. As a result, the time of vacuum filtration is a major factor for the solid base on removal of hydrogen sulfide, the optimum time of vacuum filtration should be 60 min.

The effect of solid base drying time on the removal of H2S
A series of solid bases were made with different time of drying from short to long. And the removal of hydrogen sulfide of these solid bases were examined.

the adsorption quantity of the solid base for hydrogen sulfide firstly increased then decreased with the time of
drying prolonged in the preparation of the solid base. The shorter the time of drying is, the higher the water content of the solid base is, the higher water content of the solid base reduced the physical adsorption of the solid base for hydrogen sulfide. With the further drying, the water is so less in the solid base that can not provide the polar
environment for the chemical adsorption. consequently the chemical adsorption quantity of hydrogen sulfide in the solid base was decreased greatly.
It was found that the optimum time of drying for the solid base with good properties should be 2 hr.

The effect of additive on the removal of H2S
It is believed that the function of polar compound is to serve as a proton transfer medium in the chemical reaction. Specially the compounds are selected from the group consisting of water, alcohols, esters, ketones, diols and mixtures thereof. A group of polar compounds was chosen as the additive for the solid base for removal
of H2S. Experiments were carried out for measuring the adsorption capacity of the solid base with different quantity of the additive.

the additive was added, thus the adsorption of the solid base for hydrogen sulfide has greatly increased.

1.Preparation factors of the solid base play an important role for the solid base on removal of hydrogen sulfide. The preparation factors include the components of solid base, the time of vacuum filtration and the time of drying.
2. The adsorption capacity of the solid base for hydrogen sulfide was the sum of physical adsorption and chemical adsorption.
3. Adding a group of polar compounds can promote significantly the removal of hydrogen sulfide by the solid base. The optimum quantity of the additive is 6000 μg/g.

Wells – Chemicals

Chemicals Used in Fracturing

The identities of chemicals incorporated in fracturing fluids were probably the first thing sensationalized about fracturing. The movie “Gasland” created quite a stir with the statement that a “cocktail” of several hundred toxic chemicals were “potentially” used in fracturing. The grain of truth was that there are many chemicals in additives sold for incorporation in fracturing; however; the fact is that most fracs use only a dozen or so major chemicals, some of which are food-grade additives and many are in parts per million concentration. About half of fracturing jobs are “slick water” fracturing fluid that often use low concentrations of two to five chemicals. Many claims of chemical usage also include trace amounts of chemicals at the edge of detection and most well below the EPA’s strictest limits. Analysis of drinking water, for comparison, has shown arsenic, lead, chromium, solvents, gasoline, pesticides, prescription drugs, and a myriad of household products as the most common contaminants – none from fracturing. The upside to this commentary is that public concerns have moved chemical manufacturers to make and operators to use safer chemicals and less overall chemicals. Many companies have moved toward biocides with less residual activity, mechanical biocides such as ultraviolet light and the use of chemicals on the US EPA’s Safer Choice chemicals (formerly Designed For Environment or DfE) or UK North Sea’s OCNS Hazard rating of Gold Band (lowest possible hazard quotient). These listed materials meet requirements of rapid biodegradation and minimum harm to environments.

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Friction reducer, the largest volume chemical in slick water fracs, is polyacrylate, a polymer whose main use is in baby diaper absorbent and as a drinking water purifier that adsorbs heavy metals. A cross section of chemicals used in fracturing, the volumes used and some alternate uses helps explain oil field fracturing chemical usage. Chemicals such as diesel, benzene and proven carcinogens, mutagens and endocrine disruptors are not used in modern safe fracturing fluids. The CAS number identifies exact identity (no “trade secret” identities).

drilling chemicals

One of the most impactful problems from fracturing in Pennsylvania was the use of local water treating plants to treat water produced from oil and gas wells before disposal into Pennsylvania rivers. The practice was evidently instituted in Pennsylvania decades prior to the shale drilling boom in the Marcellus when volumes of water flowed from conventional wells was very small and natural salt contents were low. Dilution of locally severe acid mine drainage in some creeks by the produced water was expected to be beneficial; however; large volumes of produced water from fracturing in the shales with high salinity and ions such as bromine and barium proved too problematic for such a disposal method. This practice, although allowed by law in Pennsylvania until about 2010, has been forbidden by law in nearly all western states since the 1950’s.

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Chemicals Used in Production Operations

Producing oil and gas with the associated salt water from hydrocarbon bearing formations creates corrosion potential, flow restriction deposits such as mineral scales of calcium or barium and challenges in separating oil from water. Corrosion remains one of the biggest deterioration problems in the oil industry (a large problem in other industries as well). Scales may precipitate in tubulars until they restrict flow. Paraffins (wax) are longer carbon chain components of oil and can deposit anywhere in the well as temperatures cool and pressure declines. Mixing of salt water, oil, gas and a small amount of solids such as sand, rust or even ice can produce emulsions, froths and foams that must be separated before the oil and gas can be sold and the salt water can be recycled or properly re-injected into the hydrocarbon producing formation. A wide variety of specialty chemicals, often at part per million (ppm) concentration, can be used, but only a handful of products are typically selected after laboratory testing. Using minimum amounts of the best additives reduces cost and risk in transport or storage.

drilling chemicals

Any chemical usage may be frightening to some people and there are definitely chemicals that should not be used, particularly where contamination or airborne emissions are possible. By using chemicals proven safe for specific uses, all elements of potential pollution are reduced. Even when the chemicals will never be disposed of in the environment outside of oilfield containment, the safe chemical route minimizes impact in the event of a spill or leak.
Note: BTX (Benzene, Toluene, Xylene) content in many additives is steadily declining but some operators have not phased the products out completely. Many companies are reviewing product offerings for the BTX or other troublesome materials and choosing alternatives. Although BTX is often reported in wells as if they were part of a chemical additive, the most likely source is in the produced oil. BTX and diesel range oil components are a natural part of many produced oils.

Chemicals Used in Crude Oil Production

“A complex combination of hydrocarbons. It consists predominantly of aliphatic, alicyclic and aromatic hydrocarbons. It may also contain small amounts of nitrogen, oxygen and sulfur compounds. This category encompasses light, medium, and heavy petroleums, as well as the oils extracted from tar sands. Hydrocarbonaceous materials requiring major chemical changes for their recovery or conversion to petroleum refinery feedstocks such as crude shale oils,
upgraded shale oils and liquid coal fuels are not included in this definition.”

Oilfield ChemicalsVarious types of chemicals (which themselves can be mixtures or formulations of various chemicals) are required to aid the production, handling and transportation of crude oil. The chemicals used fall into several types as outlined below. For most, only trace amounts may remain in the crude as impurities once it reaches the refinery. This document will review the various types of chemicals used in crude and their role in production.
Most Oilfield production chemicals (OFCs) are complex formulations of many different chemicals. Often the constituent chemicals themselves are not pure chemical species but a mixture of reaction products, reactants, and diluents. The formulation usually has one or two primary ingredients that give the additive its main functionality. In addition, the formulation is specifically designed for each oilfield, and within the oilfield, for each well, and for each well the recipe may vary depending upon the time and the operation conditions. The crude from a number of wells/fields is combined such that it is nearly impossible to ascertain the resulting combination of OFC’s used for a crude oil at a loadport.
Chemicals are used in various stages of oilfield development namely drilling, cementing, well completion, and well stimulation/workover. These chemicals may end up as impurities in the crude oil.
During the production phase, the flow of oil out of the well needs to be assured by preventing the deposition of hydrates, wax, asphaltenes, or scale. Chemicals provide a means for controlling such deposits. The presence of water, bacteria, and acids all result in a corrosive environment. Production of crude oil usually involves a significant bulk water phase, many (OFCs) are water-soluble by design. When used in continuous low dose injection they remain with the water phase at the upstream facilities. The production of oil usually involves its separation from water and gas. A small amount may be present in water droplets dispersed or partitioned in the oil phase as an impurity.

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Additionally chemicals may be needed during the transportation and logistical handling of the crude oil, e.g. in a pipeline, tanker, or terminal. Drag reducing agents can be added in pipelines to improve flow. Pour point depressants, mercaptan scavengers, hydrogen sulfide scavengers are often added to cargoes in order to satisfy shipping or loadport requirements for stability.
Chemicals can be added either by continuous dosage or in batch treatments. The concentration in the crude usually ranges from 10 – 200 ppm. These post-production chemicals help to control corrosion, scale, hydrogen sulfide, bacteria; help to prevent hydrate formation, wax deposition, asphaltene precipitation; and help to resolve emulsions. In other words, they are added to preserve the stability of the crude oil during transport so that the crude can reach the refinery for conversion to products.

Chemical families used in the production and transportation of crude oil include the following:

(1) Scale Inhibitors
Used in the oil production process to prevent the deposition of mineral scale that may occur in the pores of rock formations, in downhole pipework and in surface treating facilities.

(2) Corrosion Inhibitors:
Aqueous acids are used to stimulate production from reservoirs. Such acids expose oil production systems to the possibility of corrosion. Thus corrosion inhibitors are required to protect the downhole pipework and
vessels of oil production facilities.

(3) Oxygen Scavengers:
Often used to mitigate corrosion problems in water injection systems, in hydrotesting and drilling.

(4) Biocides:
Bacterial growth in waters associated with crude oil production is controlled by the use of biocides. Biocides are water-soluble and removed with the water from crude.

(5) Emulsion Breakers:
Production of Oil usually involves the coproduction of large quantities of water. Natural surfactants present in the oil or water, other chemicals such as corrosion inhibitors combined with the shearing effect from
turbulent flow and pumps may create emulsions. Demulsifiers are used to resolve water-in-oil emulsions.

(6) Antifoam Agents:
Foaming problems occur in many oilfield processes. Problems occur when gas breaks out form crude oil in separators, or in gas processing plants.

(7) Drag reducing Agents:
High molecular weight oil-soluble polymeric compounds are added to crude oil pipeline fluids in order to enhance flow and minimize pressure drop. A long pipeline can have more then one injection point.

(8) Hydrate Inhibitors:
Gas hydrates are formed when water molecules crystallize around hydrocarbon molecules at certain pressure and temperature combinations. They can plug flowlines and damage process equipment. In addition to specific chemicals, methanol or glycols (MEG, DEG, TEG) may be used to prevent crystallization of the water molecules.

(9) Hydrogen Sulfide Scavengers:
Hydrogen sulfide in produced oil and gas poses safety and corrosion concerns. Scavengers bind the H2S in a form that is stable in the liquid phase. They can be added at oil production facilities or in transit in a pipeline or

(10) Mercaptan Scavengers:
Low molecular weight (C1-C3) mercaptans have offensive odors and are toxic. It is necessary to remove and neutralize them.
Mercaptan scavengers either oxidize the offending species or convert them to less volatile molecules.

(11) Paraffin Control Agents and Pour Point Depressants:
Crude oils may contain varying degrees of long chain paraffins or waxes that tend to form deposits if the oil is subjected to changes in temperature, pressure or other conditions.
Dispersants/detergents are used to remove deposits already formed and inhibitors to interfere with wax crystal growth and formation.

(12) Asphaltene Control Agents:
Asphaltenes can destabilize and precipitate out when temperature, pressure or oil composition changes. Chemicals are added to control asphaltene precipitation.

Offshore Petroleum Platforms

what are offshore platforms?

offshore platformOffshore structures are used worldwide for a variety of functions and in a variety of water depths, and environments. Since right selection of equipment, types of platforms and method of drilling and also right planning, design, fabrication, transportation, installation and commissioning of petroleum platforms, considering the water depth and environment conditions are very important, this post will present a general overview of these aspects. This post reviews the fundamentals behind all types of offshore structures (fixed or floating) and, in the case of fixed platforms, will cover applications of these principles. The overall objective is to provide a general understanding of different stages of design, construction, loadout, transportation and installation of offshore platforms.

Offshore platforms have many uses including oil exploration and production, navigation, ship loading and unloading, and to support bridges and causeways.
Offshore oil production is one of the most visible of these applications and represents a significant challenge to the design engineer. These offshore structures must function safely for design lifetimes of twenty-five years or more and are subject to very harsh marine environments. Some important design considerations are peak loads created by hurricane wind and waves, fatigue loads generated by waves over the platform lifetime and the motion of the platform. The platforms are sometimes subjected to strong currents which create loads on the mooring system
and can induce vortex shedding.

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Offshore platforms are huge steel or concrete structures used for the exploration and extraction of oil and gas from the earth’s crust. Offshore structures are designed for installation in the open sea, lakes, gulfs, etc., many kilometers from shorelines. These structures may be made of steel, reinforced concrete or a combination of both. The offshore oil and gas platforms are generally made of various grades of steel, from mild steel to high-strength steel, although some of the older structures were made of reinforced concrete.
Within the category of steel platforms, there are various types of structures, depending on their use and primarily on the water depth in which they will work.
Offshore platforms are very heavy and are among the tallest manmade structures on the earth. The oil and gas are separated at the platform and transported through pipelines or by tankers to shore.

offshore platforms

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Design of offshore fixed platforms

The most commonly used offshore platforms in the Gulf of Mexico, Nigeria, California shorelines and the Persian Gulf are template type platforms made of steel, and used for oil/gas exploration and production (Sadeghi 1989, 2001).
The design and analyses of these offshore structures must be made in accordance with recommendations published by the American Petroleum Institute (API).
The design and analysis of offshore platforms must be done taking into consideration many factors, including the following important parameters:
• Environmental (initial transportation, and in-place 100-year storm conditions)
• Soil characteristics
• Code requirements (e.g. American Institute of Steel Construction “AISC” codes)
• Intensity level of consequences of failure.
The entire design, installation, and operation must be approved by the client.

Environmental parameters

The design and analysis of fixed offshore platforms may be conducted in accordance with the API’s “Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms – Working Stress Design (API-RP-2AWSD)”.
The latest revision of API-RP-2A-WSD is the 21st edition dated December 2000. The API specifies minimum design criteria for a 100-year design storm.
Helicopter landing pads/decks on offshore platforms must conform to API RP-2L (latest edition being the 4th edition, dated May 1996).
Normally, for the analysis of offshore platforms, the environmental parameters include wave heights of as much as 21 meters (depending on the water depth) and wind velocities of 170 km/hr for Gulf of Mexico, coupled with tides of up to 4 m in shallow waters. The wave heights up to 12.2 meters and wind velocities up to 130 km/hr for the Persian Gulf, coupled with tides up to 3 m are considered in design of platforms (Sadeghi 2001).
The design wave height in the Southern Caspian Sea is about 19 m for a return period of 100 years, and for the North Sea is over 32 m depending on the location.
The API RP-2A also specifies that the lowest deck must maintain a minimum of 1.5 m air gap between the bottom of the deck beams and the wave crest during the maximum expected level of water considering the combination of wave height and tides.
The platform should resist the loads generated by the environmental conditions and loadout, transportation and installation loads plus other loads generated by onboard equipment.

A typical offshore structure supported by piles normally has a deck structure containing a Main Deck, a Cellar Deck, Sub-Cellar Deck and a Helideck. The deck structure is supported by deck legs connected to the top of the piles. The piles extend from above the Mean Low Water through the mudline and into the soil.
Underwater, the piles are contained inside the legs of a “jacket” structure which serves as bracing for the piles against lateral loads. The jacket may also serve as a template for the initial driving of the through leg piles (The piles may be driven through the inside of the legs of the jacket structure). In the case of using skirt piles.
the piles may be driven from outside of the legs of the jacket structure. The structural model file consists of:
• The type of analysis, the mudline elevation and water depth.
• Member sizes
• Joints definition.
• Soil data (i.e. mudmat bearing capacity, pile groups, T-Z, P-Y, Q-Z curve points).
• Plate groups.
• Joint coordinates.
• Marine growth input.
• Inertia and mass coefficients (CD and CM) input.
• Distributed load surface areas.
• Wind areas.
• Anode weights and locations.
• Appurtenances weights and locations
• Conductors and piles weight and location
• Grouting weight and locations
• Load cases include dead, live and environmental loading, crane loads, etc.

Any analysis of offshore platforms must also include the equipment weights and a maximum deck live loading (distributed area loading), dead loads in addition to the environmental loads mentioned above, and wind loads. Underwater, the analysis must also include marine growth as a natural means of enlargement of underwater
projected areas subject to wave and current forces.
The structural analysis will be a static linear analysis of the structure above the mudline combined with a static non-linear analysis of the soil with the piles.
Additionally, checks will be made for all tubular joint connections to analyze the strength of tubular joints against punching. The punching shear analysis is colloquially referred to as “joint can analysis”. The Unity Checks must not exceed 1.0.
All structural members will be chosen based on the results of the computer-aided in-place and the other above-mentioned analyses. The offshore platform designs normally use pipe or wide flange beams for all primary structural members.
Concurrently with the structural analysis the design team will start the development of construction drawings, which will incorporate all the dimensions and sizes optimized by the analyses and will also add construction details for the field erection, transportation, and installation of the structure.
The platforms must be capable of withstanding the most severe design loads and also of surviving a design lifetime of fatigue loading. The fatigue analysis is developed with input from a wave scatter diagram and from the natural dynamic response of the platform, and the stiffness of the pile caps at the mudline by applying Palmgeren-Miner formula (Sadeghi 2001). A detailed fatigue analysis should be performed to assess cumulative fatigue damage. The analysis required is a “spectral fatigue analysis” or simplified fatigue analysis according to API.
API allows a simplified fatigue analysis if the platform (API 1996):
• Is in less than 122 m (400 ft) water depth.
• Is constructed of ductile steel.
• Has redundant framing.
• Has natural periods less than 3 seconds.

1. Offshore Platform Design.
2. Installation of Petroleum Offshore Platform.

Gas–Oil Separators part. 2

Inlet Diverters
Inlet diverters are used to cause the initial bulk separation of liquid and gas. The most common type is the baffle plate diverter, which could be in the shape of a flat plate, a spherical dish, or a cone. Another type, is the
centrifugal diverter; it is more efficient but more expensive. The diverter provides a means to cause a sudden and rapid change of momentum (velocity and direction) of the entering fluid stream. This, along with the difference in densities of the liquid and gas, causes fluids separation.

Inlet Divertor

Wave Breakers
In long horizontal separators, waves may develop at the gas–liquid interface. This creates unsteady fluctuations in the liquid level and would negatively affect the performance of the liquid level controller. To avoid this, wave breakers, which consist of vertical baffles installed perpendicular to the flow direction, are used.

Defoaming Plates
Depending on the type of oil and presence of impurities, foam may form at the gas–liquid interface. This results in the following serious operational problems:
1. Foam will occupy a large space in the separator that otherwise would be available for the separation process; therefore, the separator efficiency will be reduced unless the separator is oversized to allow for the presence of foam.
2. The foam, having a density between that of the liquid and gas, will disrupt the operation of the level controller.
3. If the volume of the foam grows, it will be entrained in the gas and liquid streams exiting the separator; thus, the separation process will be ineffective. The entrainment of liquid with the exiting gas is known as liquid carryover. Liquid carryover could also occur as a result of a normally high liquid level, a plugged liquid outlet, or an undersized separator with regard to liquid capacity. The entrainment of gas in the exiting liquid is known as gas blowby. This could also occur as a result of a normally low liquid level, an undersized separator with regard to gas capacity,
or formation of a vortex at the liquid outlet.
Foaming problems may be effectively alleviated by the installation of defoaming plates within the separator. Defoaming plates are basically a series of inclined closely spaced parallel plates. The flow of the foam through such plates results in the coalescence of bubbles and separation of the liquid from the gas.
In some situations, special chemicals known as foam depressants may be added to the fluid mixture to solve foaming problems. The cost of such chemicals could, however, become prohibitive when handling high production rates.


Vortex Breaker
A vortex breaker, similar in shape to those used in bathroom sink drains, is normally installed on the liquid outlet to prevent formation of a vortex when the liquid outlet valve is open. The formation of a vortex at the liquid outlet may result in withdrawal and entrainment of gas with the exiting liquid (gas blowby).

Sand Jets and Drains
As explained previously , formation sand may be produced with the fluids. Some of this sand will settle and accumulate at the bottom of the separator. This takes up separator volume and disrupts the efficiency of
separation. In such cases, vertical separators will be preferred over horizontal separators. However, when horizontal separators are needed, the separator should be equipped with sand jets and drains along the bottom of the separator. Normally, produced water is injected though the jets to fluidize the accumulated sand, which is then removed through the drains.

Design Principles and Sizing of Gas–Oil Separators
In this section, some basic assumptions and fundamentals used in sizing gas–oil separators are presented first. Next, the equations used for designing vertical and horizontal separators are derived. This will imply finding the diameter and length of a separator for given conditions of oil and gas flow rates, or vice versa.

1. No oil foaming takes place during the gas–oil separation (otherwise retention time has to be drastically increased as explained earlier).
2. The cloud point of the oil and the hydrate point of the gas are below the operating temperature.
3. The smallest separable liquid drops are spherical ones having a diameter of 100 mm.
4. Liquid carryover with the separated gas does not exceed 0.10 gallon/MMSCF (M¼1000).

1. The difference in densities between liquid and gas is taken as a basis for sizing the gas capacity of the separator .
2. A normal liquid (oil) retention time for gas to separate from oil is between 30 s and 3 min. Under foaming conditions, more time is considered (5–20 min). Retention time is known also as the residence time (¼V/Q, where V is the volume of vessel occupied by oil and Q is the liquid flow rate).
3. In the gravity settling section, liquid drops will settle at a terminal velocity that is reached when the gravity force Fg acting on the oil drop balances the drag force (Fd) exerted by the surrounding fluid or gas.
4. For vertical separators, liquid droplets (oil) separate by settling downward against an up-flowing gas stream; for horizontal ones, liquid droplets assume a trajectory like path while it flows through the vessel (the trajectory of a bullet fired from a gun).
5. For vertical separators, the gas capacity is proportional to the cross-sectional area of the separator, whereas for
horizontal separators, gas capacity is proportional to area of disengagement (LD) (i.e., length  diameter).

Settling of Oil Droplets
In separating oil droplets from the gas in the gravity settling section of a separator, a relative motion exists between the particle, which is the oil droplet, and the surrounding fluid, which is the gas. An oil droplet, being much greater in density than the gas, tends to move vertically downward under the gravitational or buoyant force, Fg.
The fluid (gas), on the other hand, exerts a drag force, Fd, on the oil droplet in the opposite direction. The oil droplet will accelerate until the frictional resistance of the fluid drag force, Fd, approaches and balances Fg; and, thereafter, the oil droplet continues to fall at a constant velocity known as the settling or terminal velocity.

read also:
 Gas – Oil Separators Part.1
2-phase Gas Oil Separation

1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook. 

Gas–Oil Separators part. 1

Commercial Types of Gas–Oil Separator

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.


Test Separators

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.

Modern GOSPs
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.

horizontal separator internal design
Horizontal Separator

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.

التصميم الداخلي لعازلة أفقية
vertical separator internal design

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
4. Deemulsification
5. Washing
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.

Mist Extractor

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:

mist extractor mist extractor

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.

read also:
 Gas – Oil Separators Part.2
2-phase Gas Oil Separation

1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.

Two-Phase Gas–Oil Separation

At the high pressure existing at the bottom of the producing well, crude oil contains great quantities of dissolved gases. When crude oil is brought to the surface, it is at a much lower pressure. Consequently, the gases that were dissolved in it at the higher pressure tend to come out from the liquid. Some means must be provided to separate the gas from oil without losing too much oil.

Vertical SeparatorIn general, well effluents flowing from producing wells come out in two phases: vapor and liquid under a relatively high pressure. The fluid emerges as a mixture of crude oil and gas that is partly free and partly in solution. Fluid pressure should be lowered and its velocity should be reduced in order to separate the oil and obtain it in a stable form. This is usually done by admitting the well fluid into a gas–oil separator plant (GOSP) through which the pressure of the gas–oil mixture is successively reduced to atmospheric pressure in a few stages.
Upon decreasing the pressure in the GOSP, some of the lighter and more valuable hydrocarbon components that belong to oil will be unavoidably lost along with the gas into the vapor phase. This puts the gas–oil separation step as the initial one in the series of field treatment operations of crude oil. Here, the primary objective is to allow most of the gas to free itself from these valuable hydrocarbons, hence increasing the recovery of crude oil.
Crude oil as produced at the wellhead varies considerably from field to field due not only to its physical characteristics but also to the amount of gas and salt water it contains. In some fields, no salt water will flow into the well from the reservoir along with the produced oil. This is the case we are considering in this chapter, where it is only necessary to separate the gas from the oil; (i.e., two-phase separation).

When, on the other hand, salt water is produced with the oil, it is then essential to use three-phase separators, oil-field separators can be classified into two types based on the number of phases to separate:
1. Two-phase separators, which are used to separate gas from oil in oil fields, or gas from water for gas fields.
2. Three-phase separators, which are used to separate the gas from the liquid phase, and water from oil.
Oil from each producing well is conveyed from the wellhead to a gathering center through a flow line. The gathering center, usually located in some central location within the field, will handle the production from several wells in order to process the produced oil–gas mixture.
Separation of the oil phase and the gas phase enables the handling, metering, and processing of each phase independently, hence producing marketable products.



In order to understand the theory underlying the separation of well effluent hydrocarbon mixtures into a gas stream and oil product, it is assumed that such mixtures contain essentially three main groups of hydrocarbon,
1. Light group, which consists of CH4 (methane) and C2H6 (ethane)
2. Intermediate group, which consists of two subgroups: the propane/butane (C3H8/C4H10) group and the pentane/hexane (C5H12/C6H14) group.
3. Heavy group, which is the bulk of crude oil and is identified as C7H16.
In carrying out the gas–oil separation process, the main target is to try to achieve the following objectives:
1. Separate the C1 and C2 light gases from oil
2. Maximize the recovery of heavy components of the intermediate group in crude oil
3. Save the heavy group components in liquid product To accomplish these objectives, some hydrocarbons of the
intermediate group are unavoidably lost in the gas stream. In order to minimize this loss and maximize liquid recovery, two methods for the mechanics of separation are compared:
1. Differential or enhanced separation
2. Flash or equilibrium separation
In differential separation, light gases (light group) are gradually and almost completely separated from oil in a series of stages, as the total pressure on the well-effluent mixture is reduced. Differential separation is characterized by the fact that light gases are separated as soon as they are liberated (due to reduction in pressure). In other words, light components do not come into contact with heavier hydrocarbons; instead, they find their way out.
For flash separation, on the other hand, gases liberated from the oil are kept in intimate contact with the liquid phase. As a result, thermodynamic equilibrium is established between the two phases and separation takes place at the required pressure.
Comparing the two methods, one finds that in differential separation, the yield of heavy hydrocarbons (intermediate and heavy groups) is maximized and oil-volume shrinkage experienced by crude oil in the storage tank is minimized. This could be explained by the fact that separation of most of the light gases take place at the earlier high-pressure
stages; hence, the opportunity of loosing heavy components with the light gases in low-pressure stages is greatly minimized. As a result, it may be concluded that flash separation is inferior to differential separation because the former experiences greater losses of heavy hydrocarbons that are carried away with the light gases due to equilibrium conditions.
Nevertheless, commercial separation based on the differential concept is very costly and is not a practical approach because of the many stages required. This would rule out differential separation, leaving the flash process as the only viable scheme to affect gas–oil separation using a small number of stages, a close approach to
differential separation is reached by using four to five flash separation stages.

The conventional separator is the very first vessel through which the welleffluent mixture flows. In some special cases, other equipment (heaters, water knockout drums) may be installed upstream of the separator.
The essential characteristics of the conventional separator are the following:
1. It causes a decrease in the flow velocity, permitting separation of gas and liquid by gravity.
2. It always operates at a temperature above the hydrate point of the flowing gas.
The choice of a separator for the processing of gas–oil mixtures containing water or without water under a given operating conditions and for a specific application normally takes place guided by the general classification.

Functional Components of a Gas–Oil Separator

Regardless of their configuration, gas–oil separators usually consist of four functional sections:
1. Section A: Initial bulk separation of oil and gas takes place in this section. The entering fluid mixture hits the inlet diverter.
This causes a sudden change in momentum and, due to the gravity difference, results in bulk separation of the gas from the oil. The gas then flows through the top part of the separator and the oil through the lower part.
2. Section B: Gravity settling and separation is accomplished in this section of the separator. Because of the substantial reduction in gas velocity and the density difference, oil droplets settle and separate from the gas.
3. Section C: Known as the mist extraction section, it is capable of removing the very fine oil droplets which did not settle in the gravity settling section from the gas stream.
4. Section D: This is known as the liquid sump or liquid collection section. Its main function is collecting the oil and retaining it for a sufficient time to reach equilibrium with the gas before it is discharged from the separator.

In separating the gas from oil, a mechanical mechanism could be suggested which implies the following two

(a) To separate oil from gas: Here, we are concerned primarily with recovering as much oil as we can from the gas stream. Density difference or gravity differential is responsible for this separation. At the separator’s operating condition of high pressure, this difference in density between oil and gas becomes small (gas law). Oil is about eight times as dense as the gas. This could be a sufficient driving force for the liquid particles to separate and settle down. This is especially true for large-sized particles, having diameter of 100 mm or more. For smaller ones,
mist extractors are needed.

(b) To remove gas from oil: The objective here is to recover and collect any non solution gas that may be entrained or ‘‘locked’’ in the oil. Recommended methods to achieve this are settling, agitation, and applying heat and chemicals.

read also:
Gas – Oil Separators part. 1
 Gas – Oil Separators Part.2

1. Petroleum and Gas Field Processing – H. K. Abdel-Aal and Mohamed Eggour.
2. Oil & Gas Production Handbook.

Oil Refinery Processes

Process Objective:
To distill and separate valuable distillates (naphtha, kerosene,diesel) and atmospheric gas oil (AGO) from the crude feedstock.


Primary Process Technique:
Complex distillation

Process steps:
–Preheat the crude feed utilizing recovered heat from the product streams
–Desalt and dehydrate the crude using electrostatic enhanced liquid/liquid separation (Desalter)
–Heat the crude to the desired temperature using fired heaters
–Flash the crude in the atmospheric distillation column
–Utilize pumparoundcooling loops to create internal liquid reflux
–Product draws are on the top, sides, and bottom.

Typical Yields and Dispositions:

product & Yield in wt% of Crude

Light Ends 2.3
Light Naphtha  6.3
Medium Naphtha 14.4
Heavy Naphtha 9.4
Kerosene  9.9
Atmospheric Gas Oil 15.1
Reduced Crude 42.6

Vacuum Distillation Unit VDU Process
Process Objective:
To recover valuable gas oils from reduced crude via vacuum distillation.
Primary Process Technique:
Reduce the hydrocarbon partial pressure via vacuum and stripping steam.
Process steps:
–Heat the reduced crude to the desired temperature using fired heaters
–Flash the reduced crude in the vacuum distillation column
–Utilize pumparoundcooling loops to create internal liquid reflux
–Product draws are top, sides, and bottom.

Vacuum Distillation Unit (VDU) Process Schematic


Typical Yields and Dispositions:

product & Yield in wt% of Crude

Light Ends <1
Light VGO 17.6
Heavy VGO 12.7
Vacuum residue (Resid) 12.3

Delayed Coking Process:

Process Objective:
To convert low value residto valuable products (naphtha and diesel) and cokergas oil.
Primary Process Technique:
Thermo cracking increases H/C ratio by carbon rejection in a semi-batch process.
Process steps:
–Preheat residfeed and provide primary condensing of coke drum vapors by introducing the feed to the bottom of the main fractionator
–Heat the coke drum feed by fired heaters
–Flash superheated feed in a large coke drum where the coke remains and vapors leave the top and goes back to the fractionator
–Off-line coke drum is drilled and the petroleum coke is removed via hydrojetting.

Delayed Coking Process Schematic

Delayed Coking process

Fluidic Coking Process

Process Objective:
–To convert low value residto valuable products (naphtha and diesel) and coker gas oil.
Primary Process Technique:
–Thermocracking increases H/C ratio by carbon rejection in a continuous process.
Process steps:
–Preheat residfeed, scrub coke particles, and provide primary condensing of reactor vapors by introducing the feed to the scrubber
–Residis atomized into a fluid coke bed and thermocracking occurs on the particle surface
–Coke particles leaving the reactor are steam stripped to remove remaining liquid hydrocarbons
–Substoichiometricair is introduced to burner to burn some of the coke and provide the necessary heat for the reactor
–Reactor vapors leave the scrubber and go to the fractionator.

Delayed & Fluid Coking Processes
Typical Yields and Dispositions

Light Ends 12.5 –20
Naphtha 10 –15
Light Coker Gas Oil 18 –24
Heavy Coker Gas Oil 30 –40
Pet. Coke 20 -35

 Fluidic Catalytic Cracking FCC Process

Process Objective:
–To convert low value gas oils to valuable products (naphtha and diesel) and slurry oil.
Primary Process Technique:
–Catalytic cracking increases H/C ratio by carbon rejection in a continuous process.
Process steps:
–Gas oil feed is dispersed into the bottom of the riser using steam
–Thermal cracking occurs on the surface of the catalyst
–Disengaging drum separates spent catalyst from product vapors
–Steam strips residue hydrocarbons from spent catalyst
–Air burns away the carbon film from the catalyst in either a “partial-burn”or “full-burn”mode of operation
–Regenerated catalyst enters bottom of riser-reactor.


Typical Yields and Dispositions:

Light Ends 16.5 – 22
Naphtha 44 – 56
Light Cycle Oil  13 – 20
Medium Cycle Oil 10 – 26
Slurry Oil 4 – 12
Coke 5 – 6

 HF Alkylation Process

Process Objective:
–To combine light olefins (propylene and butylene) with isobutaneto form a high octane gasoline (alkylate).
Primary Process Technique:
–Alkylationoccurs in the presence of a highly acidic catalyst (hydroflouricacid or sulfuric acid).
Process steps:
–Olefins from FCC are combined with IsoButaneand fed to the HF Reactor where alkylation occurs
–Acid settler separates the free HF from the hydrocarbons and recycles the acid back to the reactor
–A portion of the HF is regenerated to remove acid oils formed byfeed contaminants or hydrocarbon polymerization
–Hydrocarbons from settler go to the DeIsobutanizerfor fractionating the propane and isobutane from the n-butane and alkylate
–Propane is then fractionated from the isobutane; propane as a product and the isobutaneto be recycled to the reactor
–N-Butane and alkylateare deflourinatedin a bed of solid adsorbent and fractionated as separate products.

Hydrotreating Process

Naphtha Hydrotreating
–Primary objective is to remove sulfur contaminant for downstream processes; typically < 1 wppm
Gasoline Hydrotreating
–Sulfur removal from gasoline blending components to meet recent clean fuels specifications
Mid-Distillate Hydrotreating
–Sulfur removal from kerosene for home heating
–Convert kerosene to jet via mild aromatic saturation
–Remove sulfur from diesel for clean fuels
Ultra-low sulfur diesel requirements are leading to major unit revamps
FCC Feed Pretreating
–Nitrogen removal for better FCC catalyst activity
–Sulfur removal for SOx reduction in the flue gas and easier post-FCC treatment
–Aromatic saturation improves FCC feed “crackability”
–Improved H/C ratios increase FCC capacity and conversion.

Hydrocracking Process
Process Objective:
–To remove feed contaminants (nitrogen, sulfur, metals) and to convert low value gas oils to valuable products (naphtha, middle distillates, and ultra-clean lube base stocks).
Primary Process Technique:
–Hydrogenation occurs in fixed hydrotreating catalyst beds to improve H/C ratios and to remove sulfur, nitrogen, and metals. This is followed byone or more reactors with fixed hydrocracking catalyst beds to dealkylatearomatic rings, open naphthenerings, and hydrocrack paraffin chains.
Process steps:
–Preheated feed is mixed with hot hydrogen and passes through a multi-bed reactor with interstagehydrogen quenches for hydrotreating
–Hydrotreatedfeed is mixed with additional hot hydrogen and passes through amulti-bed reactor with quenches for first pass hydrocracking
–Reactor effluents are combined and pass through high and low pressure separators and are fed to the fractionatorwhere valuable products are drawn from the top, sides, and bottom
–Fractionator bottoms may be recycled to a second pass hydrocrackerfor additional conversion all the way up to full conversion.

1. Fundamentals of Oil Refining.
2. Oil Refinery Processes

Oilfield Jobs in USA

Oil and Gas Jobs in United States:

Materials Coordinator I:

 North Dakota – Supply Chain/Procurement > Materials Logistics
Salary: $29 per hour, Benefits: yes
Job Title: SC- Materials Management – Materials Coordinator I
Work Location: Arnegard, ND
Start/End Dates: 3/3/2017 – 3/2/2018
Assignment Scope: Responsible for ensuring on time delivery of materials in accordance with contract terms and conditions.
Expires: Fri 14 Apr at 16:54

Project Manager – LNG

Texas – Long Term Contract / Office
Oscar Energy has been tasked searching for an LNG Project manager to work with our client who is an LNG development company based in downtown Houston.
Expires: Fri 14 Apr at 16:00


Onshore Permian – Texas – Immediate Start – Multinational Service Company
Are you an experienced CHIEF RIG MECHANIC – Looking to return to work in the Permian Basin

We are looking for a large number of CHIEF RIG MECHANICS to start work immediately.
Expires: Thu 13 Apr at 16:00

Drilling > Derrickman – Texas

Salary: Competitive
FLOORHAND – Onshore Permian – Texas – Immediate Start – Multinational Service Company
Are you an experienced Floor Hand – Looking to return to work in the Permian Basin
We are looking for a large number of FLOOR HANDS to start work immediately.
Expires: Thu 13 Apr at 12:28

Heavy Equipment Operator

North Dakota
Salary: Pay DOE, 100+ Hours/Week, $1,350/monthly Housing Allowance, 15 Days on / 6 Days Off
The Operator – Fracturing is an entry level position within Fracturing field operations for inpiduals with prior commercial driving experience and credentialing and is considered a training position for future Field Operator positions. The Operator – Fracturing will be responsible for learning how to drive, operate, and maintain Fracturing Services equipment such as the Iron Truck, Sand Truck, Belt Assist Sand Storage (BASS) and Auxiliary Sand Trucks and Equipment.
Expires: Sun 14 May at 19:54

Well Site Manager – Houston, USA

alary: USD125000 – USD150000 per annum
Well Site Manager – – Immediate Start – Texas – Onshore Experience Essential – Multinational Service Company
We are looking for a large number of Well Site Managers to start work in West Texas Immediately.
Expires: Wed 12 Apr at 9:59

Rig Manager – Houston, USA

Salary: USD125000 – USD150000 per annum
RIG MANAGER – Onshore Permian – Texas – Immediate Start – Multinational Service Company.
Expires: Wed 12 Apr at 9:06

IT/Communications > Database Administration

Salary: $130000 – $170000 per annum, Benefits: Full
This opportunity will be based in the corporate offices of an Engineering, Procurement & Construction company in the energy corridor, Houston.
Expires: Tue 11 Apr at 15:27

Project Manager

PROJECT MANAGER required by our Client, an International EPC Contractor, to be assigned on a Permanent basis, located in Denver, Colorado.

Expires: Fri 07 Apr at 9:00

HVAC Mechanical Engineer

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Detection of Oil Spills

Oil Spills

oil spillSpecial instruments are sometimes required to detect an oil spill, especially if the slick is very thin or not clearly visible. For example, if a spill occurs at night, in ice, or among weeds, the oil slick must be detected and tracked using instruments onboard aircraft, satellites, or spacecraft. This technology is known as remote sensing.
There are also surface technologies available to detect and track oil slicks. In addition, samples of the oil must often be obtained and analyzed to determine the oil’s properties, its degree of weathering, its source, or its potential impact on the environment. This analysis, as well as tracking and remote sensing technologies, are
discussed in this article.

In the past, when an oil spill occurred, the location and extent of the spill, the potential behaviour of the oil, and its impact on the environment were often not immediately known. Today, technology is available to provide much of this information.
Laboratory analysis can provide information to help identify an oil if its source is unknown and a sample is available. With a sample of the source oil, the degree of weathering and the amount of evaporation or biodegradation can be determined for the spilled oil. Through laboratory analysis, the more-toxic compounds in the oil can be measured and the relative toxicity of the oil at various stages of the spill can be determined. This is valuable information to have as the spill progresses.

Taking a sample of oil and then transporting it to a laboratory for subsequent analysis is common practice. While there are many procedures for taking oil samples, it is always important to ensure that the oil is not tainted from contact with other materials and that the sample bottles are pre-cleaned with solvents, such as hexane,
that are suitable for the oil.
The simplest and most common form of analysis is to measure how much oil is in a water, soil, or sediment sample. Such analysis results in a value known as total petroleum hydrocarbons (TPH). The TPH measurement can be obtained in many ways, including extracting the soil, or evaporating a solvent such as hexane and measuring the weight of the residue that is presumed to be oil.
The oil can also be extracted from water using an oil-absorbing and waterrepelling solid. The oil is then analyzed from this substrate by a variety of means, including measuring the amount of light absorbed in certain selected narrow bands.
Still another method is to use enzymes that are selectively affected by some of the oil’s components. A test kit that uses colour to indicate the effect of the oil on the enzymes is available.
A more sophisticated form of analysis is to use a gas chromatograph (GC). A small sample of the oil extract, often in hexane, and a carrier gas, usually helium, are passed through a small glass capillary. The glass column is coated with absorbing materials and, as the various components of the oil have varying rates of adhesion, the oil separates as these components are absorbed at different rates onto the column walls. The gases then pass through a sensitive detector. The system is calibrated by passing known amounts of standard materials through the unit. The amount of many individual components in the oil is thereby measured. The components that pass through the detector can also be totalled and a TPH value determined. While it is highly accurate, this value does not include resins, asphaltenes, and some other components of the oil with higher molecular weight that do not pass through the

One type of detector used on a gas chromatogram is a mass spectrometer (MS). The method is usually called GC-MS and can be used to quantify and identify many components in oil. The mass spectrometer provides information about the structure of the substance so that each peak in the chromatogram can be more positively identified. This information can then be used to predict how long the oil has been in the environment and what percentage of it has evaporated or biodegraded. This is possible because some of the components in oils, particularly crude oils, are very
resistant to biodegradation, while others are resistant to evaporation. This difference in the distribution of components then allows the degree of weathering of the oil to be measured. The same technique can be used to “fingerprint” an oil and positively identify its source. Certain compounds are consistently distributed in oil, regardless
of weathering, and these are used to identify the specific type of oil.

Analysis performed in the field is faster and more economical than analysis done in a laboratory. As analytical techniques are constantly improving and lighter and more portable equipment is being developed, more analytical work can be carried out directly in the field. Test methods are now available for measuring physical properties of oil such as viscosity, density, and even flash point in the field. Test kits have also been developed that can measure total petroleum hydrocarbons directly in the field. While these test kits are less accurate than laboratory methods, they are a rapid screening tool that minimizes laboratory analysis and may provide adequate data for making response decisions.
Oil Spill Detection and Tracking Buoys and Systems
As oil spills frequently occur at moorings and docks, buoys and fixed-point monitoring systems have been developed to ensure rapid response at these sites.
These systems detect the oil on water and transmit a radio signal to an oil spill response agency.

is one method used to detect oil in these systems. An ultraviolet light is focused on the water surface and any oil that is present fluoresces, or absorbs the ultraviolet light and re-emits it as visible light. This fluorescing phenomenon is relatively unique to oil and provides a positive detection mechanism.

In another detection method, an oil sorbent is used that changes in physical properties when it absorbs oil and thus triggers a device. An example of this would be a sorbent that loses it strength when oil is absorbed. The sorbent is placed in contact with a spring and a switch, which is activated when oil enters the sorbent.
This type of device is not effective for fast response. Other detection units are triggered by the differential light reflection or absorption properties of oil.As these systems monitor a specific small area of water, they must be located where a spill would be likely to enter that area. It is difficult to determine this entry point in most situations. Furthermore, technologies available today are not sensitive to quantities of oil released and thus may be triggered by very small amounts of oil. For these reasons, these systems are not used extensively.

As an oil spill moves with the winds and surface currents, the slick or portions of it may move and responders may not always know its position, especially in darkness or fog. Buoys have been developed that move on the water in a manner similar to oil. These buoys transmit a position signal directly to receivers located on aircraft or ships or to a satellite that corresponds to the position of the oil slick.
Some of these buoys receive Global Positioning System (GPS) data from satellites and transmit this with the signal. The position of the spill can then be determined using a remote receiver. For this type of device to be effective, however, the buoy must respond to both the wind and surface currents in the same way as the oil would.
Although this precision in response is difficult to achieve, devices are available that can successfully track a range of crude oils and Bunker C.

Visual Surveillance
Oil spills are often located and surveyed from helicopters or aircraft using only human vision. There are some conditions, however, such as fog and darkness, in which oil on the surface cannot be seen. Very thin oil sheens are also difficult to detect as is oil viewed from an oblique angle (less than 45°) especially in misty or other conditions that limit vision. Oil can also be difficult to see in high seas and among debris or weeds and it can blend into dark backgrounds, such as water, soil,
or shorelines. Oil spill

In addition, many naturally occurring substances or phenomena can be mistaken for oil. These include weeds and sunken kelp beds, whale and fish sperm, biogenic or natural oils such as from plants, glacial flour (finely ground mineral material, usually from glaciers), sea spume (organic material), wave shadows, sun glint and wind sheens on water, and oceanic and riverine fronts where two different bodies of water meet, such as a river entering another body of water.
A very thin oil sheen as it appears on water is shown in the above Figure. This figure also shows the thickness and amount of oil that could be present under such circumstances.
Remote sensing of oil involves the use of sensors other than human vision to detect or map oil spills. As already noted, oil often cannot be detected in certain conditions. Remote sensing provides a timely means to map out the locations and approximate concentrations of very large spills in many conditions. Remote sensing is usually carried out with instruments onboard aircraft or by satellite. While many sensors have been developed for a variety of environmental applications, only a few are useful for oil spill work. Remote sensing of oil on land is particularly limited and only one or two sensors are useful.

Visual and Ultraviolet Sensors
Many devices employing the visible spectrum, including the conventional video camera, are available at a reasonable cost. As these devices are subject to the same interferences as visual surveillance, they are used primarily to document the spill or to provide a frame of reference for other sensors. A sub-set of sensors operating in the ultraviolet spectrum may be useful for mapping out a very thin sheen.

Infrared Sensors
Thick oil on water absorbs infrared radiation from the sun and thus appears in infrared data as hot on a cold ocean surface. Unfortunately, many other false targets such as weeds, biogenic oils, debris, and oceanic and riverine fronts can interfere with oil detection. The advantage of infrared sensors over visual sensors is that they give information about relative thickness since only thicker slicks, probably greater than 100 μ m, show up in the infrared.
Infrared images are sometimes combined with ultraviolet images, which show the thin oil sheens, to yield a relative thickness map of an oil spill. This is referred to as an IR/UV overlay map. Infrared imagery also has some use at night since the oil appears “colder” than the surrounding sea. The oil is not detected at night in the infrared as it is during the day.
Infrared sensors are relatively inexpensive and widely used for supporting cleanup operations and directing cleanup crews to thicker portions of an oil spill.
They are also often used on cleanup vessels. The oblique view from a ship’s mast is often sufficient to provide useful information on where to steer the vessel for best oil recovery over a short range.

Laser Fluorosensors
Oils that contain aromatic compounds will absorb ultraviolet light and give off visible light in response. Since very few other compounds respond in this way, this can be used as a positive method of detecting oil at sea or on land. Laser fluorosensors use a laser in the ultraviolet spectrum to trigger this fluorescing phenomenon and a sensitive light-detection system to provide an oil-specific detection tool. There is also some information in the visible light return that can be used to determine whether the oil is a light or heavy oil or a lubricating oil. Laser fluorosensors are the most powerful remote sensing tools available because they are subject to very few interferences. Laser fluorosensors work equally well on water and on land and are the only reliable means of detecting oil in certain ice and snow situations. Disadvantages include the high cost of these sensors and their large size and weight.
Passive Microwave Sensors The passive microwave sensor detects natural background microwave radiation.
Oil slicks on water absorb some of this signal in proportion to their thickness. While this cannot be used to measure thickness absolutely, it can yield a measure of relative thickness. The advantage of this sensor is that it can detect oil through fog and in darkness. The disadvantages are the poor spatial resolution and relatively
high cost.

Thickness Sensors
Some types of sensors can be used to measure the thickness of an oil slick. For example, the passive microwave sensor can be calibrated to measure the relative thickness of an oil slick. Absolute thickness cannot be measured for the following reasons: many other factors such as atmospheric conditions also change the radiation levels; the signal changes in cyclical fashion with spill thickness; and the signal must be averaged over a relatively wide area and the slick can change throughout this area.
The infrared sensor also measures only relative thickness. Thick oil appears hotter than the surrounding water during daytime. While the degree of brightness of the infrared signal changes little with thickness, some systems have been adjusted to yield two levels of thickness. A third thickness level on the thinner outer edges of fresh slicks shows up “colder” in the infrared as a result of light interference.
Sensors using lasers to send sound waves through oil can measure absolute oil thickness. The time it takes the sound waves to travel through the oil changes little with the type of oil and thus the measurement of this travel time yields a reliable measurement of the oil’s thickness. This type of sensor is large and heavy and is still considered experimental.
As oil on the sea calms smaller waves (on the order of a few centimetres in length), radar can detect oil on the sea as a calm area. The technique is highly prone to false targets, however, and is limited to a narrow range of wind speeds (approximately 2 to 6 m/s). At winds below this, there are not enough small waves to yield a difference between the oiled area and the sea. At higher winds, the waves can propagate through the oil and the radar may not be able to “see” into the troughs between the waves. Radar is not useful near coastlines or between head lands because the wind “shadows” look like oil. There are also many natural calms on the oceans that can resemble oil. Despite its large size and expense, radar equipment is particularly well suited for searches of large areas and for work at night or in foggy or other bad weather conditions

While many satellites provide images in the visible spectrum, oil cannot be seen in these images unless the spill is very large or rare sea conditions are prevalent that provide a contrast to the oil. Oil has no spectral characteristics that allow it to be enhanced from the background.
Several radar satellites are now available that operate in the same manner as airborne radar and share their many limitations. Despite these limitations, radar imagery from satellite is particularly useful for mapping large oil spills. Arrangements to provide the data within a few hours are possible, making this a useful option.

Geologic Classification of Petroleum Reservoirs


Petroleum reservoirs exist in many different sizes and shapes of geologic structures. It is usually convenient to classify the reservoirs according to the conditions of their formation as follows:

A reservoir formed by folding of rock layers.
Figure 1

1. Dome-Shaped and Anticline Reservoirs:

These reservoirs are formed by the folding of the rock layers as shown in Figure 1. The dome is circular in outline, and the anticline is long and narrow. Oil and/or gas moved or migrated upward through the porous strata where it was trapped by the sealing cap rock and the shape of the structure.


2. Faulted Reservoirs:

A cross section of a faulted reservoir.
Figure 2

These reservoirs are formed by shearing and offsetting of the strata (faulting), as shown in Figure 2. The movement of the nonporous rock opposite the porous formation containing the oil/gas creates the sealing. The tilt of the petroleum-bearing rock and the faulting trap the oil/gas in the reservoir.



3. Salt-Dome Reservoirs:

Section in a salt-dome structure
figure 3

This type of reservoir structure, which
takes the shape of a dome, was formed due to the upward
movement of large, impermeable salt dome that deformed and
lifted the overlying layers of rock. As shown in Figure 3,
petroleum is trapped between the cap rock and an underlying
impermeable rock layer, or between two impermeable layers of
rock and the salt dome.



4. Unconformities:

A reservoir formed by unconformity.
figure 4

This type of reservoir structure, shown in Figure 4, was formed as a result of an unconformity where the
impermeable cap rock was laid down across the cutoff surfaces of the lower beds.




5. Lense-Type Reservoirs:

In this type of reservoir, the petroleum bearing porous formation is sealed by the surrounding, nonporous formation. Irregular deposition of sediments and shale at the time the formation was laid down is the probable cause for this abrupt change in formation porosity.

6. Combination Reservoirs:

In this case, combinations of folding, faulting, abrupt changes in porosity, or other conditions that create the trap, from this common type of reservoir.

Reservoir Drive Mechanisms
At the time oil was forming and accumulating in the reservoir, the pressure energy of the associated gas and water was also stored. When a well is drilled through the reservoir and the pressure in the well is made to be lower than the pressure in the oil formation, it is that energy of the gas, or the water, or both that would displace the oil from the formation into the well and lift it up to the surface. Therefore, another way of classifying petroleum reservoirs,
which is of interest to reservoir and production engineers, is to characterize the reservoir according to the production (drive) mechanism responsible for displacing the oil from the formation into the wellbore and up to the surface. There are three main drive mechanisms:

I. Solution-Gas-Drive Reservoirs:
Depending on the reservoir pressure and temperature, the oil in the reservoir would have varying amounts of gas dissolved within the oil (solution gas).
Solution gas would evolve out of the oil only if the pressure is lowered below a certain value, known as the bubble point pressure, which is a property of the oil. When a well is drilled through the reservoir and the pressure conditions are controlled to create a pressure that is lower than the bubble point pressure, the liberated gas expands and drives the oil out of the formation and assists in lifting it to the surface.
Reservoirs with the energy of the escaping and expanding dissolved gas as the only source of energy are called solution-gas-drive reservoirs.
This drive mechanism is the least effective of all drive mechanisms; it generally yields recoveries between 15% and
25% of the oil in the reservoir.

II. Gas-Cap-Drive Reservoirs:
Many reservoirs have free gas existing as a gas cap above the oil. The formation of this gas cap was due to the presence of a larger amount of gas than could be dissolved in the oil at the pressure and temperature of the reservoir. The excess gas is segregated by gravity to occupy the top portion of the reservoir.
In such a reservoirs, the oil is produced by the expansion of the gas in the gas cap, which pushes the oil downward and fills the pore spaces formerly occupied by the produced oil. In most cases, however, solution gas is also
contributing to the drive of the oil out of the formation.
Under favorable conditions, some of the solution gas may move upward into the gas cap and, thus, enlarge the gas cap and conserves its energy. Reservoirs produced by the expansion of the gas cap are known as Gas-cap-drive
reservoirs. This drive is more efficient than the solution-gas drive and could yield recoveries between 25% and 50% of the original oil in the reservoir.

III. Water-Drive Reservoirs:
Many other reservoirs exist as huge, continuous, porous formations with the oil/gas occupying only a small portion of the formation. In such cases, the vast formation below the oil/gas is saturated with salt water at very high pressure. When oil/gas is produced, by lowering the pressure in the well opposite the petroleum formation, the salt
water expands and moves upward, pushing the oil/gas out of the formation and occupying the pore spaces vacated by the produced oil/gas. The movement of the water to displace the oil/gas retards the decline in oil, or gas pressure, and conserves the expansive energy of the hydrocarbons.
Reservoirs produced by the expansion and movement of the salt water below the oil/gas are known as water-drive
reservoirs. This is the most efficient drive mechanism; it could yield recoveries up to 50% of the original oil.

Petroleum and Natural Gas Field Processing
 -H. K. Abdel-Aal and Mohamed Aggour

Acidizing Concepts

Acid Types
acidizingAlthough many acid compounds are available to the oil industry, only the following types have been proven economically effective in oil well stimulation:
Inorganic Acids (Strong).
· Hydrochloric Acid (HCl).
· Hydrofluoric Acid (HCl:HF).
Other inorganic acids include Sulphamic, Sulphuric and Nitric acids.
Organic Acids (Weak).
· Acetic Acid and Glacial Acetic Acid.
· Acetic Anhydride.
· Citric Acid.
· Formic Acid.

Inorganic Acids
Hydrochloric Acid (HCl).
Hydrochloric acid is an inorganic acid and is the most commonly used acid in oil well stimulation. Hydrochloric acid has many advantages in its application as follows:
· Low cost and availability.
· Easily inhibited to prevent attack on oil-field tubulars.
· Surface tension can be controlled to aid in :
– Penetration.
– Wetting properties.
– Exhibit detergency.
– Reducing friction pressure.
· Can be emulsified for slower reaction rate.
· Exhibit de-emulsification properties for rapid clean up.
· Most reaction products are water soluble and easily removed.
· Additives to minimise or eliminate insoluble reaction products can be applied.
It has long been recognised that hydrochloric acid is the best field acid for most applications. It is however, not without limitations. Hydrochloric acid is quite reactive; therefore, it will spend quite rapidly on some formations. It is essential with hydrochloric acid to size acid treatments and pump rates to optimise this property.

read more about Acidizing Different Formations

The reaction rate also dictates the selection of additives that will perform their functions during the relatively short spending time. These same additives must survive the spending process and function in the spent acid. Certain materials are soluble in hydrochloric acid but not necessarily in the spent acid water. For example, calcium sulphate can be partially solubilised by hydrochloric acid, but will crystallise out as scale when the acid spends. Iron oxide will dissolve in hydrochloric acid but will re-precipitate, as the acid spends, at about a pH of 2.0. These properties require
the selection of additives that will circumvent these problems.
Hydrochloric acid is normally pumped in concentrations ranging from 3.0% to 28%.
The low concentration acids are used for the removal of salt plugs and emulsions. The high concentration acids are selected to achieve longer reaction times and to create larger flow channels. By far the most frequently used strength is 15%, for the following reasons :
· Less cost per unit volume than stronger acids.
· Less costly to inhibit.
· Less hazardous to handle.
· Will retain larger quantities of dissolved salts in solution after spending.
In addition to the above advantages 15% hydrochloric acid will also provide other specific properties such as emulsion control and silt suspension. The general uses for hydrochloric acid are as follows :
· Carbonate acidizing – Fracture and Matrix.
· Sandstone acidizing – Matrix only.
· Preflush for HCl:HF mixtures.
· Post-flush for HCl:HF mixtures.
· Acidizing sandstones with 15% to 20% carbonate content.
· Clean-up of acid-soluble scales.
· Perforation washes.
Pure hydrochloric acid (muriatic acid) is a colourless liquid, but takes on a yellowish hue when contaminated by iron, chlorine, or organic substances. It is available commercially in strengths up to 23.5° Bé (Baumé scale) or 38.7% percent by weight of solution.
Some processes dictate that hydrochloric acid is not the most suitable acid to use. In these cases, alternatives, such as organic acids (acetic and formic) may be used.
These acids are used because of their inherently retarded nature, their ability to be used at higher temperatures and their solvation ability in “dirty” formations. The primary objection to the use of organic acids is their cost and their lack of effectiveness in removing limestone.

Other acids are also used in limited quantities. An example is citric acid, which can be used both alone, or as a component of an acid blend, or for use as a stabiliser, buffer and iron control agent. Also sulfamic acid has been used in the oil industry on a “do it yourself” basis. Its usage is recommended because of its low corrosivity,
although it is limited by its ability to strip chrome from chrome pumps and by its relatively high cost.

Hydrofluoric Acid (HF).
Hydrofluoric acid, another inorganic acid, is used with hydrochloric acid to intensify the reaction rate of the total system and to solubilise formations, in particular sandstones. In general hydrofluoric acid is used as follows :
· It is always pumped as an HCl:HF mixture.
· Ensure that salt ion contact is prevented.
· Sandstone matrix acidizing.

· Removal of HCl insoluble fines.
· Normal concentrations 1.5% to 6.0%.
· One gallon of 12:3 HCl:HF will dissolve 0.217 pounds of sand.
Hydrofluoric occurs as a liquid either in the anhydrous form (where it is fuming and corrosive), or in an aqueous solution (as used in well stimulation). Hydrofluoric acid attacks silica and silicates, (glass and concrete). It will also attack natural rubber, leather, certain metals such a cast iron and many organic materials.
In well stimulation, hydrofluoric acid is normally used in combination with hydrochloric acid. Mixtures of the two acids may be prepared by diluting mixtures of the concentrated acids with water, or by adding fluoride salts (e.g. ammonium bifluoride) to the hydrochloric acid. The fluoride salts release hydrofluoric acid when dissolved in hydrochloric acid.
Hydrofluoric acid is poisonous, alone or in mixtures with hydrochloric acid, and should be handled with extreme caution.Other Inorganic Acids.
Some consideration has been given to using sulfuric and nitric acids; however, these acids are not used extensively in the oil industry today. The reasons for the lack of use are; sulfuric acid will form insoluble precipitates, and nitric acid often forms poisonous gases during its reaction with certain minerals.

 Organic Acids.
These acids are used in well stimulation basically because they have a lower corrosion rate and are easier to inhibit at high temperatures than hydrochloric acid. Although mixtures of organic acids are considered corrosive to most metals, the corrosion rate is far lower than that of hydrochloric or hydrofluoric acid, therefore, organic acids are used when long acid-pipe contact time is required. An example of this is when organic acid is used as a displacing fluid for a cement job. The organic acids is left in the production string. and is subsequently used as the perforating fluid.
Organic acids are also used when metal surfaces of aluminium, magnesium, and chrome are to be contacted, such as in trying to remove acid-soluble scales in wells with downhole pumps in place. They can also be used as iron control agents for other acid systems. Many organic acids are available, but the four most commonly
used are :
· Acetic Acid.
· Acetic Anhydride.
· Citric Acid.
· Formic Acid.

Acetic Acid (CH3COOH).
Acetic acid is a colourless organic acid soluble in water in any proportion and in most organic solvents. Although mixtures of acetic acid with water are considered corrosive to most metals, the corrosion rate is far lower than that of hydrochloric and hydrofluoric acids. Acetic acid is easy to inhibit against corrosion and is used frequently as a perforating fluid where prolonged contact times are required. With this ability, the acid is sometimes used as a displacing fluid on a well cementing job, where the contact time may be hours or days before perforating takes place. This ability is beneficial in three ways:
· Reduces formation damage. The first fluid two enter the formation will be an acid or low pH fluid which will react with carbonate or the calcareous materials of a sandstone formation.
· Reduces clay swelling.
· Can be used where aluminium, magnesium or chrome surfaces must be protected.
The relation of dissolving power of one gallon of a 15% concentration of acetic acid compared to that of hydrochloric acid and formic acid at the same volume is listed in Table 1, page 3. The cost of acetic acid per unit, based on dissolving power, is more expensive than either hydrochloric acid or formic acid.
Normally, acetic acid is used in small quantities or with hydrochloric acid, as a delayed reaction, or retarded acid. The general uses and properties of acetic acid are as follows:
· Acetic acid is relatively weak.
· Normal concentrations of 7.5% to 10% when used alone.
· Mainly used in hydrochloric acid mixtures.
· Used as an iron control additive.
· Carbonate acidizing.
· Perforating fluid.
· Retarded acids.
Commercially available acetic acid is approximately 99% “pure”. It is called glacial acetic acid because, ice-like crystals will form in it at temperatures of approximately 60° F (16° C) and will solidify at approximately 48° F (9° C). When glacial acetic acid is mixed with water, a contraction occurs. For this reason, the amount of acetic acid and the amount of water normally total more than the required volume.
Care should be exercised when handling acetic acid. This solution in concentrated form can cause severe burns and fume inhalation can harm lung tissue

Acetic Anhydride Acid.
Acetic anhydride is the cold weather version, for use instead of acetic acid due to its lower freezing point of 2.0° F (-17° C). The properties of acetic anhydride are the same for those of acetic acid, the only changes are those in relation to volumes used.
A comparison of acetic anhydride to acetic acid shows that one gallon of acetic anhydride mixed with 0.113 gallons of water is equivalent to 1.127 gallons of acetic acid. Expressed alternatively one gallon of acetic acid is equivalent to 0.887 gallons of acetic anhydride mixed with 0.101 gallons of water.
When mixing acetic anhydride always add it to water or dilute acid. If water or dilute acid is added to acetic anhydride, an explosion will occur due to a rapid increase in temperature caused by the chemical reaction.
As with acetic acid, care should be exercised when handling acetic anhydride as this solution in concentrated form can cause severe burns and fume inhalation can harm lung tissue.

Citric Acid (C6H8O7)
Iron scales are normally found in the casing and tubing in wells and sometimes as the mineral deposits in the formation rock itself. When hydrochloric acid solutions come into contact with these scales or deposits, the iron compounds are partially dissolved and are carried in solution as iron chloride. As the acid becomes spent,
the pH rises above 2.0, allowing the iron chloride to undergo chemical changes and re-precipitate as insoluble iron hydroxide. This re-precipitation can reduce formation permeability and injectivity.
Citric acid (Ferrotrol 300) is a white granular organic acid material. It is used to “tie up” dissolved iron scales and prevent re-precipitation of dissolved iron from spent hydrochloric acid solutions. Normally, citric acid (often referred to as a sequestrant or sequestering agent), is used with X-14 to make the effects of suspension more
Citric acid is not used alone as an acid treating solution itself but is used in hydrochloric acid solutions known as sequestering acids (SA-systems) for the control of iron.
The amount of citric acid added to the hydrochloric acid system depends upon the amount of iron that is present. The first 50 pounds of citric acid added to 1000 gallons of acid, will sustain 2000 parts per million (ppm) of iron in solution (SA-2).
Each additional 50 pounds of citric acid added will increase its sequestering property by an additional 2000 ppm

Formic Acid (HCOOH)
Formic acid is the simplest of the organic acids and is completely miscible (capable of being mixed) with water. Formic acid is stronger than acetic acid yet weaker than hydrochloric acid. Formic acid is used in well stimulation, most frequently in combination with hydrochloric acid as a retarded acid system for high-temperature wells. The percentage of formic acid used in such applications is commonly between 8.0% and 10%. Formic acid can be easily inhibited, but not as effectively as with acetic acid at high temperatures and long contact times. The properties and uses of formic acid parallel those of acetic acid as stated below:
· Formic acid is relatively weak.
· Seldom used alone.
· Mainly used in hydrochloric acid mixtures.

Corrosion inhibitor aid.
· Hot wells.
· Retarded acids.
Acetic acid, acetic anhydride and formic acid are used when exceptionally retarded acid is needed because of extreme temperature or very low injection rates. At high temperatures, blends of organic and hydrochloric acid are much more successfully inhibited by organic inhibitors, than when hydrochloric acid is used alone. This property minimises the danger of hydrogen embrittlement of steel associated with hydrochloric acid treatments in high-temperature wells. Organic acid concentrations of up to 25% by weight are required, making acid treatment costs increase. Organic acids do not give as much reacting capability as hydrochloric acid treatments.

Enhanced Oil Recovery

Enhanced Oil RecoveryEOR Books :in this section you will find a collection of books about Enhanced Oil Recovery which is known as EOR, all you have to do is to choose the required book then click on Download word under this book’s name:
  Enhanced Oil Recovery “EOR” I – Fundamentals & Analysis

  Enhanced Oil Recovery “EOR” II – Processes & Operations

  EOR PowerPoint

  Microbial Enhanced Oil Recovery (MEOR)

 Enhanced Oil Recovery for Heavy Oil and Tar Sands

 Enhanced Oil Recovery pdf   10.7 MB

  Improved Oil Recovery  RAR 7.5 MB

  Enhanced Oil Recovery by CO2 Injection

  Thermal Recovery of Oil

  Enhanced Oil Recovery – Latil

See our Reservoir Books section  .. more than 60 FREE books about oil reservoirs.

  Enhanced Oil Recovery – Willhite    176 MB

  Enhanced Oil Recovery 43.5 MB

  Enhanced Oil Recovery Larry W. Lake


  Introduction to EOR

 Enhanced Oil Recovery compressed 

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 Petroleum Recovery, Heinemann

 Water Flooding EOR

  EOR Course – Part.1Introduction        Download

  EOR Course – Part.2EOR Methods       Download

  EOR Course – Part.3EOR Methods      Download

  EOR Teknica

  Improved Oil Recovery

Enhanced Oil Recovery Compressed 380 MB

The Mathematics Of Oil Recovery

  Mathematical Theory of Oil and Gas Recovery

  EOR with CO2
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  CO2 EOR and Storage in Oil Reservoirs
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EOR Challenges and Opportunities
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 Gas Injection for Disposal and Enhanced Recovery
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Enhanced Recovery and Production Stimulation
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See our Petroleum Reservoir Books section

EOR with CO2 Primer

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Surfactant Enhanced Oil Recovery by Wettability Alteration in Sandstone
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Summary Carbon Dioxide Enhanced Oil Recovery Well Technology
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Surface Phenomena in Enhanced Oil Recovery


  EOR – a big archive collection of 396 MB



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Produced Water Treatment

produced water treatmentThis section is for FREE books about produced water treatment in oil and natural gas industry, the multiple technologies used, produced water management

  Fundamentals of Sour Water Stripping

  Water Treatment part.1           Download Link

  Water Treatment part.2          Download Link

Oil Water Treatment

  Produced Water Papers

  Produced Water Treatment
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  State of Art in Produced Water Treatment
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  Overview of Emerging Produced Water Treatment Technologies
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  Technical Summary of Oil & Gas Produced Water Treatment Technology
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  Oil & Gas Produced Water Treatment Technologies
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  Advanced Produced Water and Reuse of Oilfields
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   a guide to practical management of produced water from onshore oil and gas operations in the United States
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Produced Water Course
Water Management       Download Link 1      Download Link 2

  Produced Water Management Part.1     Download Link 1      Download Link 2

  Produced Water Management Part.2     Download Link 1      Download Link 2

  Part.1 Produced Water Management    Download Link 1      Download Link 2

  Part.Economic Impact of Produced Water   Download Link 1      Download Link 2

  Part.3  Produced Water Quality & Characterization    Download Link 1      Download Link 2

  Part.4  Scale Problems in Oilfields & their Prevention   Download Link 1      Download Link 2

  Part.5  Microbiological Problems connected to Produced Water    Download Link 1      Download Link 2

  Part.6  Corrosion Connected to Produced Water        Download Link 1      Download Link 2

  Part.7  Produced Water Environmental Issues in the Marine Environment    Download Link 1      Download Link 2

  Part.8  Ecological Evaluation of Chemicals Added in Produced Water       Download Link 1      Download Link 2

  Part.9  Techniques to Minimize Water Production        Download Link 1      Download Link 2

  Part.10 Downhole Oil/Water Separation        Download Link 1      Download Link 2

  Part.11  State of Art in Water Treatment      Download Link 1      Download Link 2

 Effect of Hydrodynamic Characteristics on Floatation Treatment Process of Oily Wastewater Shahad Salim

   Oilfield Water Technology
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Water Treatment Handbook

Industrial Water Treatment

Water Treatment Plant

Water and Wastewater Treatment 

Petrophysics Seismic Books

     PetroPhysicsthis page contains the biggest collection of free books about seismic interpretation, petrophysics, and many other books related to petroleum and natural gas industry , you can download each book by clicking on Download below.

 Principles of 2D & 3D Seismic Interpretation

3D Seismic Interpretation

    Petrophysics, Peters

  3D Seismic Technology – Application to the Exploration of Sedimentary Basins


  Carbonate Petrophysics

 Recommended Practices for Core Analysis

 Formation Evaluation & Petrophysics

  A Lab Manual of Seismic Reflection+Processing

Petrophysical Engineering

  Seismic Data Interpretation and Evaluation for Hydrocarbon Exploration and Production

  Petrophysics 33.7 MB

  a Petroleum Geologists Guide to Seismic Reflection

  Basic Petrophysics

  the Role of the Petrophysicist in Reservoir Characterization

  Seismic Data Analysis Processing Inversion and Interpretation of Seismic Data 121 MB

   3D Seismic Imaging

 3D Seismic Survey Design  from Schlumberger

  a Geoscientist guide to Petrophysics

   Developments in Petrophysics

  Fundamentals of the Petrophysics of Oil and Gas Reservoirs

Fundamentals of Petrophysics

Seismic Exploration of Hydrocarbons in Heterogeneous Reservoirs

  Formation Evaluation and Petrophysics

  Seismic Migration Imaging of Acoustic Energy by Wave Field Extrapolation

    Application of Well Log Analysis to Assess the Petrophysical Parameters

  Guide To Petrophysical Interpretation


 Petrophysical Properties of Crystalline Rocks


  A Breviary of Seismic Tomography

  Introduction to Seismic Survey

  Petrophysics, A Practical Guide

  Principles of Mathematical Petrophysics

Practical Petrophysics

  Working Guide to Reservoir Rock Properties & Fluid Flow Tarek Ahmed

  Introduction to Petrophysics

  Physical Properties of Rocks


  Petrophysics and Reservoir Engineering

Interactive Petrophysics B1 archive 421 MB

Petrophysics, Geophysics and Logging

Basics for petrophysics
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Petrophysics  a B1 compressed file contains a huge collection of Petrophysics books 1.1 GB

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