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Get In-Stock Alert. Delivery not available. Pickup not available. Product Highlights The injected steam heats up the surrounding formation, causing significant reduction in oil viscosity.
Petroleum and Gas Field Processing, Second Edition - xexatifo.tk
The well is then put on production for a period of time until the oil flow declines. The process is then repeated through the same cycle of injection, shutting off, and production. This process is also known as the Hugh and Pugh method. Steam Flooding: This method is similar to the water-flooding process, except that steam is used instead of water.
The steam is injected into an injection well to reduce the oil viscosity while the condensed steam hot water displaces the oil toward the producing wells. In Situ Combustion: In this process, air is injected into the formation through an injection well under conditions that initiate ignition of the oil within the nearby formation. The combustion zone creates a front of distilled oil, steam, and gases. Continued air injection drives the combustion front toward the producing wells.
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The combination of heating and displacement by the steam, gases, and condensed liquids enhances the recovery of the oil. Production engineers have probably the most important role in both the development and operating stages of the field. They are responsible for making the development and production strategies prepared by the reservoir engineers a reality. They are also responsible for maintaining the wells at their best producing conditions throughout the life of the field.
These two major responsibilities are classified as subsurface production engineering. Still, production engineers are responsible for designing, installing, operating, and maintaining all surface production facilities starting from the flow lines at the wellhead and ending with the delivery of oil and gas to the end user. This is classified as surface production engineering, which is the main theme of this book. Both the subsurface and surface production engineering.
The main objective of that system is to obtain maximum recovery in the most economical and safe manner. In the following subsections, the functions are operations related to subsurface production engineering are briefly described. The well completion is the subsurface mechanical configuration of the well which provides the passage for the produced fluids from the face of the formation to the wellhead at the surface. The well completion design is needed by the drilling engineers to properly design, plan, and execute the drilling of the well that is compatible with the well completion.
Types of Well Completion There are three major types of well completion: 1. Open Hole Completions: For this type of completion, the well is drilled down to a depth that is just above the target petroleum formation. The production casing is then lowered into the well and cemented. The target formation is then drilled and is left uncased open.
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Depending on the production rate and the properties of the produced fluids, the well may be produced through the production casing or through production tubing placed above the producing formation with a packer that provides a seal between the tubing and casing. One of the functions of the packer is to protect the casing from the produced fluids. Figure 11 illustrates this type of well completion.
Cased Hole Perforated Completions: For this type of completion, the well is drilled all the way through the producing zone and the production casing is lowered and cemented. The casing is then perforated across the producing zone to establish communication between the formation and the well, as illustrated in Figure Again, depending on the producing conditions, production could be either through the casing or through a tubing.
Liner Completion: As illustrated in Figure 13, the production casing is set and cemented above the petroleum formation similar to an open hole completion. A liner basically a smaller diameter casing is then set and cemented across the producing formation. The linear is then perforated to establish communication between the well and the formation.
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In some cases, an already perforated or slotted liner may be set across the formation without cementing. The selection of a particular configuration is normally governed by the characteristics of the reservoir and cost. The type of the reservoir and drive mechanism, the rock and fluid properties, and the need for artificial lift and improved recovery are among the technical factors which influence the selection of. A conventional completion is the completion with a production tubing inside the production casing. A packer may or may not be used and the production could be through the tubing, the annulus, or both.
Depending on the number of petroleum formations to be produced through the well, we may have either single or multiple completion. Figure 14 illustrates a multiple triple conventional completion. The tubingless completion is a special type of completion where a relatively small-diameter production casing is used to produce the well without the need for production tubing. Such completions are low-cost completions and are used for small and short-life fields.
Again, we may have multiple tubingless completions or single as illustrated in Figure Tubing design involves the determination of the size, the grade, and weight of the production tubing. The size of the production tubing is controlled by the production rate, the types of flowing fluid, and the pressures at the bottom of the well and at the surface. The grade and weight of the tubing reflect its strength and are determined through analysis of the various loads that act on the tubing under all expected conditions.
Determining Tubing Size Determining the size of production tubing is the starting point for completion and drilling design, as it directly affects the sizes of all casing strings and, accordingly, the design and cost of the drilling program. The tubing size must be selected to handle the desired production rates under the varying producing conditions for the life of the well.
To properly determine the tubing size, the whole production system from the formation to the surface separator must be considered. The ability of the formation to produce fluids by the natural drive and improved recovery methods from the start of production until depletion need to be considered.
The flow of produced fluids through the production tubular, the wellhead restrictions, and the surface flow line over the life of the well need to be analyzed taking into account possible means of artificially lifting the fluids. The flow from the formation to the bottom of the well bottom hole is governed by what is known as the inflow performance relationship of the well, whereas the flow from the bottom hole to the surface is represented by the outflow performance relationship. The relationship is linear for reservoirs producing at pressures above the bubble point pressure i.
Otherwise, the relationship takes the shape of a curve, as illustrated in Figure The PI is basically the production rate per unit drawdown the difference in pressures between the average reservoir static pressure, PR, and Pwf. The IPR depends on the reservoir rock and fluid characteristics and changes with time, or cumulative production as illustrated in Figure Outflow Performance Relationship OPR : Outflow performance involves fluid flow through the production tubular, the wellhead, and the surface flow line.
In general, analyzing fluid flow involves the determination of the pressure drop across each segment of the flow system. This is a very complex problem, as it involves the simultaneous flow of oil, gas, and water multiphase flow , which makes the pressure drop dependent on many variables, some of which are interdependent.
There is no. Instead, empirical correlations and mechanistic models have been developed and used for predicting the pressure drop in multiphase flow. Computer programs based on such correlations and models are now. Sizing Tubing and Flow Line: Determination of the tubing and flow line sizes is a complex process involving the determination and prediction of future well productivity, analysis of multiphase flow under varying production conditions, and economic analysis. However, a simplied approach is summarized in the following steps and illustrated in Figure i ii. Determine predict the present and future IPR.
Plot the results as Pwf versus q. Selecting tubing and flow line diameters and starting with a specified value for the surface separator pressure, determine the flowing bottom-hole pressure for a specified production rate, water cut W. Step ii is repeated for different values of production rates q with W. Thus, a relation between q and Pwf is established and presented on the same plot of the IPR.
Steps ii and iii are repeated for various combinations of tubing and flow line sizes. Steps ii — iv are repeated for various expected values of W. If possible, select the tubing—flow line combination whose OPR curves intersects with present and all corresponding future IPR curves and provides values for q that are consistent with the planned production strategy. When more than one tubing—flow line combinations are possible, select the one that provides the best economics. Determining Tubing Grade and Weight Once the tubing size has been determined, the next step is to determine the grade and weight of the tubing.
Similar to casing, tubing grade refers to the type of steel alloy and its minimum yield strength. Tubing are available in the same grades as casing i. Other high-strength grades that are resistance to sulfide stress cracking are also available. To determine the tubing grade and weight, the maximum collapse and burst loads that act on the tubing are first calculated and multiplied by a safety factor.
These values are then used to make an initial selection of tubing grade and weight that provides sufficient collapse and burst resistance. With the selected weight, the tension load is calculated and multiplied by a safety factor.
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This is then compared to the tensile strength of the selected tubing. The selected tubing is accepted if its tensile strength matches or exceeds the tensile load. Completion and workover operations are basically similar. However, they are given different associations based on when the operation is performed. Completion operations are any and all operations performed on the well to get if ready for production.
Workover operations, however, refer to. Some of the important and common operations are briefly described in the following subsections. Perforating Operation For cased hole completions, perforations are made through the casing and cement and into the formation to establish communication between the formation and the wellbore. It is essential to have clean perforations with relatively large diameters and deep penetrations to achieve high well productivity.
Further, perforating should be done only through the clean and productive zones within the formation, as determined from the formation evaluation logs. Therefore, extreme care is taken in locating the perforating gun at the right locations. The selection of the type of perforating gun, explosive charges, and completion fluid and the control of the pressure in the well at the time of perforating are very important elements in achieving effective and productive perforations.
Perforations are made by detonating specially shaped explosive charges. The shaped charge consists of a body called the case, a linear that is made of a powder alloy of lead, copper, and tungsten, the explosive material that is contained between the case and the liner, and a detonating cord. Figure 19 shows a schematic cross section of a shaped charge.
Upon explosion, the case expands and ruptures and the liner collapses into a carrot-shaped jet consisting of lead, copper, and tungsten particles. The jet travels at very high velocity and impacts upon the casing with an extremely high pressure. The high energy of the jet causes the jet to penetrate through the casing, cement, and formation, thus creating the perforation.
Perforating guns are classified as hollow steel carrier, semi expendable, and fully expendable guns Fig. Hollow steel carrier guns are made of steel cylinders that carry the explosive charges and needed accessories. They come in small diameters that can go through the production tubing, and in large diameters that can go only through the production casing. They are rigid, can withstand high pressure and. However, because of their rigidity, they would not go through sharp bends.
For semiexpendable guns, the charges are fixed to a flexible metal strip. After detonation, most of the debris is expelled into the well, but the metal strip, any unfired charges, and the electronic detonator are retrieved. The flexibility of the guns allows movement through bends and highly deviated holes. Fully expendable guns have advantages similar to those of semiexpendable guns. However, because, after detonation, the gun breaks completely into pieces that are left in the hole, there is no way to know whether all charges have been fired.
To obtain clean and relatively undamaged perforations, the perforating operation should be conducted with the bottom-hole pressure much less than the reservoir pressure. Upon perforating, the differential pressure causes fluids to surge from the formation into the well; this effectively cleans the perforations from any debris. This method of perforating is known as underbalance perforating.
To perforate underbalance, the production tubing must be installed in the well and the peforating mode is, therefore, identified as the through-tubing perforating mode. In the early days, large through-casing hollow steel carrier guns were always needed to obtain large-diameter perforations with deep penetration. This required that the tubing be out of the well, and in order to have control over the well, perforating had to be conducted with the bottomhole pressure being higher than the reservoir pressure by a safe margin.
This mode of perforating overbalance did not offer an effective means for cleaning the perforations of the debris. Another mode of perforating which offers the opportunity to use large casing guns and perforating underbalance is known as tubing-conveyed perforating. Recent technological developments, however, have made it possible to obtain such desired perforations using small-size charges on a semiexpendable gun. Well Stimulation Operations Well stimulation operations could be classified into two main categories: matrix acidizing and formation fracturing. The objective of matrix acidizing is to remove near-wellbore formation damage that might have been caused by drilling or other workover operations in order to restore or enhance well productivity.
Formation fracturing, however, is conducted on formations having very low permeability in order to increase well productivity. For carbonate formation, matrix acidizing is achieved by injecting hydrochloric acid HCl into the formation at low pressure. As acid is injected, it preferentially flows through more permeable passages, reacting. This creates irregular highly conductive channels, known as a wormholes, for easier flow of fluid from the formation to the well.
For sandstone matrix acidizing, a solution of hydrofluoric and hydrochloric acids known as mud acid is injected into the formation to dissolve clay and, to some extent, silica. This removes the damage to restore the near-wellbore permeability. Fracturing is performed mostly on wells completed in very tight very low permeability formations. In carbonate formations, a fracturing fluid followed by HCl is injected at pressures exceeding the formation fracturing pressure.
The fracturing fluid initiates a fracture and the acid reacts with the carbonate walls of the fracture, leaving the walls as rough surface. Therefore, when the pressure is reduced, the fracture will not close and will provide a very conductive passage for fluids to flow from the formation into the well. This operation is known as acid fracturing.
Fracturing tight sandstone formations is known as hydraulic fracturing. As with carbonate fracturing, a fracturing fluid is injected at high pressure to initiate the fracture. The fracture is kept open by filling it with highly permeable, high-compressive-strength sand known as proppant. Sand Control When wells are completed in unconsolidated or weakly consolidated formations, sand is likely to be produced with the fluids. Sand production is a very serious problem. Produced sand erodes subsurface and surface equipment, necessitating very costly frequent replacement.
Sand also settles in the bottom of the well and in surface processing facilities. This requires periodic shutdowns to clean the well and facilities. Methods are available to control or prevent sand production. These are classified as mechanical retention methods and chemical, or plastic, consolidation methods.
The simplest method of mechanical retention involves the installation of screens opposite the producing zone.
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Screens, however, are subject to erosion and corrosion and would need to be replaced frequently. Therefore, screens are used only as a temporary solution to sand production problems. The best and most commonly used method of mechanical sand control is known as gravel packing. In simple terms, the method involves the installation of a screen having a smaller diameter than the casing diameter opposite the producing zone.
The annular space between the casing and screen is packed with specially sized gravel sand. Formation sand will bridge against the gravel, which bridges against the screen. This prevents formation sand from flowing with the fluids into the well. Chemical or plastic consolidation involves the injection of the polymer and catalyst solution into the formation to coat the sand grains around the wellbore with the polymer.
The polymer is then cured to harden and bonds the sand grains together and thus consolidates the sand around the wellbore. Each sand control method has its limitations and care should be taken to select the most suitable method for the situation in hand. All methods of sand control result in loss of productivity; this, however, is acceptable in comparison to the problems associated with sand production. Remedial Cementing Remedial cementing refers to any cementing operation performed on the well after placing it in production. These are basically repair jobs executed to resolve specific problems in the well.
The most common applications of remedial cementing are the following: 1. Channel Repair. A channel is a void or crack that developed during the primary cementing of the production casing string. When the channel behind the casing communicates two or more zones, unwanted fluids such as water may flow through the channel into the formation and be produced with the oil. Alternatively, the oil may flow through the channel and be lost into another lower-pressure formation.
A channel is repaired by creating a few perforations at the top and bottom of the channel and squeezing cement into the channel to seal if off. When one well is used to produce from multiplereservoir or multiple zones with one reservoir or zone produced at a time, the depleted zone must be plugged off before producing the next zone. Cement is squeezed into the old perforations to seal the depleted zone completely; then, the new zone is perforated.
Casing Leak Repair. Depending on the nature of the leak, cement may be used to seal parts of the casing, leaking unwanted fluids into the well or allowing produced oil to leak into other formations. Setting Liners. Cementing liners to convert an open hole completion into a perforated liner completion. Plug and Abandonment. For abandoning depleted wells, cement is used to squeeze and seal off all perforations and to set several cement plugs in the well.
Producing the well means bringing the fluids that flowed from the formation into the borehole, from the bottom of the well to the surface. Fluids need to be brought to the surface at the desired rate and with sufficient pressure to flow through the surface-treating facilities. Some reservoirs possess such a high pressure that it can produce the desired rates at high bottom-hole pressures that could push the fluids to the surface at the desired wellhead pressure.
This mode of production is known as natural flow. Reservoirs with high initial pressures and with strong pressure support i. When the reservoir pressure declines, pressure support may be provided by injecting water or gas into the reservoir to maintain natural flow at desired rates and surface pressures. In some cases, however, pressure support may not be sufficient to maintain desired natural flow.
This usually occurs due to increased water production, which increases the hydrostatic head and friction losses in the tubing. Therefore, the fluids may reach the surface at lower than desired pressures, or may not even reach the surface. In such cases, external means of lifting the fluids to the surface will be needed.
These means are known as the artificial lift methods. Production engineers are responsible for selecting, designing, installing, and operating artificial lifting facilities. Artificial Lift Methods The objective of artificial lift is to create low bottom-hole pressure to allow high rates of production from the formation into the bottom of the well and artificially lift the fluids to the surface with the desired surface pressure. The main methods of artificial lift are as follows: 1. The method is, however, limited to vertical and straight wells with relatively low productivity.
The pumping facility consists mainly of surface equipment that provide reciprocating up-and-down movement to a rod string the sucker rod that is connected to. The pump may be thought of as a cylinder-plunger system with one-way valves. Produced fluids enter the cylinder above the plunger during the down stroke and are lifted to the surface during the up stroke. Hydraulic Pumping HP : In this method, a pump located at the bottom of the well is powered by high-pressure fluid.
The function of the pump is to increase the produced fluid pressure to lift it to the surface with the desired wellhead pressure. Figure 22 shows a schematic of hydraulic pumping facility. The surface facility provides the high-pressure hydraulic fluid that powers the pump. Hydraulic fluid may flow through a closed circuit and does not come in contact with the produced fluids.
Oil may also be used as the hydraulic fluid, allowing its mixing with the produced fluids. The major limitations of this method are the need for expensive centralized hydraulic power units and expensive clean hydraulic fluid. The pump and motor are both located at the bottom of the well and electric power is provided to the motor from the surface through a special cable, Fig. As with the HP, the function of the ESP is to increase the pressure of the fluid so that it can move and reach the surface with high pressure.
The ESP is capable of producing very high rates with a high surface pressure. Gas Lift GL : Although many different types of gas-lift installation exist, the lifting concept is the same. High-pressure gas is injected into the annular space between the casing and tubing and enters the tubing, through special gas-lift valves Fig. The gas mixes with fluids in the tubing, reducing its density and, consequently, reducing the hydrostatic head imposed by the fluid at the bottom of the well.
The reduction. The reduced hydrostatic head reduces the pressure losses in the tubing and thus enables the fluid to reach the surface with relatively high pressure. Berger, B. Bradely, H. Bourgoyne, A. Craft, B. Prentice-Hall, Englewood, NJ. Green, D. Donohue, D. Hearts, J. Lee, W. Link, P K. Describe briefly the organic theory of petroleum formation. Define the petroleum reservoir. What are the necessary conditions that lead to the accumulation of petroleum to form a petroleum reservoir? Name and briefly describe, with illustrations, the different geologic types of petroleum reservoir.
Describe the different types of reservoir drive mechanism. Name and briefly describe the techniques used for petroleum exploration. What are the functions of drilling fluids? What is the purpose of the well casting? Describe briefly the role and functions of reservoir engineering in petroleum field development and operation. Show, using illustrations and giving reasons, where would you locate and complete wells for an anticline gas-cap-drive reservoir.
Show, using illustrations and giving reasons, where would you locate and complete wells for an anticline water-drive reservoir. What are the roles of reservoir simulation? Describe the various methods of improved recovery. Describe briefly the role and functions of production engineering in petroleum fields development and operation.
What are the main types of well completion? What are the different types of artificial lift method? Crude oils are complex mixtures of a vast number of hydrocarbon compounds. Properties of crude petroleum vary appreciably and depend mainly on the origin. In this chapter, the chemical composition of the crude oils is viewed, including the hydrocarbon series as well as the nonhydrocarbon compounds.
Physical methods generally used for indentifying types of crude oils are described next. Characterization and classification of crude oils based on correlation indexes and crude assays are presented, followed by a comparison between some of the well-known types of oil. In general, composition of crude oil may be studied by two methods: 1. Chemical approach 2. Physical methods Chemical composition describes and identifies the individual chemical compounds isolated from crude oils over the years.
Physical representation, on the other hand, involves considering the crude oil and its products as mixtures of hydrocarbons and describing physical laboratory tests or methods for characterizing their quality. Nearly all petroleum deposits are made up of a mixture of chemical compounds that consist of hydrogen and carbon, known as hydrocarbons, with varying amounts of nonhydrocarbons containing S, N2, O2, and other some metals.
The composition of crude oil by elements is approximated as shown in Table 1 . Each series consists of compounds similar in their molecular structure and properties e. Within a given series, there exists a wide spectrum of compounds that range from extremely light or simple hydrocarbon to a heavy or complex one. An example, CH4 for the former and C40H82 for the latter in the paraffinic series.
Hydrocarbon Series The major constituents of most crude oils and its products are hydrocarbon compounds, which are made up of hydrogen and carbon only. These compounds belong to one of the following subclasses: 1. Alkanes are relatively nonreactive compounds in comparison to other series. They may either be straight-chain or branched compounds, the latter are more valuable than the former, because they are useful for the production of high-octane gasoline. Cycloalkanes or Cycloparaffins Naphtenes : Cycloalkanes and bicycloalkanes are normally present in crude oils and its fractions in variable proportions.
The presence of large amounts. Naphtha cuts with a high percentage of naphthenes would make an excellent feedstock for aromatization. Alkenes or Olefins: Alkenes are unsaturated hydrocarbon compounds having the general formula CnHn. They are practically not present in crude oils, but they are produced during processing of crude oils at high temperatures.
Alkenes are very reactive compounds. Light olefinic hydrocarbons are considered the base stock for many petrochemicals. Ethylene, the simplest alkene, is an important monomer in this regard. For example, polyethylene is a wellknown thermoplastic polymer and polybutadiene is the most widely used synthetic rubber. Aromatics: Aromatic compounds are normally present in crude oils. Aromatics in this range are not only important petrochemical feedstocks but are also valuable for motor fuels. Dinuclear and polynuclear aromatic compounds are present in heavier petroleum fractions and residues.
Asphaltenes, which are concentrated in heavy residues and in some asphaltic crude oils, are, in fact, polynuclear aromatics of complex structures. It has been confirmed by mass spectroscopic techniques that condensed-ring aromatic hydrocarbons and heterocyclic compounds are the major compounds of asphaltenes. Nonhydrocarbon Compounds So far, a brief review of the major classes of the hydrocarbon compounds that exist in crude oils and their products was presented. For completeness, we should mention that other types of nonhydrocarbon compound occur in crude oils and refinery streams.
Sulfur Compounds. In addition to the gaseous sulfur compounds in crude oil, many sulfur compounds have been found in the liquid phase in the form of organosulfur. These compounds are generally not acidic. Sour crude oils are those containing a high percentage of hydrogen sulfide. However, many of the organic sulfur compounds are not thermally stable, thus producing hydrogen sulfide during crude processing.
High-sulfur crude oils are in less demand by refineries because of the extra cost incurred for treating refinery products. Naphta feed to catalytic reformers is hydrotreated to reduce sulfur compounds to very low levels 1 ppm to avoid catalyst poisoning. The following sulfur compounds are typical: 1. Mercaptans H—S—R : Hydrogen sulfide, H—S—H, may be considered as the simple form of mercaptan; however, the higher forms of the series are even more objectionable in smell.
For example, butyl mercaptan H—S—C4H9 is responsible for the unusual odor of the shank. Sulfides R—S—R : When an alkyl group replaces the hydrogen in the sulfur-containing molecule, the odor is generally less obnoxious. The hydrogen sulfide may be removed by heating and may be separated by using amine solutions. Polysulfides R—S—S—R : These are more complicated sulfur compounds and they may decompose, in some cases depositing elemental sulfur.
They may be removed from petroleum fractions, similar to the sulfides, by hydrotreating. Nitrogen Compounds. Nitrogen compounds in crude oils are usually low in content about 0. Nitrogen in petroleum is in the form of heterocyclic compounds and may be classified as basic and nonbasic.
Basic nitrogen compounds are mainly composed of pyridine homologs and have the tendency to exist in the high-boiling fractions and residues. The nonbasic nitrogen compounds, which are usually of the pyrrole and indole, also occur in high-boiling fractions and residues. Only a trace amount of nitrogen is found in light streams. During hydrotreatment hydrodesulfurization of petroleum streams, hydrodenitrogeneation takes place as well, removing nitrogen as ammonia gas, thus reducing the nitrogen content to the acceptable limits for feedstocks to catalytic processes.
It has to be stated that the presence of nitrogen in petroleum is of much greater significance in refinery operations than might be expected from the very small amounts present. It is established that nitrogen compounds are responsible for the following: 1. Catalyst poisoning in catalytic processes 2. Gum formation in some products such as domestic fuel oils Oxygen Compounds.
Oxygen compounds in crude oils are more complex than sulfur compounds. However, oxygen compounds are not poisonous to processing catalysts. Most oxygen compounds are weakly acidic, such as phenol, cresylic acid and naphthenic acids. Metallic Compounds. Many metals are found in crude oils; some of the more abundant are sodium, calcium, magnesium, iron, copper, vanadium, and nickel. The occurrence of metallic constituents in crude oils is of considerably greater interest to the petroleum industry than might be expected from the very small amounts present. The organometallic compounds are usually concentrated in the heavier fractions and in crude oil residues.
The presence of high concentration of vanadium compounds in naphtha streams for catalytic reforming feeds will cause permanent poisons. These feeds should be hydrotreated not only to reduce the metallic poisons but also to desulfurize and denitrogenate the sulfur and nitrogen compounds. Hydrotreatment may also be used to reduce the metal content in heavy feeds to catalytic cracking. Having discussed the various chemicals found in crude oils and realizing not only the complexity of the mixture but the difficulty of specifying a crude oil as a particular mixture of chemicals, we can understand why the early petroleum producers adopted the physical methods generally used for classification.
As may be seen, crude oils from different locations may vary in appearance and viscosity and also vary in their usefulness as producers for final products. It is possible by the use of certain basic tests to identify the. The tests included in the following list are primarily physical except sulfur determination : 1.
Aniline point Carbon residue. The details of some of these tests are described next. API Gravity Earlier, density was the principal specification for petroleum products. However, the derived relationships between the density and its fractional composition were only valid if they were applied to a certain type of petroleum. Density is defined as the mass of a unit volume of material at a specified temperature. It has the dimensions of grams per cubic centimeter. Another general property, which is more widely, is the specific gravity.
It is the ratio of the density of oil to the density of water and is dependent on two temperatures, those at which the densities of the oil sample and the water are measured. Thus, the density of water, for example, varies with temperature, whereas its specific gravity is always unity at equal temperatures. Although density and specific gravity are used extensively in the oil industry, the API gravity is considered the preferred property. Thus, in this system, a liquid with a specific gravity of 1. A higher API.
Carbon Residue Carbon residue is the percentage of carbon by weight for coke, asphalt, and heavy fuels found by evaporating oil to dryness under standard laboratory conditions. Carbon residue is generally referred to as CCR Conradson carbon residue. It is a rough indication of the asphaltic compounds and the materials that do not evaporate under conditions of the test, such as metals and silicon oxides.
The lower the pour point, the lower the paraffin content of the oil. Ash Content This is an indication of the contents of metal and salts present in a sample. The ash is usually in the form of metal oxides, stable salts, and silicon oxides. The crude sample is usually burned in an atmosphere of air and the ash is the material left unburned. Metals In particular, arsenic, nickel, lead, and vanadium are potential poisons for process catalysts. Metal contents are reported in parts per million ppm. Nitrogen It is the weight of total nitrogen determined in a liquid hydrocarbon sample in ppm.
Thanks for telling us about the problem. Return to Book Page. Abdel-Aal ,. Mohamed A. The immediate product extracted from oil and gas wells consists of mixtures of oil, gas, and water that is difficult to transport, requiring a certain amount of field processing. This reference analyzes principles and procedures related to the processing of reservoir fluids for the separation, handling, treatment, and production of quality petroleum oil and gas products. I The immediate product extracted from oil and gas wells consists of mixtures of oil, gas, and water that is difficult to transport, requiring a certain amount of field processing.
It details strategies in equipment selection and system design, field development and operation, and process simulation and control to increase plant productivity and safety and avoid losses during purification, treatment, storage, and export. Providing guidelines for developing efficient and economical treatment systems, the book features solved design examples that demonstrate the application of developed design equations as well as review problems and exercises of key engineering concepts in petroleum field development and operation.
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