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(2) INSTRUMENTATION BOOKS SERIES. Volume 1. Measurement of Pressure and Flow. Volume 2. Measurement of Temperature and Level. Volume 3. Analysers. Volume 4. Control Valves Part I. Volume 5. Control Valves Part II. Volume 6. Control Valves Design. Volume 7. Digital Controllers. Volume 8. Distributed Control Systems. Volume 9. Programmable Logic Controller. Volume 10. Supervisory Control and Data Acquisition System. Volume 11. Vibration Systems. Volume 12. Interview Questions. Volume 13. Instrumentation in Process Industry. Volume 14. Logic Distributed Control Systems. Gowtham Books. 2 of 92.

(3) Volume 13 Instrumentation in Process Industry. A.Gowthaman. ME,MBA. Mail : [email protected] Web : http://sites.google.com/site/gowthamancpcl/. Gowtham Books. 3 of 92.

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(5) UNIT I PETROLEUM PROCESSING Petroleum exploration – Recovery techniques – Oil – Gas separation - Processing wet gases – Refining of crude oil. INTRODUCTION The carbon and hydrogen necessary for the formation of oil and gas were derived from early marine life forms living on the Earth during the geologic past -- primarily marine plankton. Although plankton are microscopic, the ocean contains so many of them that over 95% of living matter in the ocean is plankton. The Sun's energy provides energy for all living things including plankton and other forms of marine life.. As these early life forms died, their remains were captured by the processes of erosion and sedimentation.. Successive layers of organic-rich mud and silt covered preceding layers of organic rich sediments and over time created layers on the sea floor rich in the fossil remains of previous life .. Thermal maturation processes (decay, heat, pressure) slowly converted the organic matter into oil and gas. Add additional geologic time (millions of years) and the organic rich sediments were converted into layers of rocks. Add more geologic time and the layers were deformed, buckled, broken, and uplifted; the liquid petroleum flowed upward through porous rock until it became trapped and could flow no further forming the oil and gas reservoirs that we explore for at present .. But the chemistry of the hydrocarbons found in the end product (oil, gas) differ somewhat from those we find in living things. Thus changes, transformation, take place between the deposition of the organic remains and the creation of the end product. The basic formula for the creation of petroleum (oil, gas) is: Petroleum End Product = ([Raw Material + Accumulation + Transformation + Migration] + Geologic Time). Conversion of the organic material is called catagenesis. It is assisted by pressure caused by burial, temperature and thermal alteration and degradation. These factors result from depth, some bacterial action in a closed nonoxidising chemical system, radioactivity and catalysis. Temperature, as thermogenic activity, appears to be the most important criterion, with assistance other factors as applicable. Accumulation of organic and clastic material on a sea or lake bottom is accompanied by bacterial action. If there is abundant oxygen, aerobic bacteria act upon the organic matter and destroy it.. Gowtham Books. 1 of 92.

(6) Plant and animal remains contain abundant carbon and hydrogen, which are fundamental elements in petroleum. Shale and some carbonates contain organic material that bears hydrocarbons of types similar to those in petroleum. These rocks are not reservoir rocks and could be considered ultimately to be source beds. The hydrocarbons are of the same type as those found in living plants and animals and consist of asphalt, kerogen and liquid forms. The best source rocks are considered to be organically rich, black-coloured shales, deposited in a non-oxidising, quiet marine environment.. Generation of crude oil. Organic composition in shales. Organic material in shale averages approximately one (1) percent of the shale rock volume. Clay mineral constituents comprise the remaining 99 percent. Kerogen is an insoluble, high molecular weight, polymeric compound which comprises about 90 percent of the organic material in shale. The remaining 10 percent comprises bitumens of varying composition, which, according to some researchers, is thermally altered kerogen. As alteration occurs, kerogen is developed by the increasing temperature in the closed system. Temperature increases with depth. Normal heat flow within the earth’s crust produces an average geothermal gradient of approximately 1.50F for each 100 feet of depth. Maturation studies on various crude oil types indicate that temperatures required to produce oil occur between the depth of approximately 5,000 feet and 20,000 feet under average heat-flow conditions. Pressure, like temperature, is a function of depth and increases 1 psi for each foot of depth. Pressure is caused by the weight of the sedimentary overburden. Bacterial action is important in the conversion of organic material to petroleum at shallow depths. It is involved in the process of breaking down the original material into hydrocarbon compounds, which eventually become biogenic gas. Kerogen is a primary factor in forming bitumens that increase and migrate to accumulate as crude oil. Thermal conversion of kerogen to bitumen is the important process of crude oil formation. Thermal alteration increases the carbon content of the migratable hydrocarbons, which leaves the unmigratable kerogen components behind. Maturation of kerogen is a function of increased burial and temperature and is accompanied by chemical changes. As kerogen thermally matures and increases in carbon content, it changes from an immature light greenish-yellow color to an overmature black, which is representative of a higher coal rank.. Gowtham Books. 2 of 92.

(7) Generation of Natural Gas Natural gas comprises biogenic gas and thermogenic gas with differences contingent upon conditions of origin. Biogenic gas forms at low temperatures at overburden depths of less than 3,000 feet under anaerobic or conditions associated with high rates of marine sediment accumulation. Oxygen in the sediments is consumed or eliminated early. And before reduction of sulfates in the system. Methane, the most common of natural gas constituents, forms after the sulfates are eliminated by hydrogen reduction of carbon dioxide. Anaerobic oxidation of carbon dioxide produces methane. Current estimates suggest that approximately 20 percent of the world’s known natural gas is biogenic. Thermogenic gas forms at significantly higher temperatures and overburden pressures. It contains methane and significantly larger amounts of heavier hydrocarbons than biogenic gas. As time and temperature increase, progressively lighter hydrocarbons form as wet gas and condensate in the latter stages of thermogenesis. PETROLEUM RESERVOIRS The term reservoir implies storage. Reservoir rock, therefore, is that rock in which the hydrocarbon can be stored and from which it can be produced. The fluids of the subsurface migrate according to density with the dominant fluids in hydrocarbon regions being hydrocarbon gas, hydrocarbon liquids and salt water. Since the hydrocarbons are the less dense of these fluids, they will tend to migrate upward, displacing the heavier salt water down elevation. Hydrocarbons may be forced from their source rock during lithification, and migrate into the reservoir rock in which they are stored. The fluids present will separate according to density as migration occurs. SURFACE EXPLORATION METHODS In regions where rocks are exposed at the surface, geological studies based on these surface outcrops can be of value in predicting sub-surface geology. Analysis of this information can provided can sometimes be extrapolated to anticipate geology in other locations not accessible for observation and analysis. The major sources of surface geological information are: i) Field Reconnaissance ii) Aerial Surveys iii) Satellite Surveys iv) Surface Geochemical Analysis. Gowtham Books. 3 of 92.

(8) Field Reconnaissance This involves observation and sample collection of surface geological exposures. In some regions, surface geological outcrops imply sub-surface geological characteristics. This surface observation might provide an indication of the sequence of geological events, which led to this surface geology. Geological properties such as strike and dip of sedimentary beds, faults unconformities or other geologic exposures may be of major importance in anticipating subsurface geology. The strike is the compass direction of a horizontal line drawn in the plane under consideration. The dip is the angle between a horizontal plane and a line drawn in the plane under consideration, perpendicular to the intersection of the horizontal plane and the plane under consideration.. Aerial surveys/ satellite survey More recently, satellite surveys might provide the same type of information as that by field reconnaissance, except over large regions. Extensive geologic information of importance in defining sub-surface geology has been gathered by such surveys as landsat survey, infra-red photography, radar photography and other sophisticated technologies.. Surface Geochemical Analysis This can provide indicates of the presence of sub-surface hydrocarbon reservoirs. Many scientists speculate that all sub-surface hydrocarbon reservoirs give surface chemical indications of their presence. The simplest example is the surface seep, where hydrocarbon is actually escaping or seeping to the surface and being dissipated, in geologic time, into the environment. The conclusion can therefore be drawn that this surface hydrocarbon must be originating from sub-surface reservoirs.. 1.2. GEOPHYSICAL EXPLORATION. After identifying sedimentary basins thought to contain hydrocarbons, an oil company acquires the mineral rights from the individual or government holding them. The oil company will then contract with a seismic acquisition company to map the area's underground rock formations through seismic surveying.. Gowtham Books. 4 of 92.

(9) 1.2.1 GRAVITY METHODS Gravity methods are based on the measurement of physical quantities related to the gravitational field, which in turn are affected by differences in the density and the disposition of underlying geological bodies. In oil and gas exploration, in which no direct density control is associated with the material being sought, exploration is based on the mapping of geological structures to determine situations that might localize the material being sought. In such cases, the significant density values are salt 2.1 to 2.2, igneous rocks 2.5 to 3.0, and sedimentary rocks 1.6 to 2.8. The last value increases with depth owing to consolidation and geological age, and as a result, structural deformation associated with faults and folding can be detected. Compaction of sediments over edges or knolls on the underlying crystalline rock surface also leads to a local increase in mass, as does the development of calcareous cap rock over the heads of intrusive salt columns. Thus, the gravimeter detects differences in gravity and gives an indication of the location and density of underground rock formations. Differences from the normal can be caused by geological and other influences, and such differences provide an indication of subsurface structural formations. In the early days of gravity prospecting, both the torsion balance and the pendulum apparatus were extensively employed, but these have been supplanted by spring balance systems (gravimeters). The latter can be read in a matter of minutes, in contrast to the several hours required in obtaining readings with the earlier instruments. There is a variety of gravimeters, but those in common use consist essentially of a weighted boom that pivots about a hinge point. The boom is linked to a spring system so that the unit is essentially unstable and hence very sensitive to slight variations in gravitational attraction. Deflections of the boom from a central (zero) position are measured by observing the change in the tension in the spring system required to bring the boom back to that position. Readings are taken from a graduated dial on the head of the instrument that is attached to the spring system through a screw. There must be an accurate calibration of the screw, reading dial, and spring response for the readings to have gravitational significance. Gravimeters can also be employed for use in shallow water. Thus, use of watertight housings with automatic leveling and electronic reading devices allows gravimeter surveys to be carried out in aqueous environments. Other gravimeters have been developed for use in submarines and on gyro-stabilized platforms on surface ships as well as in aircraft.. 1.2.2 MAGNETIC METHODS. Magnetic methods are based upon measuring the magnetic effects produced by varying concentrations of ferromagnetic minerals, such as magnetite. Instruments used for magnetic prospecting vary from the simple mining compass used in the seventeenth century to sensitive airborne magnetic units permitting intensity variations to be measured with an accuracy greater than 1=10,000 part of the earth’s field.. Gowtham Books. 5 of 92.

(10) The magnetometer is a specially designed magnetic compass and detects minute differences in the magnetic properties of rock formations, thus helping to find structures that might contain oil, such as the layers of sedimentary rock that may lie on top of the much denser igneous, or basement, rock. The data give clues to places that might conceal anticlines or other oilfavorable structures. Of even more value is the determination of the approximate total thickness of the sedimentary rock, which can save unwarranted expenditure later or more costly geophysics or even the drilling of a well when the sediment may not contain sufficient oil to warrant further investigation. Most magnetometer surveys used now are performed by the use of aircraft, which permits large-scale surveys to be made rapidly and surveys over regions that may be otherwise inaccessible. One of the most widely used magnetic instruments is the Schmidt vertical magnetometer. It consists of a pair of blade magnets balanced horizontally on a quartz knife edge. The balance is oriented at right angles to the magnetic meridian. The deflection from the horizontal is observed, giving the variation in magnetic vertical intensity with gravity.. The torsion fiber magnetometer is also a vertical component instrument but has an operating range greater than the Schmidt instrument. It also has an advantage in that it is easier and quicker to read. The instrument values are referred to a base and corrected for temperature and diurnal variation and for the normal geographic variation of the earth’s magnetic field. The nuclear precession magnetometer is another continuous recording magnetic instrument that measures the earth’s total magnetic field by observing the free precession (progressive movement) frequency of the protons in a sample of water. The interpretation of magnetic measurements is subject to the same fundamental drawbacks as noted for gravity measurements. The drawbacks are as follows: 1. Contrast in physical properties of the formations 2. Depth of origin and integrated contributions from many sources 3. Changes in strength and direction of the earth’s field with location 4. Canceling effect related to proximity of opposite induced poses at the boundaries of finite geological bodies However, the method has proved valuable in exploration for magnetic mineral deposits, in the determination of geological structural trends, and in estimating the probable depth of the crystalline rock floor beneath sedimentary rock areas.. Gowtham Books. 6 of 92.

(11) 1.2.3 SEISMIC METHODS Seismic methods are based on determinations of the time interval that elapses between the initiation of a sound wave from detonation of a dynamite charge or other artificial shock and the arrival of the vibration impulses at a series of seismic detectors (geophones). The arrivals are amplified and recorded along with time marks (0.01 sec intervals) to give the seismogram. The method depends upon whether (1) the velocity within each of the layers penetrated at depth is greater than that in the layers above; (2) the layers are bounded by plane surfaces; and (3) the material within each layer is essentially homogeneous. The seismograph measures the shock waves from explosions initiated by triggering small controlled charges of explosives at the bottom of shallow holes in the ground. The formation depth is determined by the time elapsed between the explosion and detection of the reflected wave at the surface. The depths and media reached by seismic waves depend on the distance between shot point and receiving points. The first impulses or breaks in a seismogram are caused by waves that have traveled quickly between the shot point and any receiving point. At short distances this is usually also the shortest path, but beyond a certain distance it is quicker for a refracted pulse to travel via a longer path involving underlying layers with a higher velocity. From a plot of travel time as a function of surface distance, data are obtained for determining both the velocity of the material and number of layers present. From the distances at which changes in velocity are indicated, the depth of each layer can be computed.. In general, the deeper, older formations as a result of higher compression have a higher density and also a higher seismic velocity than the overlying material. Observed differences in velocity not only define the direction of slope of the rock surfaces but also provide information for computing the degree of slope present. For what might be termed normal conditions (increase in velocity with depth), the error determined in depths is usually less than 10% with this method.. Seismic geophysical work is also carried out on the water, greatly aiding the search for oil on the continental shelves and other areas covered by water. A marine seismic project moves continually, with detectors towed behind the boat at a constant speed and a fairly constant depth. Explosive charges are detonated at a position and time determined by the speed of the boat, so that a continuous survey of the reflecting horizons can be obtained.. Gowtham Books. 7 of 92.

(12) 1.2.4 ELECTRICAL METHODS Electrical prospecting methods depend upon differences in electrical conductivity between the geological bodies under study and the surrounding rocks. In general, metallic minerals, particularly the sulfides, range in resistivity from 1.0 to several V-cm, whereas consolidated sediments of low water content average about l04 S-cm, igneous rocks range from 104 to 106 V-cm, and saturated unconsolidated sediments from 102 to 104 V-cm. The resistivity of the last depends largely on the amount and electrolytic nature (salinity) of the included water. On the other hand, the self-potential method makes use of the fact that most metallic sulfide minerals are easily oxidized by downward-percolating groundwater. As a result of this surface oxidation, the elements of a simple chemical battery are established and an electrical current flows down through the ore body and back to the surface through the surrounding water-saturated ground, which acts as the electrolyte. It is possible to locate these localized electrical fields and, hence, ore bodies by mapping points of equal electrical potential at the surface using nonpolarizing electrodes and a sensitive ammeter, or a milli-ammeter. Alternatively, measuring the potential differences between successive profile stakes forming a grid over an area using a potentiometer can also be employed. A special application of electrical methods is in the study of subsurface stratigraphy by measuring the potential differences between the surface and an electrode lowered in a borehole and also by measuring variations in electrical resistivity with depth (electrical logging). This method produces a measure of porosity and permeability, as the data are affected markedly by the ability of the drilling fluid to penetrate the formation. The resistivity measurements define the position of formation boundaries and the lithological character of the sediments. Three resistivity logs are usually taken: (1) one having a shallow penetration to define the location of the formation boundaries and two others having (2) intermediate and (3) deep penetration. These last two logs are used to determine the extent to which the drilling fluid has penetrated into the formations and the true resistivity of the formation present. The various measurements taken in conjunction provide a valuable tool not only for studying conditions in a given well, but also for carrying out correlation studies between wells and thus defining geological structure and horizontal changes in lithology.. 1.2.5 ELECTROMAGNETIC METHODS Electromagnetic methods are based upon the concept that an alternating magnetic field causes an electrical current to flow in conducting material. Measurements are carried out by connecting a source of alternating current to a coil of wire, which acts as a source for a magnetic field similar to that which will be produced by a short magnet located on the axis of the coil. A receiving system consisting of a second coil connected to a voltmeter is mounted, so that there is free rotation about a horizontal axis. The receiving coil should be mounted so that rotation is on an axis perpendicular to that of the induced magnetic field. In this case, the induced voltage (in the absence of a conductor) will vary from zero (when the coil plane is parallel to the plane of the applied field) to a maximum (when the coil plane is perpendicular to the plane of the applied field). Gowtham Books. 8 of 92.

(13) However, if a conductor is present, the induced current in the conductor sets up a secondary magnetic field that distorts the primary field and gives a value that is not horizontal except directly over the conductor. By using an inclinometer to record the angle of the moving search coil when in the null position, the location of a conductor can be determined as the crossover (inflection) point on a profile across the body. Another variation of this method is to have both the receiver and the transmitting coils in the horizontal plane. In this arrangement, the voltage developed over nonconducting ground is a function of the construction of the coils that are usually moved across the ground with a constant separation. The presence of a conductor is indicated by changes in the voltage values from the normal values for this configuration. 1.2.6 RADIOACTIVE METHODS In the disintegration of radioactive minerals three spontaneous emissions take place, the election of an electron (b-ray), a helium nucleus (a-ray), and short-wavelength electromagnetic radiation (grays). The instruments used in radioactive exploration are the Geiger counter and the scintillometer. In addition to prospecting for radioactive minerals, the radioactive method is extensively applied in borehole studies of subsurface stratigraphy as might be deemed necessary when prospecting for oil. Different sedimentary rocks are naturally characterized by different concentrations of radioactive materials. Shale and volcanic ash give the highest g-ray count and limestone, the lowest g-ray count. BOREHOLE LOGGING This involves drilling a well and the use of instruments to log or make measurements at various levels in the hole by such means as electrical resistivity, radioactivity, acoustics, or density. In addition, formation samples (cores) are taken for physical and chemical tests. The use of electrical logging is based on the fact that the resistivity of a rock layer is a function of its fluid content. Oil-filled sand has very high resistivity. The method consists of passing a current between an electrode at the surface and one that is lowered into the hole, the latter being uncased and filled with drilling mud. Any change in the resistivity conditions around the moving electrode affects the flow of current and voltage distribution around it. Voltage fluctuations can be measured by a pair of separate electrodes used in conjunction with the moving electrode.. Gowtham Books. 9 of 92.

(14) The natural radioactive properties of many constituents of rock have made it possible to develop and use nuclear radiation detectors (radioactive logging) in the borehole or even in holes that have already been cased. Two commonly used methods are g-ray and neutron logging. In the first case, the natural radiation from the rock is used. In the second, a neutron source is employed to excite the release of radiation from the rock. The neutron source is usually a mixture of beryllium and radium, but it can be a miniature Van der Graaff particle accelerator. The neutron method is a means for determining the relative porosity or rock formations; the g-ray log helps define shale. The acoustic logging method is quite similar to surface seismic work. Instead of explosives, an electrically operated acoustic pulse generator is used. In one instrument, the generator is separated from the receiver by an acoustic insulator. The design permits automatic selection and recording of the travel times of the onsets of pulses that travel through the rock wall of the hole as the instrument moves down or up. Signals are recorded continuously at the surface, being transmitted through a cable on which the instrument is suspended. The velocity log provided by the instrument helps to define beds and evaluate formation porosity. Density can now be logged with a new technique that uses radioactivity (density logging). The instrument consists of a radioactive cobalt source of g-rays and a Geiger counter as a detector, which is shielded from the source. The rock formation is bombarded with the g-rays, some of which are scattered back from the formation and enter the detector. The degree to which the original radiation is adsorbed is a function of the density of the rock. Test well sampling is another important method used in the search for oil (core sampling). Well data obtained from the examination of formation samples taken from various depths in the borehole are of considerable value in deciding further exploratory work. These samples can be cores, which have been taken from the hole by a special coring device or drill cuttings screened from the circulating drilling mud. The major purpose of sample examination is to identify the various strata in the borehole and compare their positions with the standard stratigraphic sequence of all the sedimentary rocks occurring in the specific basin where the hole has been drilled. DRILLING OPERATIONS Generally, the first stage in the extraction of crude oil is to drill a well into the underground reservoir. Often many wells (called multilateral wells) are drilled into the same reservoir, to ensure that the extraction rate is economically viable. Also, some wells (secondary wells) may be used to pump water, steam, acids, or various gas mixtures into the reservoir to raise or maintain the reservoir pressure, and hence maintain an economic extraction rate. Drilling for oil is a complex operation and has evolved considerably over the past 100 years. The older cable tool method, used extensively until 1900, involves raising and dropping a heavy bit and drill stem attached by cable to a cantilever arm at the surface. It pulverizes the rock and earth, gradually forming a hole. The cable tool system is generally preferred only for penetrating hard rock at shallow depths and when oil reservoirs are expected at shallow depths. The weight of the column is usually enough to attain penetration but can be augmented by a hydraulic pressure cylinder at the surface.. Gowtham Books. 10 of 92.

(15) PREPARING TO DRILL Once the site has been selected, it must be surveyed to determine its boundaries, and environmental impact studies may need to be performed. Lease agreements, titles, and right-of way accesses for the land must be obtained and evaluated legally. For offshore sites, legal jurisdiction must be determined. Once the legal issues have been settled, the crew goes about preparing the land; preparation is essential and involves the following steps: 1. Land is cleared and leveled, and access roads may be built. 2. Because water is used in drilling, there must be a source of water nearby. If there is no natural source, a water well is necessary. 3. Reserve pit, which is used to dispose of rock cuttings and drilling mud during the drilling process and which is lined with plastic to protect the environment, is created. If the site is an ecologically sensitive area, such as a marsh or wilderness, then the cuttings and mud must be disposed offsite, it may have to be trucked away instead of being placed in a pit. Once the land has been prepared, several holes must be dug to make way for the rig and the main hole. A rectangular pit (a cellar) is dug around the location of the actual drilling hole. The cellar provides a workspace around the hole for the workers and drilling accessories. The crew then begins drilling the main hole, often with a small drill truck rather than the main rig. The first part of the hole is larger and shallower than the main portion, and is lined with a large-diameter conductor pipe. Additional holes are dug off to the side to temporarily store equipment, after which the rig equipment can be brought in and set up. DRILLING RIG Depending upon the remoteness of the drill site and its access, equipment may be transported to the site by truck, helicopter, or barge. Some rigs are built on ships or barges for work on inland water where there is no foundation to support a rig (as in marshes or lakes). Once the equipment is at the site, the rig is set up (Figure below). The anatomy of a drilling rig, although simple in a schematic representation is, in reality, quite complex and consists of the following systems: 1. Power system: a. Large diesel engines to provide the main source of power b. Electrical generators powered by diesel engines to provide electrical power 2. Mechanical system that is driven by electric motors: a. Hoisting system that is used for lifting heavy loads and consists of a mechanical winch (draw works) with a large steel cable spool, a block-and-tackle pulley, and a receiving storage reel for the cable b. Turntable that is part of the drilling apparatus 3. Rotating equipment (used for rotary drilling): a. Swivel, i.e., a large handle, which holds the weight of the drill string; allows the string to rotate and makes a pressure-tight seal on the hole b. Kelly, i.e., a four- or six-sided pipe that transfers rotary motion to the turntable and drill string c. Turntable or rotary table drives the rotating motion using power from electric motors d. Drill string that consists of drill pipe (connected sections of about 30 ft=10 m) and drill collars larger diameter, heavier pipe that fits around the drill pipe and places weight on the drill bit) e. Drill bit(s) at the end of the drill that actually cuts up the rock and comes in many shapes and materials (tungsten carbide steel, diamond) that are specialized for various drilling tasks and rock formations Gowtham Books. 11 of 92.

(16) 4. Casing, which is a large-diameter concrete pipe that lines the drill hole, prevents the hole from collapsing, and allows drilling mud to circulate. 5. Circulation system—pumps drilling mud (mixture of water, clay, weighting material and chemicals, used to lift rock cuttings from the drill bit to the surface) under pressure through the kelly, rotary table, drill pipes and drill collars (Figure 1.7): a. Pump—sucks mud from the mud pits and pumps it to the drilling apparatus b. Pipes and hoses—connect pump to drilling apparatus c. Mud-return line—returns mud from hole d. Shale shaker—shaker =sieve that separates rock cuttings from the mud e. Shale slide—conveys cuttings to the reserve pit f. Reserve pit—collects rock cuttings separated from the mud g. Mud pits—where drilling mud is mixed and recycled h. Mud-mixing hopper—where new mud is mixed and then sent to the mud pits 6. Derrick—support structure that holds the drilling apparatus; tall enough to allow new sections of drill pipe to be added to the drilling apparatus as drilling progresses 7. Blowout preventer—high-pressure valves (located under the land rig or on the sea floor) that seal the high-pressure drill lines and relieve pressure, when necessary, to prevent a blowout (uncontrolled gush of gas or oil to the surface, often associated with fire). Gowtham Books. 12 of 92.

(17) DRILLING RIG COMPONENTS Although there are many variations in design, all modern rotary drilling rigs have essentially the same components (Figure 1.5). The hoisting, or draw works, raises and lowers the drill pipe and casing, which can weigh as much as 200 tons (200,000 kg). The height of the derrick depends on the number of joints of drill pipe to be withdrawn as a unit before being unscrewed. The rotary table located in the middle of the rig floor rotates the drill column. The table also gaps the drill stem when the hoist is disconnected and pipe sections are inserted or removed. It imparts rotary motion to the drill stem through the kelly attached to the upper end of the column. The kelly fits into a shaped hole in the center of the rotary table. The couplings between pipe sections are called tool joints. The drilling bit is connected to drill collars at the bottom of the stem. These are thick steel cylinders, 20 to 29 ft (6 to 9 m) long; as many as 10 may be screwed together. They concentrate weight at the bottom of the column and exert tension on the more flexible pipe above, reducing the tendency of the hole to go off-line and the drill pipe to fracture. Drill bits have many designs and the variations include the number of blades, type of metal, and shape of cutting or brading components. To lleviate the problem of dull wearout or jamming, a mudcirculating system is one of the most important parts of a rig (Ranney, 1979). This system maintains the drilling mud in proper condition, free of rock cuttings or other abrasive materials that might cause problems with the drilling operation, as well as retains the proper physical and chemical characteristics of the mud. DRILLING Drilling an oil well is tedious and is often accompanied by difficulties. Some problems result from formation penetration and the occurrence of high-pressure gas, fissures, or unexpected high pressures in permeable rock. Others result from metallurgical or mechanical failures in the bit, the drill stem, the draw works, or the mud system. Many tools and techniques have been developed to solve most problems; probably the best known is the fish used to recover broken bits. Another technique involves intentional deviation of the borehole to avoid difficult formations, to go around an unrecoverable fish, or sometimes to restore the direction of the hole after an accidental deviation. Once the rig is set up, drilling operations commence. First, from the starter hole, a surface hole is drilled to a preset depth, which is somewhere above the location of the oil trap. There are five basic steps to drilling the surface hole: 1. Place the drill bit, collar, and drill pipe in the hole 2. Attach the kelly and turntable and begin drilling 3. As drilling progresses, circulate mud through the pipe and out of the bit to float the rock cuttings out of the hole 4. As the hole increases in depth, add new sections (joints) of drill pipes 5. Remove (trip out) the drill pipe, collar and bit when the preset depth (anywhere from a few hundred to a couple-thousand feet) is reached. Gowtham Books. 13 of 92.

(18) When the preset depth is reached, the casing pipe sections are run into the hole and cemented to prevent the hole from collapsing. The casing pipe has spacers around the outside to keep it centered in the hole. The cement is pumped down the casing pipe using a bottom plug, a cement slurry, a top plug, and drilling mud. The pressure from the drilling mud causes the cement slurry to move through the casing and fill the space between the outside of the casing and the hole. Finally, the cement is allowed to harden and is then tested for such properties as hardness, alignment, and a proper seal. Drilling continues in stages and when the rock cuttings from the mud reveal the oil sand from the reservoir rock, the final depth may have been reached. At this point, the drilling apparatus is removed from the hole and tests are preformed to confirm that the final depth has been reached. These tests include the following: 1. Well logging: lowering electrical and gas sensors into the hole to take measurements of the rock formations there 2. Drill-stem testing: lowering a device into the hole to measure the pressures, which will reveal whether reservoir rock has been reached 3. Core sampling: taking samples of rock to look for characteristics of reservoir rock. Gowtham Books. 14 of 92.

(19) WELL COMPLETION Once the final depth has been reached, the well is completed to allow oil to flow into the casing in a controlled manner. First, a perforating gun is lowered into the well to the production depth. The gun has explosive charges to create holes in the casing through which oil can flow. After the casing has been perforated, a small-diameter pipe (tubing) is run into the hole as a conduit for oil and gas to flow up the well and a packer is run down the outside of the tubing. When the packer is set at the production level, it is expanded to form a seal around the outside of the tubing. Finally, a multivalve structure (the Christmas tree; Figure 1.8) is installed at the top of the tubing and cemented to the top of the casing. The Christmas tree allows them to control the flow of oil from the well.. Tight formations are occasionally encountered and it becomes necessary to encourage flow. Several methods are used, one of which involves setting off small explosions to fracture the rock. If the formation is mainly limestone, hydrochloric acid is sent down the hole to dissolve channels in the rock. The acid is inhibited to protect the steel casing. In sandstone, the preferred method is hydraulic fracturing. A fluid with a viscosity high enough to hold coarse sand in suspension is pumped at very high pressure into the formation, fracturing the rock. The grains of sand remain, helping to hold the cracks open.. Gowtham Books. 15 of 92.

(20) 1.3. RECOVERY TECHNIQUES. The recovery of hydrocarbons is basically a volume displacement process. When a volume of hydrocarbon is removed from the reservoir by production, it will be replaced by a volume of some fluid. Energy is expended in this process. Hydrocarbon recovery mechanisms may be divided into three categories: i) Primary Recovery ii) Secondary Recovery iii) Enhanced Recovery 1.3.1 Primary Recovery Primary recovery is “utilization of the natural energy of the reservoir to cause the hydrocarbon to flow into the wellbore.” Based on this definition, as long as the hydrocarbon flows into the wellbore, this is primary recovery, even if the hydrocarbon must be artificially lifted to the surface by pumps or some other process. There are many sources of this primary recovery energy of which three are dominant: a) Dissolved Gas Drive ( Solution Gas Drive ) b) Gas-Cap Drive c) Water Drive Dissolved Gas Drive When the reservoir is produced so that gas is permitted to escape from the hydrocarbon liquid in the reservoir, so that two-phase flow (gas and liquid ) occurs from the reservoir into the wellbore, the expanding gas will force the oil ahead of the gas into the wellbore. In order to maximize oil recovery, however, for most reservoirs it is desirable to prevent dissolved gas drive, at least until late in the productive life of the reservoir. As the reservoir approaches depletion, the flowing bottom hole pressures may be reduced to as low a value as possible, in order to recover whatever percentage of remaining hydrocarbons might flow into the wellbore, including solution gas from the oil which will remain in the reservoir (residual oil) at the time the reservoir is abandoned. Dissolved gas drive can be delayed by injecting water into the water zone beneath the oil. Gas-Cap Drive If a gas cap exists above the oil zone, and wells are drilled and perforated in the oil zone and the bottomhole pressures are sufficiently reduced, the expanding gas cap will force the oil into the wells as the gas interface encroaches into the oil zone. In order for gas-cap drive to exist as a primary recovery mechanism, the gas cap must exist naturally.. Gowtham Books. 16 of 92.

(21) Water Drive Most hydrocarbon reservoirs will have a water zone beneath the hydrocarbon. This water is tending to encroach into the oil zone. If wells are drilled and perforated in the oil zone, when the wellbore pressure is reduced, oil flow will be initiated into the well as water encroaches into the oil zone forcing the oil towards the producing wells. If this natural encroachment tendency is to exist, natural energy must be present. There are several possible sources of this natural energy. One source is the expansion of the water as a compressible fluid, as reservoir pressures are reduced. As the reservoir pressure is reduced, the expanding water will push the oil in front of it into the producing wells. Water expansion as a compressed liquid produces more oil than oil as a compressed liquid, not because the compressibility of water is much different to compressibility of oil, but because the total volume of water in the water zone is usually very large when compared to the total volume of oil in the oil zone. Another source of energy for water drive occurs when the reservoir rock dips upward to the surface where it outcrops. If permeability continuity exists through this rock, as oil is produced from the reservoir, water flows down dip from the surface to replace the oil volume removed. Surface water replenished that water, maintaining a constant hydrostatic pressure on the reservoir fluids.. Gowtham Books. 17 of 92.

(22) 1.3.2 Secondary Recovery Water Flood This is not water drive. In water drive, water is encroaching into the oil zone from beneath, but in a true water flood, water is injected down injection wells into the oil zone. Ideally, this creates a vertical flood front, pushing the oil in front of the water toward the producing wells. In a water flood, the water injection wells are placed relative to the oil producing wells in some predetermined pattern based on reservoir characteristics and production history. A common pattern for water flooding for large reservoirs which are basically horizontal reservoirs in the five spot pattern. This five spot pattern is repeated over the reservoir, Prior to the initiation of a water flood project for a reservoir. Various studies will have been made in designing the water flood. These might include model studies in the laboratory, digital and analog computer Simulations, and pilot floods may have been run in a portion of the reservoir as a preliminary study, so that an analysis of the water flood plan might be made. It is desirable to conduct the water flood so as to maximize the sweep efficiency within economic limits relative to production, so that when the water front from the injection wells breaks into the producing wells, a maximum percent of the reservoir volume will have been swept by the flood. Once this water front reaches the producing wells, further hydrocarbon production will be negligible, in that the wells will now produce essentially water. Whatever the technique used for recovery, it is desirable that the mobility ratio of driving fluid be less than the mobility ratio for the driven fluid. The mobility ratio is the ratio of the permeability to the flow of the liquid to the dynamic viscosity of that liquid. The oil ratio mobility ratio will be [ko/μo ] = Oil Mobility Ratio And, in the case of the water flood, the water mobility ratio of the water will be [kw/μw ] = Water Mobility Ratio If the mobility ratio of the driving fluid is greater than the mobility ratio of the driven fluid, the driving fluid will tend to channel or finger through the hydrocarbon, tending to bypass the hydrocarbon in the smaller permeability channels, leaving it behind in the reservoir. Gas –Cap Injection In the gas cap drive injection secondary recovery technique, gas is injected into the gas cap above the oil zone, to pressurize the gas cap. In reservoirs where reservoir fluid pressure is higher than the bubble point pressure, a gas cap may be created by gas injection so that the expending gas cap with further gas injection will displace the oil into the producing wells. As previously discussed, gas cap drive or gas cap drive enhancement is often used as a reservoir pressure maintenance technique.. Gowtham Books. 18 of 92.

(23) 1.3.3 Enhanced Recovery Processes that inject fluids other than natural gas and water to augment a reservoir’s ability to produce oil have been designated “improved,” “tertiary,” and “enhanced” oil recovery processes. The term used in this assessment is enhanced oil recovery (EOR). According to American Petroleum Institute estimates of original oil in place and ultimate recovery, approximately two-thirds of the oil discovered will remain in an average reservoir after primary and secondary production. This inefficiency of oil recovery processes has long been known and the knowledge has stimulated laboratory and field testing of new processes for more than 50 years. Early experiments with un-conventional fluids to improve oil recovery involved the use of steam (1920’s) and air for combustion to create heat (1935). Current EOR processes may be divided into four categories: (a) thermal, (b) miscible, (c)chemical, and (d) other.. a) Thermal Processes Viscosity, a measure of a liquid’s ability to flow, varies widely among crude oils. Some crudes flow like road tar, others as readily as water. High viscosity makes oil difficult to recover with primary or secondary production methods. The viscosity of most oils dramatically decreases as temperature increases, and the purpose of all thermal oil-recovery processes is therefore to heat the oil to make it flow or make it easier to drive with injected fluids. An injected fluid may be steam or hot water (steam injection), or air (combustion processes).. Steam Injection Steam injection is the most advanced and most widely used EOR process. It has been successfully used in some reservoirs in California since the mid-1960’s. There are two versions of the process: cyclic steam and steam drive. In the first, high-pressure steam or steam and hot water is injected into a well for a period of days or weeks. The injection is stopped and the reservoir is allowed to “soak.” After a few days or weeks, the well is allowed to backflow to the surface. Pressure in the producing well is allowed to decrease and some of the water that condensed from steam during injection or that was injected as hot water then vaporizes and drives heated oil toward the producing well.. Gowtham Books. 19 of 92.

(24) When oil production has declined appreciably, the process is repeated. Because of its cyclic nature, this process is occasionally referred to as the “huff and puff” method. The second method, steam drive or steam flooding, involves continuous injection of steam or steam and hot water in much the same way that water is injected in water flooding. A reservoir or a portion thereof is developed with interlocking patterns of injection and production wells. During this process, a series of zones develop as the fluids move from injection well to producing well. Nearest the injection well is a steam zone, ahead of this is a zone of steam condensate (water), and in front of the condensed water is a band or region of oil being moved by the water. The steam and hot water zone together remove the oil and force it ahead of the water. Cyclic steam injection is usually attempted in a reservoir before a full-scale steam drive is initiated, partially as a means of determining the technical feasibility of the process for a particular reservoir and partly to improve the efficiency of the subsequent steam drive. A steam drive, where applicable, will recover more oil than cyclic steam injection. Combustion Processes. Combustion projects are technologically complex, and difficult to predict and control. Injection of hot air will cause ignition of oil within a reservoir. Although some oil is lost by burning, the hot combustion product gases move ahead of the combustion zone to distill oil and push it toward producing wells. Air is injected through one pattern of wells and oil is produced from another interlocking pattern of wells in a manner similar to waterflooding. This process is referred to as fire flooding, in situ (in place) combustion, or forward combustion. Although originally conceived to apply to very viscous crude oils not susceptible to water flooding, the method is theoretically applicable to a relatively wide range of crude oils. An important modification of forward combustion is the wet combustion process. Much of the heat generated in forward combustion is left behind the burning front. This heat was used to raise the temperature of the rock to the temperature of the combustion. Some of this heat may be recovered by injection of alternate slugs of water and air. The water is vaporized when it touches the hot formation. The vapor moves through the combustion zone heating the oil ahead of it and assists the production of oil. b) Miscible Processes Miscible processes are those in which an injected fluid dissolves in the oil it contacts, forming a single oil-like liquid that can flow through the reservoir more easily then the original crude. A variety of such processes have been developed using different fluids that can mix with oil, including alcohols, carbon dioxide, petroleum hydrocarbons such as propane or propane-butane mixtures, and petroleum gases rich in ethane, propane, butane, and pentane. The fluid must be carefully selected for each reservoir and type of crude to ensure that the oil and injected fluid will mix.. The cost of the injected fluid is quite high in all known processes, and therefore either the process must include a supplementary operation to recover expensive injected fluid, or the injected material must be used sparingly. In this process, a “slug,” which varies from 5 to 50 percent of the reservoir volume, is pushed through the reservoir by gas, water (brine), or chemically treated brine to contact and displace the mixture of fluid and oil.. Gowtham Books. 20 of 92.

(25) Miscible processes involve only moderately complex technology compared with other EOR processes. Although many miscible fluids have been field tested, much remains to be determined about the proper formulation of various chemical systems to effect complete solubility and to maintain this solubility in the reservoir as the solvent slug is pushed through it. Because of the high value of hydrocarbons and chemicals derived from hydrocarbons, it is generally felt that such materials would not make desirable injection fluids under current or future economic conditions. For this reason, attention has turned to C02 as a solvent. Conditions for complete mixing of C02 with crude oil depend on reservoir temperature and pressure and on the chemical nature and density of the oil. c) Chemical Processes Three EOR processes involve the use of chemicals : surfactant/polymer, polymer, and alkaline flooding. Surfactant/Polymer Flooding Surfactant/poIymer flooding, also known as microemulsion flooding or micellar flooding, is the newest and most complex of the EOR processes. Surfactant/polymer flooding can be any one of several processes in which detergent-like materials are injected as a slug of fluid to modify the chemical interaction of oil with its surroundings. These processes emulsify or otherwise dissolve or partly dissolve the oil within the formation. Because of the cost of such agents, the volume of a slug can represent only a small percentage of the reservoir volume. To preserve the integrity of the slug as it moves through the reservoir, it is pushed by water to which a polymer has been added. The chemical composition of a slug and its size must be carefully selected for each reservoir/ crude oil system. Polymer Flooding. Polymer flooding is a chemically augmented waterflood in which small concentrations of chemicals, such as polyacrylamides or polysaccharides, are added to injected water to increase the effectiveness of the water in displacing oil.. Gowtham Books. 21 of 92.

(26) Alkaline Flooding. Water solutions of certain chemicals such as sodium hydroxide, sodium silicate, and sodium carbonate are strongly alkaline. These solutions will react with constituents present in some crude oils or present at the rock/crude oil interface to form detergent-like materials which reduce the ability of the formation to retain the oil. The few tests which have been reported are technically encouraging, but the technology is not nearly so well developed as those described previously.. Gowtham Books. 22 of 92.

(27) 1.4. Oil – Gas separation. The most commonly produced fluids and materials from oil wells are oil, gas, water (usually salt water), emulsions, and solids. Oil wells are generally classified as either high pressure wells or low pressure wells. If both well classifications are producing into a central gathering system, the high pressure wells will have their production directed to a high pressure manifold, and the low pressure wells will have their production directed to a low pressure manifold. Fluids produced from high pressure wells normally have a high solution gas-oil ratio, consequently resulting in a higher producing gas-oil ratio. There are several options for this gas, and the option selected will affect specifications for the surface processing equipment. The three most common options for the gas are: 1. Market the gas (or use the gas as a fuel at the location) 2. Re-inject the gas into the hydrocarbon reservoir from which it was produced or into some other reservoir. 3. Flare or vent the gas as waste. If significant gas is being produced, the third option is not normally permitted be government regulations, in that a natural resource would be destroyed, with adverse effect on the environment. Either of the first two options is more likely to be selected. Therefore, the surface system is designed so that gas produced at the surface is maintained as nearly as possible at the pipeline pressure or the re-injection pressure to minimize cost of recompression of the gas. The high pressure well production from the high pressure manifold will initially be directed through stage separators, so that gas is permitted to escape from the oil in stages. From each stage separator, gas, oil, salt water, emulsions and solids may be removed. The solids would tend to settle out due to gravity, but the liquids would essentially flow through each stage of separation, to the free water knockout essentially at atmospheric pressure (or at least at a relatively low pressure as compared to the wellhead pressure) The produced fluid from the low-pressure wells is taken through the same system, with the exception of the multi-stage separation process. The production from the low-pressure well is directed to a low-pressure manifold, from where it flows directly to the free water knockout. From that point to the transportation system, the process system is the same for high-pressure and low-pressure well production. The free water knockout is essentially a gravity separator with baffles to enhance the separation. The high velocity fluids flow into this separator and upon entry, the flow area is significantly greater, thereby reducing the velocity of flow and enhancing the gravity separation of fluids and other materials into their different densities. Solid particles transported from the reservoir will fall to the bottom of the system, with the fluids stratifying according to density (salt water on bottom, emulsion in the next layer, crude oil in the next layer, with gas rising to the top of the system). The water will contain droplets of oil, the oil droplets of water, and the gas both oil and water droplets, possibly in the form of a mist. As the fluids flow through baffling within the free water knockout, fluid droplets suspended within the other fluids will tend to coalesce, forming larger droplets and enhancing their gravity separation.. Gowtham Books. 23 of 92.

(28) As the separated fluids exist from the free water knockout, the salt water is removed from the bottom, oil and emulsions are removed from the top of the salt water, and gas is removed from the top. The water likely contains sufficient oil to prevent its being exhausted to the environment, and may require further processing to remove any remaining oil or other contaminants to a sufficiently low level to permit its disposal overboard, in the case of an offshore operation, into the surface environment, or reinjection into a subsurface formation through a salt water disposal system. The oil, and certainly the emulsion, flows from the free water knockout to an emulsion treater to break the emulsion and remove as much additional water as is practical. There are several different emulsion treating processes. Historically, one of the most common has been the heater treater, in that increased temperature will break the emulsion. The oil and the emulsion flows from the free water knockout into the heater treater, where it flows down the “down-comer” to the bottom of the heater treater. There it is exposed to the heater, thereby increasing its temperature. The increased temperature tends to break the emulsion with the heavier water moving downward and the lighter oil upward, through gravity separation. There may be baffling in the system through which the oil passes, further breaking the emulsion. The oil is skimmed from the top of the water and, if the processing system has serve its function, is then transported for storage or to the transportation system (pipeline, offshore tanker, rail cars etc.) Since the heater treater has increased the temperature of the system, additional gas is formed and is removed from the top of the heater treater, to be combined with the gas obtained from the free water knockout. It is then recompressed for transport or reinjection into the reservoir. The water from the emulsion treater must be transported for disposal.. If hydrogen sulfide (H2S) and/or carbon dioxide (CO2) are present in the produced fluid, they are normally removed from the oil and gas after exiting from the free water knockout, to minimize exposure of downstream processing systems to the corrosive environment which exists when H2S and/or CO2 is present. Dependent upon the volumes of H2S and/or CO2 produced, various removal systems are available. One of the most common is the amine system.. Gowtham Books. 24 of 92.

(29) Since the heater treater increases the temperature of the produced fluids, the API gravity as well as oil volume are both reduced, thereby reducing the value of the produced hydrocarbons. Therefore, other emulsion treater systems may be used. Others available include electrostatic emulsion treaters, chemical treatment to break the emulsions, and molecular sieves. The electrostatic treaters takes advantage of the fact that the H2O molecule is an electric dipole so that, when exposed to an electrostatic field there is an attraction for the water molecule, thereby enhancing separation from the hydrocarbon. The gas is removed from the stage separators, the free water knockout, and the emulsion treater will likely be directed to a dehydrator for further removal of H2O molecules. The dehydration process is the same as that process which will be discussed relative to production from gas wells. 1.5. Processing wet gases. The hydrocarbon gas leaving the gravity separator may contain too much H2O for transport, injection, or use as fuel. If this should be the case, it will pass to the dehydrator for removal of H2O molecules to an acceptably low level. This will usually be a glycol dehydrator, using components such as ethylene glycol, for removal of the H2O molecules from the hydrocarbon gas. The glycol molecule has a greater affinity (attraction) for the H2O molecule than does hydrocarbon. Glycol dehydration is therefore a relatively simple Operation.. The hydrocarbon gas is passed into the base of a glycol dehydration tower, where it rises, bubbling through trays containing glycol, exposing the hydrocarbon gas to as large a surface area of liquid glycol as is practical. As the hydrocarbon gas bubbles through the glycol, the H2O molecules are attracted to the glycol and are removed from the hydrocarbon gas, with the” dry” gas being removed from the top of the glycol tower. “Dry” glycol (glycol without the presence of H2O molecules) flows on a continuing basis into the top tray of the layered trays in the tower, and flows downward through the tower from one tray to the next, accumulating H2O molecules as the hydrocarbon gas bubbles through the glycol. By the time the glycol reaches the base of the tower, it is now “wet” glycol (glycol with a significant H2O molecular content). This process of removing the H2O molecules from the hydrocarbon gas has not been a chemical process, in that no chemical reactions have occurred. There have been no molecular changes. This “wet” glycol is removed from the base of the dehydration tower. The H2O molecules are then removed from the glycol as it is prepared for recirculation as “dry” glycol, back into the dehydration tower. Removal of the H2O molecules from the glycol is not complex,, since H2O boils at a lower temperature than does glycol. The “wet” glycol is taken to a temperature higher than the boiling point of H2O, yet lower than the boiling point of glycol, boiling the H2O molecules from the liquid glycol, leaving it “dry”. The “dry” glycol is then re-circulated back to the glycol dehydration tower.. Gowtham Books. 25 of 92.

(30) If hydrogen sulfide H2S and/or carbon dioxide (CO2) should be present in the production from the gas wells, the gas taken from the top of the gravity separator is taken through a process to remove the H2S and/or CO2 before dehydration. Several types of processes are available to remove the H2S and/or CO2, the most common being an amine system as mentioned in the discussion for processing the fluids produced by oil wells. H2S and CO2 molecules have a greater affinity (attraction) for amine molecules than for hydrocarbon molecules, so in a similar fashion to glycol removal of H2O molecules from hydrocarbon gas, the amine removes H2S and CO2 molecules. H2S and CO2 are corrosive in the presence of water; therefore it is desirable to remove them early in the processing system, to minimize exposure of downstream equipment to this corrosive environment.. Gowtham Books. 26 of 92.

(31) 1.6 Refining of crude oil. Petroleum refining is the separation of petroleum into fractions and the sub sequent treating of these fractions to yield marketable products. 1.6.1 DEWATERING AND DESALTING Before the separation of petroleum into its various constituent s can proceed, there is the need to clean the petroleum. This is often referred to as desalting and dewatering, in which the goal is to remove water and the constituents of the brine that accompany the cru de oil from the reservoir to the wellhead during recovery operations. Petroleum is recovered from the reservoir mixed with a variety of substances: gases, water, and dirt (minerals). Thus, refining actually commences with the production of fluids from the well or reservoir and is followed by pretreatment operations that are applied to the crude oil, either at the refinery or prior to transportation. Pipeline operators, for instance, are insistent on the quality of the fluids put into the pipelines; therefore, any crude oil to be shipped by pipeline or, for that matter, by any other form of transportation must meet rigid specifications with regard to water and salt content. In some instances, sulfur content, nitrogen content, and viscosity may also be specified. Field separation, which occurs at a field site near the recovery operation, is the first attempt to remove the gases, water, and dirt that accompany crude oil coming from the ground. The separator may be no more than a large vessel that gives a quieting zone for gravity separation into three phases: gases, crude oil, and water containing entrained dirt. Desalting is a water-washing operation performed at the production field and at the refinery site for additional crud e oil cleanup (Figure 1.10). If the petroleum from the separators contains water and dirt, water washing can remove much of the water-soluble minerals and entrained solids. If these crude oil contaminants are not removed, they can cause operating problems during refinery processing, such as equipment plugging and corrosion as well as catalyst deactivation. The usual practice is to blend crude oils of similar characteristics, although fluctuations in the properties of the individual crude oils may cause significant variations in the properties of the blnd over a period of time. Blending several crude oils prior to refining can eliminate the frequent need to change the processing conditions that may be required to process each of the crude oils individually. However, simplification of the refining procedure is not always the end result. Incompatibility of different crude oils, which can occur if, for example , a paraffinic crude oil is blended with heavy a sphaltic oil, can cause sediment formation in the unrefined feedstock or in the products, thereby complicating the refinery process.. Gowtham Books. 27 of 92.

(32) 1.6.2 DISTILLATION In the early stages of refinery development, when illuminating and lubricating oils were the main products, distillation was the major, and often only, refinery process. It is possible to obtain products ranging from gaseous materials taken off at the top of the distillation column to a nonvolatile residue or reduced crude (bottoms), with correspondingly lighter materials at intermediate points. The reduced crude may then be processed by vacuum, or steam, distillation in order to separate the high-boiling lubricating oil fractions without the danger of decomposition, which occurs at high (>3580C, >6600F) temperatures. Atmospheric distillation may be terminated with a lower-boiling fraction (cut), if it is felt that vacuum or steam distillation will yield a betterquality product, or if the process appears to be economically more favorable. Not all crude oils yield the same distillation products, and the nature of the crude oil dictates the processes that may be required for refining. Atmospheric Distillation The present-day petroleum distillation unit is, like the battery of the 1800s, a collection of distillation units but, in contrast to the early battery units, a tower is used in the modern-day refinery and brings about a fairly efficient degree of fractionation (separation). The feed to a distillation tower is heated by flow-through pipes arranged within a large furnace. The heating unit is known as a pipe still heater or pipe still furnace, and the heating unit and the fractional distillation tower make up the essential parts of a distillation unit or pipe still. The pipe still furnace heats the feed to a predetermined temperature—usually a temperature at which a predetermined portion of the feed will change into vapor. The vapor is held under pressure in the pipe in the furnace until it discharges as a foaming stream into the fractional distillation tower. Here, the unvaporized or liquid portion of the feed descends to the bottom of the tower to be pumped away as a bottom nonvolatile product, while the vapors pass up the tower to be fractionated into gas oils, kerosene, and naphtha.. Gowtham Books. 28 of 92.

(33) Pipe still furnaces vary greatly and, in contrast to the early units where capacity was usually 200 to 500 bbl per day, can accommodate 25,000 bbl, or more, of crude petroleum per day. The walls and ceiling are insulated with firebrick and the interior of the furnace is partially divided into two sections: a smaller convection section where the oil first enters the furnace and a larger section (fitted with heaters) where the oil reaches its highest temperature. Another twentieth century innovation in distillation is the use of heat exchangers which are also used to preheat the feed to the furnace. These exchangers are bundles of tubes arrange d within a shell, so that a feedstock passes through the tube s in the opposite direct ion from a heated feedstock passing through the shell. By this means, cold crude oil is passed through a series of heat exchangers where hot products from the distillation tower are cooled, before entering the furnace and as a heated feedstock. This results in a saving of heater fuel and is a major factor in the economical operation of modern distillation units.. Gowtham Books. 29 of 92.

(34) All of the primary fractions from a distillation unit are equilibrium mixtures and contain some proportion of the lighter constituents characteristic of a lower-boiling fraction. The primary fractions are stripped of these constituent s (stabilized) before storage or further processing.. Vacuum Distillation Vacuum distillation as applied to the petroleum refining industry is truly a technique of the twentieth century and has since wide use in petroleum refining. Vacuum distillation evolved because of the need to separate the less volatile products, such as lubricating oils, from the petroleum without subjecting these high -boiling pro ducts to cracking conditions. The boiling point of the heaviest cut obtainable at atmospheric pressure is limited by the temperature (ca. 3500C; ca. 6600F) at which the residue starts to decompose (crack). When the feedstock is required for the manufacture of lubricating oils, further fractionation without cracking is desirable and this can be achieve d by distillation under vacuum conditions. Operating conditions for vacuum distillation (Figure below) are usually 50 to 100 mm of mercury (atmospheric pressure - 760 mm of mercury). In order to minimize large fluctuations in pressure in the vacuum tower, the units are necessarily of a larger diameter than the atmospheric units. Some vacuum distillation units have diameters of the order of 45 ft (14 m). By this means, a heavy gas oil may be obtained as an overhead product at temperatures of about 1500C (3000F), and lubricating oil cuts may be obtained at temperature s of 2500C to 3500C (4800F to 6600F), feed and residue temperatures are kept below the temperature of 3500C (6600F), above which cracking will occur. The partial pressure of the hydrocarbons is effectively reduced still further by the injection of steam. The steam added to the column, principally for the stripping of asphalt in the base of the column, is superheated in the convection section of the heater .. Gowtham Books. 30 of 92.

(35) The fractions obtained by vacuum distillation of the reduced crud e (atmospheric residuum) from an atmospheric distillation unit depend on whet her or not the unit is designed to produce lubricating or vacuum gas oils. In the former case, the fractions include (1) heavy gas oil, which is a n overhead product and is used as catalytic cracking stock or, after suitable treatment, a light lubricating oil, (2) lubricating oil (usually three fractions—light , inter mediate, and heavy), which is obtained as a side- stream product, and (3) asphalt (or residuum), which is the bottom pro duct and may be used directly as, or to produce, asphalt and which may also be blended with gas oils to produce a heavy fuel oil. In the early refineries, distillation was the prime means by which pro ducts were separated from crud e petroleum. As the technologies for refining evolved into the twentieth century, refineries became much more complex, but distillation remained the prime means by which petroleum is refined. Indeed, the distillation section of a modern refinery is the most flexible section in the refinery, since conditions can be adjusted to process a wide range of refinery feedstocks from the lighter crude oils to the heavier more viscous crude oils. However, the maximum permissible temperature (in the vaporizing furnace or heater) to which the feedstock can be subjected is 3508C (6600F). Thermal decomposition occurs above this temperature which, if it occurs within a distillation unit, can lead to coke deposition in the heater pipes or in the tower itself with the resulting failure of the unit. The contained use of atmospheric and vacuum distillation has been a major part of refinery operations during this century and no doubt will continue to be employed throughout the remainder of the century as the primary refining operation.. Gowtham Books. 31 of 92.

(36) Azeotropic and Extractive Distillation As the twentieth century evolved, distillation techniques in refineries became more sophisticated to handle a wider variety of crude oils, to produce marketable products or feedstocks for other refinery units. However, it became apparent that the distillation units in the refineries were incapable of producing specific product fractions. In order to accommodate this type of product demand, refineries have, in the latter half of the twentieth century, incorporated azeotropic distillation and extractive distillation in their operations. All compounds have definite boiling temperatures, but a mixture of chemically dissimilar compounds will sometimes cause one or both of the components to boil at a temperature other than that expected. A mixture that boils at a temperature lower than the boiling point of any of the components is an azeotropic mixture. When it is desired to separate close-boiling components, the addition of a nonindigenous component will form an azeotropic mixture with one of the components of the mixture, thereby lowering the boiling point by the formation of an azeotrope and facilitate separation by distillation.. The separation of these components of similar volatility may become economic if an entrainer can be found that effectively changes the relative volatility. It is also desirable that the entrainer be reasonably cheap, stable, nontoxic, and readily recoverable from the components. In practice, it is probably this last-named criterion that limits severely the application of extractive and azeotropic distillation. The majority of successful processes are those in which the entrainer and one of the components separate into two liquid phases on cooling if direct recovery by distillation is not feasible. A further restriction in the selection of an azeotropic entrainer is that the boiling point of the entrainer be in the range of 100C to 400C (180F to 720F) below that of the components.. Gowtham Books. 32 of 92.

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