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Gas engineering

  1. 1. PETROLEUM GAS PROCESSING (CHEM 433) ZIN EDDINE DADACH 1
  2. 2. COURSE INTRODUCTION  This course is designed to cover the fundamentals of the gas process operations in the petroleum industry  An overview of gas processing from exploration to final production and transportation as well as gas properties calculations are included. 2
  3. 3. COURSE FOCUS  The course focuses on the principles of  Natural Gas Liquids (NGL)* extraction  Liquid Petroleum Gas (LPG)** fractioning  Liquid Natural Gas production (LNG)  Some design aspects of major unit process operation. 3
  4. 4. FUNDAMENTALS  To understand this course, knowledge of the basic fundamentals principals and terminology a plus.  Review of basic terminologies follows: 4
  5. 5. BASIC TERMINOLOGY (QUICK REVIEW)  Matter is the physical material that makes up the universe; anything that has mass and occupies space.  Elements, Atoms, Molecules, Chemical compounds, and Mixtures. 5
  6. 6. ELEMENT  A chemical element, or an element, is a material which cannot be broken down or changed into another substance using chemical means.  Elements may be thought of as the basic chemical building blocks of matter.  Depending on how much evidence you require to prove a new element has been created, there are 117 or 118 known elements. 6
  7. 7. ATOM  All substances are made up of matter and the fundamental unit of matter is the atom. The atom constitutes the smallest particle of an element which can take part in chemical reactions and may or may not exist independently.  N. Bohr (1940) provided the modern concept of the atomic model. According to Bohr, the atom is made of a central nucleus containing protons (positively- charged) and neutrons (with no charge). The electrons (negatively-charged) revolve around the nucleus in different imaginary paths called orbits or shells. 7
  8. 8.  Valence shell: the outer most electron shell of an atom  Valence electron: an electron in the outermost shell (very important because these are the electrons that causes chemical reactions to occur.  They are represented by the group number in the periodic table. 8
  9. 9. BASIC TERMINOLOGY (QUICK REVIEW)  Periodic table. 9
  10. 10. BASIC TERMINOLOGY (QUICK REVIEW)  Atomic Mass (weight): mass of 1 mole of an atom (listed in the periodic table) e.g. the atomic mass of Al = 27g/mole (or 27g/gmole)  1 mole contains 6.0022 x 10 23 atoms  For Aluminum (Al) this means 27 g of aluminum contains 6.0022 x 10 23 atoms of aluminum *  In other words 6.0022 x 10 23 atoms of Al weighs 27g (**question, why not use the weight of 1 atom of aluminum in the periodic table?) 10
  11. 11. MOLECULE  Two or more atoms chemically combined.  Diatomic molecule: is a molecule that is formed by a combination of 2 atoms of the same element, e.g. N2, O2, H2. 11 H-H H-H H-H H-H H-H H-H H-H Compound Diatomic molecule
  12. 12. BASIC TERMINOLOGY (QUICK REVIEW)  Going back:  Atomic Mass (weight) is the mass of 1 mole of an atom  E.g. The atomic weight of Al is 27 g/g-mole (this is from the periodic table)  Molecular Mass (weight) is the mass of 1 mole of ? *  E.g. The molecular weight of H2O is? ** 12
  13. 13. PHYSICAL COMPOUNDS  Clathrate, is a chemical substance consisting of a lattice of one type of molecule trapping and containing a second type of molecule  A type of physical compound, called a clathrate, may be formed. A gas hydrate is one example of a clathrate. These compounds are relatively unstable  An example of a clathrate is clathrate hydrate, a special type of gas hydrate* in which a lattice of water molecule encloses molecules of trapped gas. 13
  14. 14. CLATHRATE HYDRATE14
  15. 15. CHEMICAL COMPOUND  Hydro carbon: Any compound made of carbon and hydrogen atoms.  These atoms can combine in a number of ways to satisfy valence requirements.  For convenience, these are separated into families (or homologous) series, each of which is given a name.  Carbon atoms can link together to form “chains” or “rings”  Crude oil and natural gas mixtures consist primarily of “straight chain” hydrocarbon molecules, the bulk of which are PARAFFINS*. 15
  16. 16. 1) PARAFFIN SERIES FORMULA: CNH2N+2  Hydrocarbons in this series are saturated compounds because all four bonds are connected either to another carbon atom or a hydrogen atom, with one such atom for each bond.  In Paraffin (CnH2n+2 ) the # of hydrogen atoms is 2 times the # of carbon atoms plus 2 more for the end of the chain.  Name of paraffin compounds end with an “ane” 16 CH4 C2H6 C3H8
  17. 17. PARAFFIN SERIES FORMULA: CNH2N+2 (CONTINUED)  * Just note and recall that Paraffin hydrocarbons are the most stable because all valence bonds are fully satisfied as indicated by the single line linkage.  Most reactions involve the replacement of hydrogen atoms with other atoms; the carbon linkage remains stable.  Longer chain may be formed, however, the only ones normally identified by name contain ten or less carbons.  Just note that in referring to a given paraffin hydrocarbon, the abbreviation C3 for propane, C4 for butane, etc may be used but,  Statements like “propane plus fraction ( C3 +) refer to a mixture composed of propane and larger molecules. 17
  18. 18. PARAFFIN ISOMERS  When paraffin series molecule contains four or more carbon atoms there are different ways these ca be connected without affecting the formula  Compounds which have the same chemical formula but a different molecular structure are called isomers  They posses different physical and chemical properties. 18
  19. 19. 2) OLEFIN OR ETHYLENE SERIES (ALKENES) FORMULA: CNH2N  The olefin group of compounds is a simple straight chain series in which all the names end in –ene.  Ethylene (ethene) C2H4 is the simplest molecule in the series.  Hydrocarbon in this series combine easily with other atoms like chlorine and bromine, without the replacement of hydrogen atoms.  Since they are so reactive, they are called unsaturated hydrocarbons. 19
  20. 20. 2) OLEFIN OR ETHYLENE SERIES (ALKENES) FORMULA: CNH2N (CONTINUED)  Unlike the paraffins, the maximum bonding capacity of the carbon atom is not fully satisfied by hydrogen or carbon atoms.  Two adjacent carbon atoms form a “temporary” bond (in the absence of other available atoms) to meet bonding requirements fixed by valence.  The structural formula for the olefins uses a double line to indicate the double carbon-carbon linkage, the most reactive point in the molecule.  With four or more carbons, isomers also may result from the position of the double bond. 20
  21. 21. 3) ACETYLENIC OR ALKYNE SERIES FORMULA CNH2N - 2  Acetylene (systematic name: ethyne) is the chemical compound with the formula C2H2. It is a hydrocarbon and the simplest alkyne. This colorless gas is widely used as a fuel and a chemical building block. It is unstable in pure form and thus is usually handled as a solution.   It has the formula C2H2. 21
  22. 22. 3) ACETYLENIC OR ALKYNE SERIES FORMULA CNH2N – 2 (CONTINUED)  There is a triple bond between the carbon atoms.  This satisfies the valence requirements but the carbon linkage is very weak.  Therefore Acetylene is even more reactive than olefins.  Acetylene not only is unsaturated, it is also unstable chemically.  In the liquid state is explosive if subjected to a sudden shock 22
  23. 23. 4) DIOLEFINS FORMULA CNH2N - 2  Same formula as acetylene but contain two double linkages.  Di-ethene or di-butene 23
  24. 24. ORIGIN OF GAS AND OIL 24
  25. 25. THE ORIGIN OF PETROLEUM GAS The organic theory:  According to the original theory, oil originates from animals and plants.  Beds of silt (containing tiny organisms), mud, and sand were buried deep beneath the earth.  The deepest layers were turned into rock by the weight of the deposited earth layers.  Geologists believe that high heat and pressure, bacteria, chemical reactions, and other forces transformed the organic remains into oil and gas. 25
  26. 26. The Inorganic Theory:  Hydrocarbons are formed by combination of carbon and hydrogen in the earth rocks due to the influence of high temperature and pressure 26
  27. 27. GEOLOGICAL CONDITIONS FOR OIL AND GAS FORMATION  Most oil and gas accumulates in sedimentary rocks.  *Sedimentary rocks are one of three main rock groups (the others are igneous and metamorphic)  Sedimentary rocks include common types such as chalk, limestone, dolomite, sandstone, conglomerate and shale. 27
  28. 28. SEDIMENTARY ROCK IMAGES (CHALK)28
  29. 29. SEDIMENTARY ROCK IMAGES (LIMESTONE) 29
  30. 30. SEDIMENTARY ROCK IMAGES (DOLOMITE) 30
  31. 31. SEDIMENTARY ROCK IMAGES (SANDSTONE) 31
  32. 32. SEDIMENTARY ROCK IMAGES (CONGLOMERATE ) 32
  33. 33. SEDIMENTARY ROCK IMAGES (SHALE ) 33
  34. 34. GEOLOGICAL CONDITIONS FOR OIL AND GAS FORMATION (CONTINUED)  Many people think that an oil or gas reservoir is a large underground container filled with oil or gas  Some people think its like an underground river.  In reality a petroleum or gas reservoirs is a rock formation that holds oil and gas, somehow like a sponge holding water.  Physically a large reservoir can be wide and shallow, narrow and deep or somewhere in between. 34
  35. 35. RESERVOIR ROCKS  A petroleum reservoir, or oil and gas reservoir, is a subsurface pool of hydrocarbons contained in porous or fractured rock formations. The naturally occurring hydrocarbons, such as crude oil or natural gas, are trapped by overlying rock formations with lower permeability. Reservoirs are found using hydrocarbon exploration methods.  Porosity and permeability are important factors in reservoir formation. (QESTION) what's the difference between porosity and permeability? (next slide) 35
  36. 36. STRUCTURAL TRAPS  Structural traps are formed by a deformation in the rock layer that contains the hydrocarbons. Domes, anticlines, and folds are common structures. Fault-related features also may be classified as structural traps if closure is present.  Structural traps are the easiest to locate by surface and subsurface geological and geophysical studies.  They are the most numerous among trapsand have received a greater amount of attention in the search for oil than all other types of traps. 36
  37. 37. STRUCTURAL TRAP ( FOLD)37
  38. 38. STRUCTURAL TRAP (FAULT)38
  39. 39. STRATIGRAPHIC TRAPS  Stratigraphic traps are formed when other beds seal a reservoir bed or when the permeability changes (facies change) within the reservoir bed itself. Stratigraphic traps can form against either younger or older time surfaces. 39
  40. 40. POROSITY AND PERMEABILITY  Porosity is the ratio of the volume of opening (voids) to the total volume of material. (e.g. Shale is less porous and carbonate is more porous)  Permeability is a measure of the ease with fluids will flow through rock, sediment or soil ( a rock is permeable when the pores are connected)  Just as with porosity, the packing, shape, and sorting of granular materials control their permeability. Although a rock may be highly porous, if the voids are not interconnected, then fluids within the closed, isolated pores cannot move. 40
  41. 41. PORES IN ROCKS41
  42. 42. POROSITY AND PERMEABILITY (CONTINUED) REAL ROCK IMAGE 42
  43. 43. ROCK TYPE DISTRIBUTION IN THE EARTH CRUST AND OIL AND GAS PRODUCTION BY ROCK TYPE*. 43 Carbonates Sandstone Shale Distribution of rock types 42% 37% 21% Sandstone Carbonates (more pores) * Miscellaneous Production by rock types 61.5% 36% 2.5% Class of sedimentary rocks composed primarily of carbonate minerals. Two major types are: 1) Limestone (CaCO3) 2) Dolomite [CaMg(CO3)2]
  44. 44. RESERVOIR ROCKS (EROSION AND DEFORMATION)  For a rock to be an effective reservoir, it must contain adequate porosity and permeability that is properly sealed against erosion and tectonic (movement) destruction.  Many reservoirs and traps have been generated and eliminated by erosion and deformation. They are called dead oil. 44
  45. 45. OIL RESERVOIR45
  46. 46. GENERATION OF CRUDE OIL  Organic material in shale averages approximately 1% of the shale rock volume. Clay mineral constituents comprise the remaining 99 percent (some shale has greater concentrations some lower)  Kerogen* is an insoluble, high molecular weight, polymeric (i.e. consisting of a polymer) compound which comprises about 90% of the organic material in shale/rock.  The remaining 10% is bitumen** of varying composition, which is believed to be altered kerogen. (See diagram next slide) 46
  47. 47. GENERATION OF CRUDE OIL (CONTINUED) 47 Mineral Material 99% Shale (rock) Organic Material 1% Kerogen 90% Organic Material Bitumens 10% Percentage of (mineral and organic material), and (bitumen and kerogen), and (mineral material) in rock
  48. 48. KEROGEN AND KEROGEN TYPES  Labile kerogen breaks down to form heavy hydrocarbons (i.e. oils), refractory kerogen breaks down to form light hydrocarbons (i.e. gases) and inert kerogen forms graphite.  A Van Krevelen diagram is one example of classifying kerogens, where they tend to form groups when the ratios of hydrogen to carbon and oxygen to carbon are compared. 48
  49. 49. KEROGEN TYPE 1&2  Type I  Hydrogen:Carbon ratio > 1.25  Oxygen:Carbon ratio < 0.15  Tend to produce oil.  Type II  Hydrogen:Carbon ratio < 1.25  Oxygen:Carbon ratio 0.03 to 0.18  Tend to produce a mix of gas and oil. 49
  50. 50. KEROGEN TYPE 2 SULFUR AND TYPE 3  Type II-Sulfur  Similar to Type II but high in sulfur.  Type III  Hydrogen:Carbon ratio < 1  Oxygen:Carbon ratio 0.03 to 0.3  Material is thick, resembling wood or coal.  Tend to produce gas. 50
  51. 51.  Type IV (residue)  Hydrogen:Carbon < 0.5 51
  52. 52. MIGRATION OF CRUDE OIL  Even though shale is relatively impermeable, oil is created in its pores.  As tectonic forces moves the petroleum forming rocks out of there birthplace, great pressures from overlying formations squeeze the petroleum out of the relatively impermeable shale into cracks and into more permeable formations such as sandstone (i.e. carbonate rocks) 52
  53. 53. SUMMARY (OIL MIGRATION) 53 Original Organic Matter Graphite Kerogen Mature Kerogen Crude Oil Methane Losing Hydrogen Gaining Hydrogen
  54. 54. OIL AND GAS TRAPS  If the rock containing the oil is very pores and very permeable, petroleum will escape.  Something must stop the oil from escaping and migrating.  A trap is any combination of physical factors that promotes accumulation and retention of the petroleum in one location (its an arrangement of rocks that contained hydrocarbons) * 54
  55. 55. OIL AND GAS TRAPS55
  56. 56. CLASS WORK TO BE SUBMITTED (USE THE INTERNET) 1. Traps can be grouped into three basic types? Name them. 2. How is an anticline trap formed? 3. What is a seal? 4. Scan or sketch figures showing common structural traps. 5. Sketch a dome trap showing the oil and water layers. 6. What is a plug trap is? 7. What causes a stratigraphic trap to form? Scan or sketch relevant figures. 56
  57. 57. OIL AND GAS TRAPS (CONTINUED) ANSWERS 57 Structural Trap Stratigraphic Trap *ANSWERS 1)3 type of traps • Structural traps: Occurs due to the deformation of a reservoir (includes: anticline traps , fault traps and dome plug traps) • Stratigraphic traps: Occurs when porosity and permeability changes within a formation • Combination
  58. 58. OIL AND GAS TRAPS (CONTINUED) ANSWERS 2) In an anticline trap the rock layers that were originally laid down horizontally were folded upward into an arc or dome. 3) Seal is formed when a fault occurs. 58 B
  59. 59. OIL AND GAS TRAPS (CONTINUED) ANSWERS 4) Scan or sketch figures showing common structural traps.59
  60. 60. OIL AND GAS TRAPS (CONTINUED) ANSWERS 5) A sketch of a dome trap showing the oil and water layers.60
  61. 61. OIL AND GAS TRAPS (CONTINUED) ANSWERS 6) Plug trap: Oil and gas are also found associated with domes. A dome that has a core of rock, called plug, that has pushed into the other formation may create a plug trap. Usually a plug is made of nonporous salt that has pierced, deformed, or lifted the overlaying strata. 61
  62. 62. OIL AND GAS TRAPS (CONTINUED) ANSWERS 7) Stratigraphic trap is caused either by a nonporous formation sealing off the top edge of a reservoir bed or by a change of porosity and permeability within the reservoir bed itself. 62
  63. 63. EXPLORATION METHODS 63
  64. 64. EXPLORATION METHODS  Exploration was ones a matter of good luck and guess work  Now it uses many techniques and scientific principles  Most successful method was to drill near and oil seeps* (where oil is actually present on the surface)  Today, surface and subsurface, study is the leading technology in discovering oil and gas.  Aerial and satellite images and other instrumentation are used to gather information that helps determine where to drill.  Then specialist examine the rock fragments and core samples brought up while drilling the well and running special tools into the hole to get more information about the formation and possible oil or gas traps. 64
  65. 65. EXPLORATION METHODS (CONTINUED)  Finally examining, correlating and interpreting the information and the data makes it possible for the oil companies to accurately locate structures that may contain hydrocarbon and if the hydrocarbons are worth exploiting. 65
  66. 66. EXPLORATION METHODS SUMMARY Exploration methods include: 1) Surface geological studies 2) Oil and gas seeps. 3) Geophysical surveys (e.g. seismic surveys) 4) Reservoir development tools 66
  67. 67. CLASS WORK Surface geological studies include areal photographs and satellite images. List at least 2 types of equipment used to take images, and explain briefly what information each equipment gives. 1) Explain what oil and gas seeps are? 2) Geophysical surveys includes the use several methods listed below, briefly explain each method and list any sub methods.  Magnetic and electromagnetic surveys (list each one and explain)  Gravity surveys  Seismic surveys (VERY IMPORTANT)  3D seismic surveys  Explosive Methods  Modern land methods  Marine Seismic Methods. 67
  68. 68. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION)  Answers: 1) 2 types of equipment used to take images:  LandSat:  Landsat satellites have mapped all the earth's land masses this is continuously done.  The purpose is to primarily map vegetation and observe long-term changes to the earths surface.  LandSat also carry sensors especially built for geological application  It provides visible, thermal, and infrared images of all land-masses and coastal areas.  Landsat data is then interpreted and enhanced  Explorationists can then buy the data.  Radar  Radar devices bounce high frequency radio waves off land features to a satellite or airplane.  Returned signals form a low-resolution relief map (map of a terrain- topography like)  It is useful in searching areas for potential oil-trapping structures at a glance (diagram on next page) 68
  69. 69. EXAMPLE OF A RADAR RELIEF MAP 69
  70. 70. OIL AND GAS SEEPS  Seeps are oil and gas that come to the surface along porous beds or faults. They are marked and well- documented worldwide. 70
  71. 71. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION) [CONTINUED] 2 71 Crude oil seep Gas seep
  72. 72. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION) [CONTINUED] 3) Geophysical surveys include:  Magnetic and electromagnetic surveys (list each one and explain):  Magnetometer surveys: detects slight variation in the earths magnetic field which results in predicting the characteristics of overlaying sediments.  Magnetotellurics: Works on the theory that rocks of different composition have different electrical properties. It measures the naturally occurring flow of electricity between rocks then reveals subsurface structures based on the electrical data. 72
  73. 73. GRAVITY SURVEYS  Gravity surveys (e.g. of an equipment used is gravimeter or gravity meter):  It works on the theory that some rocks are denser than others which causes a slight variation in the earth's gravitational field.  For example scientists can locate salt domes based on gravitational methods since salt domes are usually associated with minimum gravity compared, for example, with ordinary and anticline domes. (EXAMPLE ON NEXT SLIDE) 73
  74. 74. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION) [CONTINUED] 74
  75. 75.  Seismic surveys  Seismic exploration utilizes an acoustic (sound) source such as an artificial earthquake ( or dynamite explosion).  Acoustic waves travel through the formation and reflect back to a detector (called geophones) where travel time is measures.  The geophones send the signals to a recorder (called a seismograph) where the signals are magnified and a seismogram is produced.  * 75 Class exercise (Answers, Discussion and explanation) [Continued]
  76. 76.  Correlations of the records produce a two dimensional cross-section that illustrates the reflections and demonstrates the subsurface structures. (See also the diagram on the wall) - (See Diagram on next slide for set up) 76
  77. 77. Seismic surveys (continued) – Set-Up  Reflected and refracted seismic  Seismic exploration 77 Class exercise (Answers, Discussion and explanation) [Continued]
  78. 78. Seismic surveys (continued) – Set-Up  Seismic line showing productive anticline in lower sediments. 78 Class exercise (Answers, Discussion and explanation) [Continued]
  79. 79.  Seismic surveys (continued) more photos 79 Class exercise (Answers, Discussion and explanation) [Continued]
  80. 80. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION) [CONTINUED]  3D seismic survey:  In this method many seismic surveys are ran close to each other to create a series of seismic sections of an area.  Computer programs paste the section together to form a cubic image of the area.  Explosive Methods  Early seismic method using dynamite to create seismic vibration.  Modern Land Methods  In general newer methods have replaced dynamite to create vibration in the earth*. For example Vibroseis which generates continuous low- frequency sound waves. 80
  81. 81. CLASS EXERCISE (ANSWERS, DISCUSSION AND EXPLANATION) [CONTINUED]  Marine Seismic Methods:  It uses similar equipment as exploration on land but uses it on a ship. (End of exercise) 81
  82. 82. WELL LOGS AND SAMPLE LOGS 82
  83. 83. RESERVOIR DEVELOPMENT TOOLS  When a surface and subsurface information of a formation indicates a strong possibility of hydrocarbon existence, an oil company may then drill an exploratory well or wells  As the drilling progresses, underground rocks are then tested by means of core sampling and well logs.  The gathered data determines whether the reservoir has enough oil or gas to justify completing the exploration and then production. 83
  84. 84. RESERVOIR DEVELOPMENT TOOLS (CONTINUED)  Well logs are records that give information about the formation through which a well has been drilled.  The log gives the geophysical and other information of a well per depth. 84
  85. 85. TYPES OF WELL LOGS 1) Well Logs:  Driller’s log  Wireline log 2) Sample logs:  Core Samples  Cutting Sample 85
  86. 86. 1) WELL LOGS  Driller log:  It’s the most common log where the log contains information about the kind of rocks and fluids encountered at different depths.  It gives also gives information when the formation is altered from soft to hard rock.  It gives an idea of how long it takes to drill the well (for future drilling purposes)  Gives other formation issues encountered during drilling. 86 JPEG Image
  87. 87. 1) WELL LOGS [CONTINUED]  Wireline logs:  A wireline is a metal cable (line) that run through the well hole with several tools attached to it.  Each tool takes a different measurement.  Each measurement gives an indirect information about the formation down the well.  Wireline logging often involves complex calculations and interpretations of the data provided from the tool.  Oil service companies (e.g. Schlumberger, Baker Atlas, Halliburton) uses the information to decide if the oil or gas in the well is economically feasible. 87
  88. 88. 1) WELL LOGS [CONTINUED]  There are different types of wireline logs: a) Electrical Logs b) Nuclear Logs c) Acoustic Logs 88
  89. 89. A) ELECTRICAL LOGS  *Induction Log: records conductivity (weak current) that flows naturally in the rocks. It gives an idea about the thickness and boundary of each layer in the borehole. (called spontaneous potential log i.e. SP log)  Resistivity Log: records resistance in the borehole (hydrocarbons do not conduct electricity while all waters do) 89 1) Well Logs [continued]
  90. 90. B) NUCLEAR LOGS  Gamma ray log:  measures radioactivity to determine what type of rocks are present in the well.  For example shale emits more radioactive elements than sandstone.  Neutron log:  The tool sends atomic particles (neutrons) through the formation.  When the neutrons collide with hydrogen, the hydrogen slows them down.  When the detector records slow neutrons, it means that there more hydrogen is present (i.e. maybe more hydrocarbons than water) 90 1) Well Logs [continued]
  91. 91. C) ACOUSTIC LOGS  It gives information about the density of the rocks (how dense the rock is)*  The acoustic or sonic log records how fast sound travels through a rock.*  The speed of sound traveled depends on how dense a formation is, and how much fluid it contains. Example: shale is less porous therefore the sound will travel faster and you will get a high acoustic signal back. (E.g. of signal on the board) 91 1) Well Logs [continued]
  92. 92. C) ACOUSTIC LOGS (CONTINUED)  The probe contains a single transmitter at the base of the probe and two receivers located above the transmitter. 92 1) Well Logs [continued]
  93. 93. SAMPLE LOGS Sample logs:  Core Samples  Cutting Sample 93
  94. 94. CORE SAMPLES 1) A core is a cylindrical column of rock that shows the sequence of rocks as they appear within the earth. 2) It provides the most accurate information about the underground formation about Porosity, permeability, composition, fluid content, and geological age. 94
  95. 95. CUTTING SAMPLES  As a regular bit drills a hole, it breaks up the rock into pieces called cuttings. The cuttings flow out of the hole where geologists can use them to analyze the rock being drilled.  Since cuttings are fragments of rocks and do not form a continuous sample like a core, they are not as useful cores are to the geologists.  Cuttings may not all come from the bottom of the hole but may include pieces of formations that have sloughed off closer to the surface.  Even with these limitations, however, cuttings can provide useful data and are regularly examined during drilling. 95
  96. 96. Homework by internet (10%) to be submitted February 27th Based on the information of the handouts and using the internet, write a report about the oil and gas reservoirs: a) How they are formed? b) How they can be trapped? c) The exploration techniques ( surface and sub-surface analysis) d) The logs used to analyze them (drilling techniques) e) Attach all the documents used. 96
  97. 97. THE DIFFERENT TYPES OF GASES 97
  98. 98. ASSOCIATED GAS A mixture of petroleum gases that range from methane to butane and traces of liquid condensate (pentane to heptane) It is produced from an oil well dissolved in the oil. It is separated from the oil by liquid-gas separator in the degassing station. The gas contains non-hydrocarbon gases such as CO2 and H2S as well as some 98
  99. 99. TYPICAL PROCESS OF AN ASSOCIATED GAS 99
  100. 100. NON-ASSOCIATED GAS  Gas occurring alone as natural gas, not in solution or as free gas with oil or condensate.  It contains mainly methane and ethane. It may also contains impurities such as CO2 , H2S and water 100
  101. 101. WET AND DRY GAS  Natural gas is often found dissolved in oil at the high pressures existing in a reservoir.  It can be present as a gas cap above the oil. Such natural gas is known as associated gas. There are also reservoirs that contain gas and no oil. This gas is termed non- associated gas.  Associated gas usually contains some light liquids and hence is sometimes called “wet gas.”  Non-associated gas, coming from reservoirs that are not connected with any known source of liquid petroleum, is “dry gas.” 101
  102. 102. SOUR AND ACID GAS  Sour gas is natural gas or any other gas containing significant amounts of hydrogen sulfide (H2S).  Natural gas is usually considered sour if there are more than 5.7 milligrams of H2S per cubic meter of natural gas, which is equivalent to approximately 4 ppm by volume[1].  On the other hand, natural gas that does not contain significant amounts of hydrogen sulfide is called "sweet gas.")  any gas that contains significant amounts of acidic gases such as carbon dioxide (CO2) or hydrogen sulfide.  Thus, carbon dioxide by itself is an acid gas but it is not a sour gas. 102
  103. 103. GAS SWEETENING  Before a raw natural gas containing hydrogen sulfide and/or carbon dioxide can be used, the raw gas must be treated to remove those impurities to acceptable levels, commonly by an amine gas treating process.[1][2]  The removed H2S is most often subsequently converted to by-product elemental sulfur in a Claus process or it can be treated in a WSA Process unit where the by-product is sulfuric acid. 103
  104. 104. ACID REMOVAL BY ABSORPTION 104
  105. 105. LNG, LPG AND NGL 105
  106. 106. WHAT IS LNG?  Liquefied natural gas, or LNG, is natural gas that has been supercooled to minus 260 degrees Fahrenheit (minus 162 degrees Celsius).  At that temperature, natural gas condenses into a liquid. When in liquid form, natural gas takes up to 600 times less space than in its gaseous state, which makes it feasible to transport over long distances.  In the form of LNG, natural gas can be shipped from the parts of the world where it is abundant to where it is in demand. 106
  107. 107.  LNG is an energy source that has much lower air emissions than other fossil fuels, such as oil or coal.  LNG is odorless, colorless, non-corrosive and non-toxic. Its weight is less than one-half that of water.  Natural gas is the world’s cleanest burning fossil fuel and it has emerged as the environmentally preferred fuel of choice. 107
  108. 108. NATURAL GAS COMPOSITION  The primary component of natural gas is methane (CH4), the shortest and lightest hydrocarbon molecule.  Natural gas as a fossil fuel also contains heavier gaseous hydrocarbons such as ethane (C2H6), propane (C3H8) and butane (C4H10), as well as carbon dioxide and sulfur- containing gases in varying amounts.  Fossil natural gas also contains in varying amounts and is the primary market source of helium, a non-renewable and valuable resource. 108
  109. 109. NATURAL GAS COMPOSITION  Methane (CH4) 80-95 %  Ethane (C2H6) 5-15 %  Propane (C3H8) and Butane (C4H10) < 5 % 109
  110. 110. HEATING VALUE  Natural gas is mainly used as a combustible  Quantities of natural gas are measured in normal cubic meters (corresponding to 0 °C at 1 atm) or in standard cubic feet (corresponding to 60 °F and 30 inches mercury).  The gross heat of combustion of one normal cubic meter of commercial quality natural gas is around 39 megajoules (≈10.8 kilowatt-hours), but this can vary by several percent.  In U.S. units, one standard cubic foot of natural gas produces around 1,000 British Thermal Units (BTUs). 110
  111. 111. HEATING VALUE OF NATURAL GAS  The actual heating value when the water formed does not condense is the net heat of combustion and can be as much as 10 percent less.  In the United States, natural gas is often sold at retail in units of therms (th), where 1 therm = 100,000 BTU.  Wholesale transactions are generally done in decatherms (Dth), or thousand decatherms (MDth), or million decatherms (MMDth).  A million decatherms is roughly a billion cubic feet of natural gas. 111
  112. 112. WHAT IS LPG ?  Liquefied petroleum gas (also called LPG, GPL, LP Gas, or autogas) is a flammable mixture of hydrocarbon gases used as a fuel in heating appliances and vehicles.  It is increasingly used as an aerosol propellant and a refrigerant, replacing chlorofluorocarbons in an effort to reduce damage to the ozone layer.  Varieties of LPG bought and sold include mixes that are primarily propane, mixes that are primarily butane, and - most common - mixes including both propane C3H8 and butane C4H10, depending on the season — in winter more propane, in summer more butane 112
  113. 113.  Propylene and butylenes are usually also present in small concentration.  A powerful odorant, ethanethiol, is added so that leaks can be detected easily.  The international standard is EN 589. In the United States, thiophene or amyl mercaptan are also approved odorants.  Blended of pure, dry "isopropane" (refrigerant designator R-290a ) and isobutane (R-600a) have negligible ozone depletion potential and very low global warming potential and can serve as a functional replacement for R-12, R-22, R-134a,and other chlorofluorocarbon or hydrofluorocarbon refrigerants in conventional stationary refrigeration and air conditioning systems.[4] 113
  114. 114. ENVIRONMENT  As a low-carbon, low-polluting fossil fuel, LPG is recognized by governments around the world for the contribution it can make towards improved indoor and outdoor air quality and reduced greenhouse gas emissions 114
  115. 115. STORAGE115
  116. 116. WHAT IS NGL?  Natural Gas, the source of Natural Gas Liquids is a natural mixture of gaseous hydrocarbons found in the ground or obtained from specially driven wells.  The composition of natural gas varies in different parts of the world. Its chief component, methane, usually makes up from 80% to 95% its composition.  The balance is composed of varying amounts of ethane, propane, butane, and other liquid hydrocarbon compounds.  They include Ethane, Propane, Butanes (Iso and Normal), and condensate, all of which can be extracted from gas plants. Propane and Butanes can also be extracted during Crude Oil refining. 116
  117. 117.  Normal Butane is a refining blend stock for gasoline and is also used as a Petrochemical feedstock,  Iso-Butane is a refining feedstock for alkylation, MTBE & TAME manufacturing and a component of gasoline octane blends. 117
  118. 118. NATURAL GAS TYPICAL PROCESS118
  119. 119. CALCULATING THE DIFFERENT PROPERTIES OF GASES. 119
  120. 120. GAS COMPOSITION BY CHROMATOGRAPHY  Chromatography involves a sample being dissolved in a mobile phase (which may be a gas, a liquid or a supercritical fluid).  The mobile phase is then forced through an immobile, immiscible stationary phase.  The phases are chosen such that components of the sample have differing solubilities in each phase.  A component which is quite soluble in the stationary phase will take longer to travel through it than a component which is not very soluble in the stationary phase but very soluble in the mobile phase. 120
  121. 121. PHYSICAL PROPERTIES OF NATURAL GAS.  I) COMPOSITION BY GAS CHROMATOGRAPHY:  As a result of these differences in mobilities, sample components will become separated from each other as they travel through the stationary phase.  Typical composition of natural gas: a) Methane (CH4) 70-90% WT b) Ethane (C2H6) 5-15 c) Propane (C3H8) and Butane (C4H10) < 5 d) Nitrogen, helium, carbon dioxide and trace amounts of hydrogen sulfide, water and odorants can also be present. 121
  122. 122. OTHER COMPONENT e) Natural gas also contains and is the primary market source of Mercury is also present in small amounts in natural gas extracted from some fields[3]. The exact composition of natural gas varies between gas fields. 122
  123. 123. MOLECULAR WEIGHT Average MW: 19.5 Average MW= Σ ( yi.MWi) 123
  124. 124. DENSITY OF NATURAL GAS Average density (kg/m3): 0.7 - 0.9 Average density ( lb/ft3): 0.044 - 0.056 The density of gases depends on the compressibility factor ρ= P.MW/z.R.T For ideal gases ( low pressures below 10 atm and high temperatures) ρ= P.MW/R.T 124
  125. 125. LISTEN...LEARN....THINK...ENJOY YOURSELF EQUATIONS OF STATE FOR REAL GASES  The ideal-gas equation is very simple, but its range and applicability are limited.  Several equations of state have been proposed in the literature to describe the behavior of real gases  We will discuss : Van der Waals equation  Beattie- Bridgeman equation
  126. 126. LISTEN...LEARN....THINK...ENJOY YOURSELF VAN DER WAALS EQUATION OF STATE  Proposed in 1873  It has two constants  a/v2 is a correction of the ideal gas equation related to the intermolecular forces  b is a correction of the ideal gas equation related to the volume occupied by the gas molecules RTbv v a P  ))(( 2
  127. 127. LISTEN...LEARN....THINK...ENJOY YOURSELF DETERMINATION OF A AND B cr cr P TR a 64 27 22  cr cr P RT b 8 
  128. 128. LISTEN...LEARN....THINK...ENJOY YOURSELF BEATTIE- BRIDGEMAN EQUATION OF STATE  Proposed in 1928  It has five experimental constants 232 u v A )Bv)( vT c 1( v TR P  )1(....).......1( 00 v b BBand v a AA 
  129. 129. LISTEN...LEARN....THINK...ENJOY YOURSELF WHAT CAUSES DEVIATION FROM IDEAL GAS BEHAVIOR?  Intermolecular forces called Van Der Waals forces . There are three such types of Van Der Waals forces:  London Dispersion Forces which are forces that exist between molecules as a result of positive nuclei of one molecule attracting the electrons of another molecule..  Dipole-Dipole interactions which are forces that exist between polar molecules where the positive end of one molecule attracts the negative end of another molecule.  Hydrogen bonding interactions are forces that exist between molecules that have a hydrogen atom bonded to a highly electronegative atom such as Oxygen, Nitrogen, or Flourine.
  130. 130. LISTEN...LEARN....THINK...ENJOY YOURSELF WHAT IS THE COMPRESSIBILITY FACTOR?  The term "compressibility" is used in thermodynamics to describe the deviance in the thermodynamic properties of a real gas from those expected from an ideal gas.  The compressibility factor is defined as  In the case of an ideal gas, the compressibility factor Z is equal to unity, and the familiar ideal gas law is recovered:  Z can, in general, be either greater or less than unity for a real gas.
  131. 131. LISTEN...LEARN....THINK...ENJOY YOURSELF REAL PHASE REGION  The deviation from ideal gas behavior tends to become particularly significant (or, equivalently, the compressibility factor stays far from unity) : near the critical point,  in the case of high pressures  low temperatures. In these cases, an alternative equation of state better suited to the problem.
  132. 132. LISTEN...LEARN....THINK...ENJOY YOURSELF COMPRESSIBILITY FACTOR  The compressibility factor can be estimated from figure 3-2 page 56 if we know the reduced temperature and the reduced pressure of the gas:  PR= P/PC and TR= T/TC The compressibility factor Z is almost the same for all the gases at the same reduced pressure and reduced temperature . This is called the principle of corresponding states
  133. 133. PC AND TC : KAY’S RULE  Kay’s rule (Page 56):  Pc= Σ yi.Pci  Tc= Σyi.Tci  Tci and Pci from tables 3.1 and 3.2  Do example 3.1 page 57 133
  134. 134. NATURAL GAS CONTAINING CO2 AND H2S  Two methods available:  1) Approach proposed by Robinson et al:  2) Approah proposed by Wichert and Aziz: The second method uses adjustments of the Pc’ and Tc’ which is found from Kay’s combination rule. It has a correction factor ε, found from figure 3.3 page 58 134
  135. 135. CORRECTION FOR TC’ Tc”= Tc’-0.556 ε ( SI) Tc”= Tc’- ε ( FPS) 135
  136. 136. CORRECTION IN PC’  Pc”= Pc’.Tc” / {(Tc’+0.556.B.ε.(1-B))} (SI)  Pc”= Pc’.Tc” / {(Tc’+B.ε.(1-B))} (FPS)  Pc’ and Tc’ from Kay’s rule  ε from figure 3.3  B mole fraction of H2S in gas 136
  137. 137. FIGURE 3.3 PAGE 58  Figure 3.3 can be estimated by the equation:  ε= 120 ( A0.9- A1.6) +15 (B0.5-B4)  ε= correction factor  A total mole fraction ( H2S +CO2) in the gas  B mole fraction CO2 in the gas. 137
  138. 138. FIGURE 3.3 PAGE 58  Figure 3.3 can be estimated by the equation:  ε= 120 ( A0.9- A1.6) +15 (B0.5-B4)  ε= correction factor  A total mole fraction ( H2S +CO2) in the gas  B mole fraction H2S in the gas.  Do example 3.2 page 59. 138
  139. 139. HEATING CONTENT OF LIGHT HYDROCARBONS 139
  140. 140. HEAT OF COMBUSTION  A large part of crude oil will be used as fuel:  1) Fuel gas  2) Gasoline for engine  3) fuel oil The heat of combustion (ΔHc 0) is the energy released as heat when a compound undergoes complete combustion with oxygen under standard conditions. The chemical reaction is typically a hydrocarbon reacting with oxygen to form carbon dioxide, water and heat: C2H6 + 3.5 O2  2CO2 +3H2O + Heat 140
  141. 141. HEAT OF COMBUSTION  By measurement: The heat of combustion is traditionally measured with a bomb calorimeter.  By calculation: It may also be calculated as the difference between the heat of formation (ΔfH0) of the products and reactants. 141
  142. 142. CALORIMETRY TO MEASURE HEAT OF COMBUSTION OF METHANE CH4 (g) + 2 O2 (g) → CO2 (g) + 2 H2O (l)  The enthalpy change for this reaction is measured by pressurizing a strong metal reaction vessel (called a bomb) with a mixture of methane and oxygen gas.  The bomb is immersed in a calorimeter filled with water. An electrical current is passed through ignition wire (a fine iron wire), which ignites the wire and the gas mixture.  The heat balance for this calorimetry experiment is:  0 = qcal + qwire + qcomb 142
  143. 143.  The heat for the calorimeter, qcal, is determined from the heat capacity of the calorimeter and the temperature change for the calorimetry experiment.  Typically the amount of water in the calorimeter is always the same; therefore Ccal includes the heat capacities of the calorimeter, the water, and the bomb itself.  The burning of the ignition wire releases heat, qwire, and this heat must be included in the calculations. (This heat is treated separately, because the amount of ignition wire used varies from one measurement to the next.) 143
  144. 144. COMBUSTION EXPERIMENT  The heat released by the combustion reaction is qcomb, which is related to the molar enthalpy of combustion by  ΔHcomb = qcomb /nmethane Combustion experiments are general conducted with a large excess of oxygen, so that the fuel (methane in this case) is the limiting reactant. 144
  145. 145. MOLAR ENTHALPIES OF FORMATION  Combustion reactions are often used to calculate the molar enthalpies of formation.  For example, the standard molar enthalpy of combustion for methane can be expressed in terms of the standard molar enthalpies of formation of the reactants and products:  ΔHo comb = 2 ΔHo f,water + ΔHo f,carbon dioxide - ΔHo f,methane - 2 ΔHo f,oxygen  ΔHo comb is measured experimentally.  ΔHo f,oxygen = 0, because oxygen is a pure element.  The other molar enthalpies of formation are known from independent measurements. 145
  146. 146.  For example, one could determine the heat of combustion of hydrogen to obtain the molar enthalpy of formation for water.  For liquid water, ΔHo f = -285.8 kJ mole-1  For gaseous carbon dioxide, ΔHo f = -393.5 kJ mole-1 146
  147. 147. HEATING VALUE= HEAT OF COMBUSTION  The heating value or energy value of a substance, usually a fuel or food (see food energy), is the amount of heat released during the combustion of a specified amount of it.  The energy value is a characteristic for each substance. It is measured in units of energy per unit of the substance, usually mass, such as: kJ/kg, J/mol, kcal/kg, Btu/m³.  Heating value is commonly determined by use of a bomb calorimeter. 147
  148. 148. HIGHER HEATING VALUE  The quantity known as higher heating value (HHV) (or gross energy or upper heating value or gross calorific value or higher calorific value HCV) is determined by bringing all the products of combustion back to the original pre- combustion temperature, and in particular condensing any vapor produced.  Such measurements often use a temperature of 25 °C. This is the same as the thermodynamic heat of combustion since the enthalpy change for the reaction assumes a common temperature of the compounds before and after combustion, in which case the water produced by combustion is liquid. 148
  149. 149. LOWER HEATING VALUE  The quantity known as lower heating value (LHV) (or net calorific value or lower calorific value LCV)) is determined by subtracting the heat of vaporization of the water vapor from the higher heating value.  This treats any H2O formed as a vapor. The energy required to vaporize the water therefore is not realized as heat.  LHV calculations assume that the water component of a combustion process is in vapor state at the end of combustion, as opposed to the higher heating value (HHV) (a.k.a. gross calorific value or gross CV) which that assumes all of the water in a combustion process is in a liquid state after a combustion process. 149
  150. 150.  For hydrocarbons the difference between HHV and LHV depends on the hydrogen content of the fuel. For gasoline and diesel the higher heating value exceeds the lower heating value by about 10% and 7%, respectively, for natural gas about 11%.  A common method of relating HHV to LHV is:  HHV = LHV + hv x (nH2O,out/nfuel,in)  where hv is the heat of vaporization of water, nH2O,out is the moles of water vaporized and nfuel,in is the number of moles of fuel combusted.[1] 150
  151. 151.  Most applications which burn fuel produce water vapor which is not used and thus wasting its heat content.  In such applications, the lower heating value is the applicable measure. This is particularly relevant for natural gas, whose high hydrogen content produces much water.  The gross energy value is relevant for gas burnt in condensing boilers and power plants with flue gas condensation which condense the water vapor produced by combustion, recovering heat which would otherwise be wasted. 151
  152. 152. SOME VALUES FOR LIGHT HYDROCARBONS Component HHV ( MJ/kg) LHV (MJ/kg) hydrogen 141.8 121 Methane 55.50 50 Ethane 51.9 47.8 Propane 50.35 46.35 Butane 49.50 45.75 Pentane 45.35 gasoline 47.30 44.40 152
  153. 153. HEATING VALUE OF A MIXTURE  GHV (HHV)= Σ( GHV)i.yi  Net heating value or LHV = Σ (LHV)i.yi 153
  154. 154. WOBBLE NUMBER W0  The Wooble number is related to the behavior of a fuel in a burner.  Two gases with the same Wooble number give the same heat release at the burner tip for the same pressure drop across the burner orifice ( Assuming T and P constants).  The Wooble number is a burner compatibility to a given fuel and is defined as ( page 36):  W0= GHV/ √ρ ( gross heating value or HHV divided by the square root of the relative density of the gas).  Wo has a unit of MJ/m3 ( SI). 154
  155. 155. SENSIBLE HEAT AND ENTHALPY OF GASES 155
  156. 156. SENSIBLE HEAT  Sensible heat is calculated when there is temperature change with no change in phase.  We need the heat capacities Cp and Cv to estimate the enthalpy needed or released due to a change of temperature ∆T.  For an ideal gas, constant pressure process or a liquid: ∆h= ∫cp.dT  Cp= A+BT+CT2 156
  157. 157. SENSIBLE HEAT FOR GASES  In general Cp is a function of temperature but the calculation of Cp at the average temperature is often used, therefore  Tav= (T1+T2)/2  ∆h=∫Cp(T).dT= Cp.av ( T2-T1) 157
  158. 158. FIG 8.3 FOR ESTIMATION OF SPECIFIC HEAT FOR NATURAL GAS  For real gas: ∆h= ∫cp.dT+ ∫{V-T(δV/δT)p }dP From fig 8.3 page 222. Do example 8.2 page 222. 158
  159. 159. ENTHALPY OF GASES  Figures 8A.2 to 8.A14 pages 234-247.  For Gases MW=16-30 159
  160. 160. VISCOSITY OF GASES 160
  161. 161. IMPORTANCE OF VISCOSITY  Viscosity is another important property of a gas used primarily in flow calculations.  Viscosity describes a fluid's internal resistance to flow and may be thought of as a measure of fluid friction.  Viscosity is a measure of the resistance of a fluid which is being deformed by either shear stress or tensile stress.  In everyday terms (and for fluids only), viscosity is "thickness" or "internal friction". Thus, water is "thin", having a lower viscosity, while honey is "thick", having a higher viscosity.  Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). 161
  162. 162. COUETTE FLOW162 Laminar shear of fluid between two plates. Friction between the fluid and the moving boundaries causes the fluid to shear. The force required for this action is a measure of the fluid's viscosity. This type of flow is known as a Couette flow.
  163. 163. APPLIED FORCE –VISCOSITY  The applied force is proportional to the area and velocity gradient in the fluid and inversely proportional to the distance between the plates. Combining these three relations results in the equation: F= μ.A.(u/y)  where μ is the proportionality factor called viscosity. 163
  164. 164. SHEAR STRESS  This equation can be expressed in terms of shear stress ( ζ=F/A). Thus as expressed in differential form by Isaac Newton for straight, parallel and uniform flow, the shear stress between layers is proportional to the velocity gradient in the direction perpendicular to the layers: ζ=μ.(δu/δy) 164
  165. 165. DYNAMIC VISCOSITY  Dynamic viscosityThe usual symbol for dynamic viscosity used by mechanical and chemical engineers — as well as fluid dynamicists — is the Greek letter mu (μ).[4][5][6] The symbol η is also used by chemists, physicists, and the IUPAC.[7]  The SI physical unit of dynamic viscosity is the pascal- second (Pa·s), (equivalent to N·s/m2, or kg/(m·s)). If a fluid with a viscosity of one Pa·s is placed between two plates, and one plate is pushed sideways with a shear stress of one pascal, it moves a distance equal to the thickness of the layer between the plates in one second. 165
  166. 166.  The cgs physical unit for dynamic viscosity is the poise[8] (P), named after Jean Louis Marie Poiseuille.  It is more commonly expressed, particularly in ASTM standards, as centipoise (cP). Water at 20 °C has a viscosity of 1.0020 cP or 0.001002 kg/(m·s).  1 P = 1 g·cm−1·s−1.  1 Pa·s = 1 kg·m−1·s−1 = 10 P.  The relation to the SI unit is  1 P = 0.1 Pa·s,  1 cP = 1 mPa·s = 0.001 Pa·s. 166
  167. 167. KINEMATIC VISCOSITY  In many situations, we are concerned with the ratio of the inertial force to the viscous force (i.e. the Reynolds number, Re = VD / ν) , the former characterized by the fluid density ρ. This ratio is characterized by the kinematic viscosity (Greek letter nu, ν), defined as follows: ν=μ/ρ  The SI unit of ν is m2/s. The SI unit of ρ is kg/m3. 167
  168. 168.  The cgs physical unit for kinematic viscosity is the stokes (St), named after George Gabriel Stokes. It is sometimes expressed in terms of centiStokes (cSt). In U.S. usage, stoke is sometimes used as the singular form.  1 St = 1 cm2·s−1 = 10−4 m2·s−1.  1 cSt = 1 mm2·s−1 = 10−6m2·s−1.  Water at 20 °C has a kinematic viscosity of about 1 cSt.  The kinematic viscosity is sometimes referred to as diffusivity of momentum, because it has the same unit as and is comparable to diffusivity of heat and diffusivity of mass. It is therefore used in dimensionless numbers which compare the ratio of the diffusivities. 168
  169. 169. VISCOSITY OF GASES  Viscosity in gases arises principally from the molecular diffusion that transports momentum between layers of flow. The kinetic theory of gases allows accurate prediction of the behavior of gaseous viscosity. Within the regime where the theory is applicable: 1) Viscosity is independent of pressure and 2) 2) Viscosity increases as temperature increases. 169
  170. 170. JAMES CLERK MAXWELL  To understand why the viscosity is independent of pressure consider two adjacent boundary layers (A and B) moving with respect to each other. The internal friction (the viscosity) of the gas is determined by the probability a particle of layer A enters layer B with a corresponding transfer of momentum.  Maxwell's calculations showed him that the viscosity coefficient is proportional to both the density, the mean free path and the mean velocity of the atoms. On the other hand, the mean free path is inversely proportional to the density. So an increase of pressure doesn't result in any change of the viscosity. 170
  171. 171. EFFECTS OF TEMPERATURE ON GAS VISCOSITY  171
  172. 172. VISCOSITY FROM CORRELATIONS  172
  173. 173. GRAPHICAL APPROXIMATION Fig 3.18 page 79 gives the viscosity of gases at atmospheric pressure and a different temperatures as a function of their density and molecular weight. Fig 3.19 gives the effects of pressure and temperature on the viscosity calculated in fig 3.18. 173
  174. 174. CLASS WORK  Study of the paper “ Comparison of correlations for viscosity of sour natural gas “ by O. Jeje and L. Mattar in “Canadian International Petroleum Conference”. 174
  175. 175. VISCOSITY OF MIXTURES  175
  176. 176. FLASH SEPARATION OF GASES 176
  177. 177. INTRODUCTION  Natural gas condensate is a low-density mixture of hydrocarbon liquids that are present as gaseous components in the raw natural gas produced from many natural gas fields.  It condenses out of the raw gas if the temperature is reduced to below the hydrocarbon dew point temperature of the raw gas.  The natural gas condensate is also referred to as simply condensate, or gas condensate, or sometimes natural gasoline because it contains hydrocarbons within the gasoline boiling range. 177
  178. 178. Raw natural gas may come from any one of three types of gas wells.  Crude oil wells – Raw natural gas that comes from crude oil wells is called associated gas. This gas can exist separate from the crude oil in the underground formation, or dissolved in the crude oil.  Dry gas wells – These wells typically produce only raw natural gas that does not contain any hydrocarbon liquids. Such gas is called non-associated gas.  Condensate wells – These wells produce raw natural gas along with natural gas liquid. Such gas is also non- associated gas and often referred to as wet gas 178
  179. 179. SEPARATION OF CONDENSATE179
  180. 180. PROCESS DESCRIPTION  The raw natural gas feedstock from a gas well or a group of wells is cooled to lower the gas temperature to below its hydrocarbon dew point at the feedstock pressure and that condenses a good part of the gas condensate hydrocarbons.  The feedstock mixture of gas, liquid condensate and water is then routed to a high pressure separator vessel where the water and the raw natural gas are separated and removed.  The raw natural gas from the high pressure separator is sent to the main gas compressor. 180
  181. 181.  The gas condensate from the high pressure separator flows through a throttling control valve to a low pressure separator.  The reduction in pressure across the control valve causes the condensate to undergo a partial vaporization referred to as a flash vaporization.  The raw natural gas from the low pressure separator is sent to a "booster" compressor which raises the gas pressure and sends it through a cooler and on to the main gas compressor. 181
  182. 182.  At the raw natural gas processing plant, the gas will be dehydrated and acid gases and other impurities will be removed from the gas.  Then the ethane (C2), propane (C3), butanes (C4) and C5 plus higher molecular weight hydrocarbons (referred to as C5+) will also be removed and recovered as byproducts.  The water removed from both the high and low pressure separators will probably need to be processed to remove hydrogen sulfide before the water can be disposed of or reused in some fashion.  Some of the raw natural gas may be re-injected into the gas wells to help maintain the gas reservoir pressures. 182
  183. 183. LIQUID-VAPOR EQUILIBRIUM  It is convenient to represent a liquid-vapor equilibrium with the equilibrium constant K.  By definition: K= yi/xi 183
  184. 184. EQUILIBRIUM DATA184
  185. 185. 185
  186. 186. FUGACITY OF GAS  In chemical thermodynamics, the fugacity (f) of a real gas is an effective pressure which replaces the true mechanical pressure in accurate chemical equilibrium calculations.  It is equal to the pressure of an ideal gas which has the same chemical potential as the real gas.  For example, nitrogen gas (N2) at 0°C and a pressure of 100 atm has a fugacity of 97.03 atm. This means that the chemical potential of real nitrogen at a pressure of 100 atm has the value which ideal nitrogen would have at a pressure of 97.03 atm. 186
  187. 187.  Fugacities are determined experimentally or estimated for various models such as a Van der Waals gas that are closer to reality than an ideal gas.  The ideal gas pressure and fugacity are related through the dimensionless fugacity coefficient φ: Φ = f/P  For nitrogen at 100 atm, the fugacity coefficient is 97.03 atm / 100 atm = 0.9703. For an ideal gas, fugacity and pressure are equal so is 1. 187
  188. 188. K VALUES FROM FUGACITIES  Fugacities are used to correct the non-ideal behavior of gases at high pressures ( above 3.5 MPa) or close to the critical point. Ki= yi/xi = f0 i,l / f0 I,v  f0 i,l= fugacity of component i in the pure liquid state  f0 I,v= fugacity of component I in the pure vapor state  Applying the law of ideal solutions ( Not ideal gas law) fi,l= f0 I,l. xi and fi,v= f0 I,v.yi  At equilibrium , we have fi,l= fi,v 188
  189. 189. Fugacity coefficient for gas φi = fi/ P.yi  For liquids : φi,l = fi/ P.xi ?  At equilibrium : Ki= φi,l / φi,v K values pages 140-154 189
  190. 190. RELATIVE VOLATILITY  The relative volatility αi for component (i) is the ratio of its distribution coefficient and the distribution coefficient of a reference component (r): αi = ( Ki/Kr) 190
  191. 191. BOILING (BUBBLE) POINT OF A MIXTURE  At a given pressure, the boiling point or bubble point of a multi-component mixture must satisfy the relationship: Σ (yi)= 1= Σ (Ki.xi)= Kr. Σ (αi.xi) where Kr= ( 1/ Σ (αi.xi) The test is to compare the value of Kr calculated with the value of Kr given in the chart for the assumed temperature.  K values found in tables for a given pressure and temperature. 191
  192. 192. STEPS OF CALCULATION 1) Assume the temperature T 2) Find the corresponding Ki 3) Select a reference component and calculate αi 4) Kr is calculated from: Kr= ( 1/ Σ (αi.xi) 5) The assumed T is compared to the temperature of the reference (r) for the calculated Kr 6) the composition yi is calculated by:  yi= ( αi.xi/Σαixi) 192
  193. 193. DEW POINT OF A MIXTURE Σxi = Σ (yi/Ki)=(1/Kr).Σ (yi/αi) 193
  194. 194. CLASS WORK  Do example 5.1 page 117 and 5.2 page 118 194
  195. 195. FLASH CALCULATION 195
  196. 196. NGL STABILIZATION: DEW POINT CONTROL  Once the NGL has been extracted from the gas, it must be stabilized to meet sales specifications.  In some cases, the NGL product is a stabilized condensate consisting only of C5+ having a vapor pressure less than 14.4 psia.  In other cases , the NGL product is a C4+ mixture which can be added to crude oil stream for sale.  In NGL recovery, the NGL product is a C2+ or C3+ which can be fractionated to produce C1, C2, C3, C4 and C5+ 196
  197. 197. STABILIZATION BY DISTILLATION  Stabilization of natural gas liquids (NGLs) or field condensate is a process utilizing controlled flashing and in some cases, a distillation of the liquid to allow it to be stored in atmospheric vessels.  The distillation of the liquid can also used to remove objectionable non-hydrocarbon components, most notably CO2, from the sales liquid. 197
  198. 198. MEMBRANE TECHNOLOGY  An improved, membrane-based method of treating gas evolved during natural gas liquids (NGL) stabilization, to separate the very light hydrocarbon gases, methane in particular, from the heavier hydrocarbons.  The membrane acts as a demethanizer and establishes a vapor/liquid equilibrium during phase separation that is different than would otherwise obtain.  This can increase NGL production and reduce the weight of C3+ hydrocarbons in the off-gas from the stabilizing phase separators. 198
  199. 199. FLASH CALCULATION  Flash (or partial) evaporation is the partial vapor that occurs when a saturated liquid stream undergoes a reduction in pressure by passing through a throttling valve or other throttling device.  This process is one of the simplest unit operations. If the throttling valve or device is located at the entry into a pressure vessel so that the flash evaporation occurs within the vessel, then the vessel is often referred to as a flash drum.  If the saturated liquid is a multi-component liquid (for example, a mixture of propane, isobutane and normal butane), the flashed vapor is richer in the more volatile components than is the remaining liquid. 199
  200. 200. FLASH VESSEL200
  201. 201. MATERIAL BALANCE  Total and partial:  A) Total: F= V+L  B) partial: Fzi= Vyi + Lxi  For Feed flow-rate F = 1mol, we obtain:  A) xi = zi/ ( L+VKi)  B) yi= zi/{ V+(L/Ki)} 201
  202. 202.  Knowing that Σxi= 1 and Σyi=1 , we will obtain: Σxi = Σ{zi/ ( L+VKi)} =1 Σyi= Σ [zi/{ V+(L/Ki)}] =1 At equilibrium: Σyi – Σxi =0, we obtain the flash equation: Σ{zi ( Ki-1)} / {V( Ki-1) +1} =0 202
  203. 203. STEPS FOR SOLVING FLASH CALCULATION  1) find K from P and T  2) assume V and L ( L=F-V)  3) solve the flash equation  4) if not equal to zero, assume new V and L  Solve example 5.3 page 119. 203
  204. 204. NGL FRACTIONATION BY DISTILLATION 204
  205. 205. SELECTION OF KEY COMPONENTS  Selecting Key components: If we have a mixture ( A,B,C,D), the separation should be only between two of the four components:  Ex:  A and B are light and heavy keys  B and C are light and heavy keys  C and D are light and heavy keys. 205
  206. 206. LIGHT AND HEAVY COMPONENTS  If we want to separate B and C  B is called the Light (L) key  C is called the Heavy (H) key  A is called light component  D is called heavy component  It is assumed that the light components are all at the top and the heavy components all in the bottom. 206
  207. 207. MINIMUM OF STAGES BY FENSKE EQUATION  The Fenske equation used for a binary distillation is also used for multicomponent distillation to estimate the minimum number of stages at total reflux:  Nm=(log {xLD. D/xHD. D} .{xHW. W/xLW. W})/ log ( αLAV )  With αLAV = √ (αLD. αLW ) 207
  208. 208. DISTRIBUTION OF THE OTHER COMPONENTS  (xi,D. D/xiw. W)= (αi,AV)Nm.(xHD.D/xHW.W) 208
  209. 209. RMINIMUM  Underwood shortcut method is used for the Minimum Reflux ratio.  Solving the two following equations:  1-q= Σ {αi,av.xiF/(αi,av-θ)}  Rm+1= Σ {αi,av.xiD/(αi,av-θ)}  1) As an approximation, the values of xiD in the second equation can be taken from the Fenske equation. 209
  210. 210. NUMBER OF PLATES  2) The value of θ of the first equation is found by trial and error. It is located between the α value of the light and heavy keys.  3) Having the value of θ , we find Rm from the second equation.  4) R= 1.5 Rm  4) Using Figure 11.7.3, we can estimate the number of stages N 210
  211. 211. LOCATION OF THE FEED  Log ( Ne/Ns)= 0.206. log [(xhf/xlf).(W/D).( xlw/xld)2 ]  Ne is the number of theoretical stages above the feed plate.  Ns is the number of theoretical stages below the feed plate. 211
  212. 212. EXAMPLE OF NGL FRACTIONATION UNIT 212
  213. 213. SECTIONS OF THE UNIT The natural gas liquefaction ( NGL) is divided into 4 sections:  The feed preparation Section  The expansion and separation Section  The recovery Section  The propane refrigerant Section 213
  214. 214. FEED PREPARATION SECTION The feed preparation section contains:  Feed Gas Scrubber D-405  Feed Gas separator D-401  The feed gas/ gas off exchanger E-401  The gas and liquid dehydrators  Purpose of the section: To remove any liquid from the inlet gas and to prepare the inlet feed gas for cooling and separation 214
  215. 215. EXPANSION SECTION The expansion and separation section contains:  High Level Gas Chiller E-402  Low Level Gas Chiller E-404  Chiller Separator D-403  Expander Feed Separator D-404  Expander KT-100  Cold gas/ off gas exchanger E-405  Intermediate gas/off gas exchanger E-403 215
  216. 216. OBJECTIVE OF EXPANSION SECTION  Purpose of the section:  Cool the inlet feed gas in a series of heat exchangers and to provide several feeds at various temperatures to the demethanizer D-402 216
  217. 217. SEPARATION SECTION The separation section contains:  Demethanizer Column D-402  Demethanizer Reboiler E-406  Compression Section K-100 and KT-100  Two product booster pumps P-401A/B 217
  218. 218. REFRIGERATION SECTION  Propane refrigerant is used  Cooling takes place in the high Level Chiller E-402 and Low Level Chiller E-404 218
  219. 219. PROCESS DESCRIPTION 219
  220. 220.  Pressurized inlet gas enters NGL recovery Unit  Entrained liquid is removed by scrubber  The liquid from the scrubber is dried and then feed the demethaniser  The gas from the scrubber is dried and then cooled by the overhead gas from the demethanizer 220
  221. 221.  The gas then enters the feed gas separator D-401  The liquid from the separator combines with the liquid from the bottom of the scrubber to go to the demethanizer  - The gas leaving the separator is chilled by passing through three heat exchangers  - high level gas chiller E-402  - Intermediate gas-gas heat exchanger E-403  - Low level Chiller E-404 221
  222. 222.  From the low level chiller, gas enters the chiller separator D-403 which remove any additional liquid  - The remaining gas is cooled in a cold gas exchanger E-405  - Then enters the expander feed separator KT 100  - The liquid from the expander separator enters the demethanizer 222
  223. 223.  The gas from the expander separator E- 404 enters the expander  - The expander reduces the temperature and pressure of the gas and condenses as much C2+ as possible  - The gas stream from the expander D- 404 feeds the demethanizer  - the expander is also used to provide power to the residue gas compressor 223
  224. 224. PROCESS CONTROL SYSTEM 224
  225. 225. FEED PREPARATION SECTION  TI-350: indicates inlet feed gas to gas Scrubber D-405 ( 0-650C)  HC-350: This is a manual valve to control the flow of inlet gas to the feed gas scrubber D-405  HS-400: This hand switch initiates the plant emergency shut down by closing the inlet feed valve HC-350 225
  226. 226.  FI-405: Indicates the inlet feed gas vapor from the top of the scrubber D-405 ( 0 -1600 kNm3/d  FI-406: Indicates the liquid flow from the bottom of D-405 ( 0-50 m3/h)  LC-350: this controls the level of liquid in the scrubber D-405 by regulating the flow of methane to the D-402. Flow shown by FI-406 226
  227. 227. FEED GAS SEPARATOR D-401  LC-411: controls the liquid level in the feed gas separator D-401 by regulating the flow of liquid from the bottom of D-401 to tray 20 of D-402  TI-400: Indicates the vapor temperature exiting the top of D- 401 227
  228. 228. TYPE OF GASSES.  Exercise B): Use the internet or any other sources to answer the following questions: 1. What is an associated gas? 2. Search (internet or any other source) for a typical associated gas composition of an oil field, preferably in the UAE, and attached/copy the table. 3. What is a non-associated gas. 4. What is the difference between a wet gas and a dry gas. (include a table showing an example of a mol% of a dry gas components compared to a wet gas) (Will discuss and will review the answers after you are done… next slide) 228
  229. 229. HIGH LEVEL GAS CHILLER  LC-401:This controls the propane refrigerant level in the shell side of the High level gas chiller E-402  LAH-401: this alarm will start when the level of the liquid in the shell side of E-402 rises above 80% as read in LC-401 229
  230. 230.  PC-405: from 0 to 7 Barg , this controls the pressure in E-402 by regulating the flow of propane vapor from the chiller to the inlet of second stage of compressor ( not simulated)  PAH-405: This alarm when the pressure in the gas chiller E-402 rises above 2.94 as read in PC-405 230
  231. 231. LOW LEVEL GAS CHILLER  LC-402:This controls the liquid propane in the shell side of E-404 by regulating the flow of propane from the propane tube side of E-409  LAHL-402: Alarm when the propane refrigerant level in shell side of E-404 rises above 80% or falls below 20%  PC-406 : from 0 to 3.5 barg, this controls the pressure in E-404 by regulating the flow of propane vapor from the chiller to first stage of the compressor ( not simulated) 231
  232. 232.  PAH-406: Alarm when the pressure in E-404 rises above 0.62 Barg as read in PC-406  Ti-404: indicates the temperature of the effluent from the tube shell of E-404. Indicates also the temperature of the feed entering D-403  LC -403: Controls the level of D-403 by regulating the flow from the bottom of the separator to tray 14 of D-402 232
  233. 233. EXPANSION SECTION  PC-401:from 0 to 50 Barg, this controls the pressure of the expander feed separator through a split-range control. This is also the pressure at the inlet to the expander section.  PAHL- 401: alarm when the pressure in D-404 rises above 48.0 Barg or falls below 44.13 Barg as read at PC- 401  TI-405: Indicates the temperature of the feed gas as it enters D-404. this is also the temperature of the feed gas from the tube side of E-405 233
  234. 234.  LC-404:this controls the liquid level in the chiller separator D-404 by regulating the flow of liquid from the bottom of separator to tray 8 of D-402  LAH-404: Alarm when the liquid level in D-404 rises above 80% as read at LC-404  HC-401: Manual control adjusts the position of the inlet louver vanes in expander4 section  HS-401:switch that determines witch controller HC-401 or PC-401 will regulate the position of the expander inlet vanes 234
  235. 235.  FC-403: from 0 to 1600 kNm3/d, this regulates the inlet flow to the compressor section  FAL-403: Alarm when compressor recycle ( anti-surge) flow falls below 750.KNm3/d as read in FC-403  HS 100: this switch operates the expander section KT-100. When the switch in ON , the expander is in operation 235
  236. 236. DE-METHANIZER  AAH-401 : Alarm when the concentration of methane in the bottom of the demethanizer D-402, rises above 2% as read in AC-401  AC-401: Controls the methane composition in the bottom of the demethanizer D-402 from 0 to 10% by sending a remote set-point signal to the demethanizer reboiler effluent temperature controller TC-403 236
  237. 237.  FI-408: this instrument indicates the flow of the methane product from the bottom of the demethanizer D-402 to the product pipeline . This flow is regulated by the Demethanizer level controller LC-400.  HS-401A-B : this are the product booster pumps. These pumps draw methane product from the bottom of the demethanizer D-402 and send it to the product line 237
  238. 238.  LAHL-400: This alarm fires when the level in the bottom of the demethanizer D-402 rises above 80% or below 20% as read at LC-400  LC-400 : this controls the level in the bottom of the demethanizer by regulating the flow of methane product from the bottom of D-402 as read in FI- 408 238
  239. 239.  PAHL-402 : Alarm when the pressure in the top of D-402 rises above 13.48 Barg or below 10.69 Barg as read in PC-402  PC-402: Controls the pressure in the top of D-402 by regulating the flow of vapor from the discharge of the compression section K-100 239
  240. 240.  TAH-401 D-402 TRAY-1 Temperature:  This alarm is on when the temperature of TRAY-1 of D-402, rises above -95C as read in TC-401  TC-401( -125C to -200C):  This controls the temperature of the feed of tray-1 of D-402 by regulating the amount of gas bypassing KT-100 and flows directly from the top of D-403 240
  241. 241.  TC-403: ( from -20C to 100C):  This controls the effluent temperature from the D-402 re- boiler E-406 by regulating the flow of heating medium to the re-boiler. This controller can receive a signal control from the D-402 methane composition controller AC-401 241
  242. 242.  TI-410: Indicator top of D-402  -1250C to -500C  TI-411: Indicator tray 24 of D-402  -1000C to 100C  TI-412 : Indicator of bottom D-402  -500C to 100C 242
  243. 243. CLASS WORK  Work the NGL fractionation plant using hysys. 243
  244. 244. ACID GAS REMOVAL 244
  245. 245. ACID & SOUR GAS  Acid gas is natural gas or any other gas mixture which contains significant amounts of hydrogen sulfide (H2S), carbon dioxide (CO2), or similar contaminants.  The terms acid gas and sour gas are often incorrectly treated as synonyms.  Strictly speaking, a sour gas is any gas that contains hydrogen sulfide in significant amounts;  Hydrogen sulfide is a toxic gas. It also restricts the materials that can be used for piping and other equipment for handling sour gas, as many metals are sensitive to sulfide stress cracking. 245
  246. 246. GLOBAL WARMING  an acid gas is any gas that contains significant amounts of acidic gases such as carbon dioxide (CO2) or hydrogen sulfide.  Thus, carbon dioxide by itself is an acid gas but not a sour gas.  Carbon dioxide is the main gas responsible for global warming. 246
  247. 247. CONVERTING H2S  Before a raw natural gas containing hydrogen sulfide and/or carbon dioxide can be used, the raw gas must be treated to reduce impurities to acceptable levels and this is commonly done with an amine gas treating process.  The removed H2S is most often subsequently converted to by-product elemental sulfur in a Claus process  or alternatively converted to valuable sulfuric acid in a WSA Process unit. 247
  248. 248. REASONS FOR REMOVING CO2 AND H2S  Carbon dioxide, hydrogen sulfide, and other contaminants are often found in natural gas streams.  CO2 when combined with water creates carbonic acid which is corrosive. CO2 also reduces the BTU value of gas and  in concentrations of more that 2% or 3 % the gas is unmarketable.  H2S is an extremely toxic gas that is also tremendously corrosive to equipment.  Amine sweetening processes remove these contaminants so that the gas is marketable and suitable for transportation. 248
  249. 249. DIFFERENT PROCESSES  Chemical solvent processes  Physical solvent processes  Dry adsorbents processes 249
  250. 250. CHEMICAL SOLVENTS  Monoethanolamine (MEA)  * Diethanolamine (DEA)  * Methyl- Diethanolamine (MDEA)  * Diglycolamine (DGA)  * Hot Potassium Carbonate 250
  251. 251. PHYSICAL SOLVENTS  Physical solvent processes:  * Selexol  * Propylene Carbonate  * Sulfinol  * Rectisol 251
  252. 252. DRY ADSORBENTS * Molecular sieve  * Activated charcoal  * Iron sponge  * Zinc oxide 252
  253. 253. AMINE GAS SWEETENING SOLUTIONS  Amine gas sweetening is a proven technology that removes H2S and CO2 from natural gas and liquid hydrocarbon streams through absorption and chemical reaction.  Each of the amines offers distinct advantages to specific treating problems. 253
  254. 254. MEA  Used in low pressure natural gas treatment applications requiring stringent outlet gas specifications 254
  255. 255. MDEA  MDEA (Methyldiethanolamine)  Has a higher affinity for H2S than CO2 which allows some CO2 "slip" while retaining H2S removal capabilities. 255
  256. 256. DEA  DEA (Diethanolamine) Used in medium to high pressure treating 256
  257. 257. PIPERAZINE  Nowadays, Piperazine mixed with MDEA or the hindered amine AMP are the most effective amine mixtures because :  1) Piperazine has fast kinetics with CO2 and H2S  2) MDEA and AMP require less energy for the regeneration of the amine. 257
  258. 258. IONIC LIQUIDS  Some Ionic liquids are now under investigation in many laboratories around the world as the new solvent to be used for acid gas removal:  They have the advantage to use less energy than amines for their regeneration  BUT they have slow kinetics with the acid gases, they are very viscous and still expensive in the market. 258
  259. 259. CHEMICAL REACTIONS  MEA is a suitable compound and, in absence of other chemicals, suffer no degradation or decomposition at temperatures up to its normal boiling point.  MEA reacts with H2S as follows:  2(RNH2) +H2S ↔ (RNH)2S  MEA reacts with CO2 as follows:  2(RNH2) +CO2 ↔RNHCOONH3R 259
  260. 260. PROCESS FOR ACID REMOVAL BY AMINE SOLUTIONS 260
  261. 261. ABSORPTION /STRIPPING UNIT 261
  262. 262. ABSORPTION UNIT262
  263. 263. STRIPPING UNIT263
  264. 264. PROCESS DESCRIPTION  The Amine Treating Unit removes CO2 and H2S from sour gas and hydrocarbon streams in the Amine Contactor. The Amine (MDEA) is regenerated in the Amine Regenerator, and recycled to the Amine Contactor.  The sour gas streams enter the bottom of the Amine Contactor. The cooled lean amine is trim cooled and enters the top of the contactor column.  The sour gas flows upward counter-current to the lean amine solution. An acid-gas-rich-amine solution leaves the bottom of the column at an elevated temperature, due to the exothermic absorption reaction.  The sweet gas, after absorption of H2S by the amine solution, flows overhead from the Amine Contactor. 264
  265. 265.  The Rich Amine Surge Drum allows separation of hydrocarbon from the amine solution.  Condensed hydrocarbons flow over a weir and are pumped to the drain.  The rich amine from the surge drum is pumped to the Lean/Rich Amine Exchanger.  The stripping of H2S and CO2 in the Amine Regenerator regenerates the rich amine solution.  The Amine Regenerator Reboiler supplies the necessary heat to strip H2S and CO2 from the rich amine, using steam as the heating medium. 265
  266. 266.  Acid gas, primarily H2S and water vapor from the regenerator is cooled in the Amine Regenerator Overhead Condenser.  The mixture of gas and condensed liquid is collected in the Amine Regenerator Overhead Accumulator. The uncondensed gas is sent to Sulfur Recovery.  The Amine Regenerator Reflux Pump, pumps the condensate in the Regenerator Accumulator, mainly water, to the top tray of the Amine Regenerator A portion of the pump discharge is sent to the sour water tank. 266
  267. 267.  Lean amine solution from the Amine Regenerator is cooled in the Lean/Rich Exchanger.  A slipstream of rich amine solution passes through a filter to remove particulates and hydrocarbons, and is returned to the suction of the pump.  The lean amine is further cooled in the Lean Amine Air Cooler, before entering the Amine Contactor. 267
  268. 268. PRODUCT SPECIFICATIONS  The Amine Treating Unit removes CO2 and H2S from sour gas and hydrocarbon streams totaling 14.5 MMSCFD.  The acid contaminants are absorbed by counter flowing amine solution (MDEA).  The stripped gas is removed overhead, and the amine is sent to the regenerator.  In the regenerator, the acidic components are stripped by heat and reboiling action and disposed of, and the amine is recycled. 268
  269. 269. EQUIPMENT'S SPECIFICATIONS  The amine contactor is 5 feet in diameter by 65 feet tangent to tangent with 22 trays.  The Rich Amine Surge drum, D-101, provides approximately 30 minutes of residence time which allow separation of the hydrocarbon from the amine solution.  The Amine Regenerator is 8 feet in diameter by 70 feet tangent to tangent with 22 trays.  The Regenerator Reboiler, E-202, uses 60 psig steam as heating medium which provides the heat for regeneration of the amine solution. 269
  270. 270. PROCESS CONTROL OF THE UNIT 270
  271. 271. PROCESS CONTROL OF THE UNIT  The sour gas stream, 14.5 MMSCFD, enters the bottom of the Amine Contactor at 95 0F and 140 psig.  The cooled lean amine is trim cooled in exchanger E-103 and enters the top of the absorber column at 105 0F.  The lean amine solution temperature is 100 higher than the feed gas to prevent any hydrocarbon condensation and foaming problems.  This temperature differential is maintained by TDIC-103, which allows bypassing of lean amine around the Lean Amine Trim Cooler E-103. 271
  272. 272.  The sour gas flows upward counter-current to the lean amine solution in T-101.  An acid-gas-rich-amine solution leaves the bottom of the column at an elevated temperature, 1350 F, due to the exothermic absorption reaction.  The rich MDEA solution temperature is monitored by TI- 105.  Rich amine leaves the bottom of the column on level control LIC-101 to the Rich Amine Surge Drum D-101. 272
  273. 273.  The sweet gas, after absorption of H2S by the MDEA solution, flows overhead from T-101 under pressure control PIC-101, monitored by the H2S and CO2 analyzers, AI-102 and AI-103.  The temperature and flow rate of the gas are monitored with TI- 104 and FI-101.  The Rich Amine Surge Drum D-101 allows the amine solution 30 minutes of residence time, which allows separation of hydrocarbon from the amine solution.  The drum pressure is maintained by a backpressure controller, PIC-102, at 5 psig.  Condensed hydrocarbons flow over a weir and are pumped to the drain system using P-102. 273
  274. 274.  The rich amine from the surge drum is pumped by P-101 to the Lean/Rich Amine Exchanger E-101.  The rich amine enters the tube side at 1350 F, where it is heated to 2260 F by the hot lean amine solution from the regenerator bottoms.  The hot lean amine solution enters the Lean/Rich Exchanger on the shell side at 265 0 F.  The stripping of H2S and CO2 in the Amine Regenerator, T- 201, regenerates the rich amine solution.  The Amine Regenerator Reboiler supplies the necessary heat to strip H2S from the rich amine, using 60-psig steam as the heating medium. 274
  275. 275.  Acid gas, primarily H2S and water vapor from the regenerator is cooled to 120 0F in the Amine Regenerator Overhead Condenser.  The temperature of the overhead gas is monitored by TI- 202 The mixture of gas and condensed liquid is collected in the Amine Regenerator Overhead Accumulator.  The pressure is maintained at 16 psig with PIC-201 controlling the acid gas from the Regenerator Accumulator, D-20, to Sulfur Recovery. 275
  276. 276.  The condensate in the Regenerator Accumulator D-201, mainly water, is pumped by the Amine Regenerator Reflux Pump, P-202, to the top tray of the Amine Regenerator.  The reflux flow is regulated by level controller LIC-201 and is monitored by FI-203. A part of the pump discharge is sent to the sour water tank.  Lean amine solution from the Amine Regenerator is cooled from 265 degrees F to 189 degrees F in the Lean/Rich Exchanger.  A slipstream of rich amine solution is controlled by PDIC-202 through a filter F-201 to remove particulates and hydrocarbons, and returned to the suction of P-201.  The lean amine is further cooled in the Lean Amine Air Cooler, E- 102, to 130 0 F. 276
  277. 277. ADVANCED CONTROL  The cooler the lean amine temperature, the better the H2S absorption. However, lowering the MDEA solution temperature below the gas inlet temperature can cause hydrocarbons to condense with resulting foaming.  The lean amine solution temperature is maintained 100 higher than the feed gas to the Amine Contactor. TDIC-103 allows bypassing of lean amine around the Lean Amine Trim Cooler, E-103, to maintain this 100 difference. 277
  278. 278. SULFUR RECOVERY UNIT: CLAUS PROCESS 278
  279. 279. SULFUR RECOVERY PROCESS  The most practical method for converting hydrogen sulfide to elementary sulfur  Best suited for gases containing more than 50% hydrogen sulfide is the  PARTIAL COMBUSTION PROCESS. 279
  280. 280.  Hydrogen sulfide is burned with 1/3 the stoichiometric quantity of air  2H2S + 3O2 → 2H2O + 2SO2  The hot gases are sent to a reactor with alumina as catalyst to react sulfur dioxide with unburned hydrogen sulfide to produce free sulfur  2H2S + SO2 → 2H2O + 3S 280
  281. 281.  Carbon sulfide (COS) and carbon disulfide CS2 have presented problems in many Claus plant operations.  These compounds are formed in the combustion step.  Unconverted, these compounds represent a loss of sulfur recovery.  They are in the tail gas of the Claus process and sent to the Scot process 281
  282. 282. CLAUS PROCESS282
  283. 283. GAS DEHYDRATION PROCESS 283
  284. 284.  Natural Gas usually contains significant quantities of water vapor.  Changes in temperature and pressure condense this vapor altering the physical state from gas to liquid to solid.  This water must be removed in order to protect the system from corrosion and hydrate formation. 284
  285. 285. DALTON’S LAW  In 1810, an English scientist by the name of John Dalton stated that the total pressure of a gaseous mixture is equal to the sum of the partial pressures of the components.  This statement, now known as Dalton's Law of Partial Pressures, allows us to compute the maximum volume of water vapor that natural gas can hold for a given temperature and pressure.  The wet inlet gas temperature and supply pressures are the most important factors in the accurate design of a gas dehydration system.  Without this basic information the sizing of an adequate dehydrator is impossible 285
  286. 286. EXAMPLE  As an example, one MMSCF (million standard cubic feet) of natural gas saturated @ 80 0F and 600 PSIG (pound per square inch gauge) will hold 49 pounds of water.  At the same pressure (600 PSIG) one MMSCF @ 120 0 F will hold 155 pounds of water.  Common allowable water content of transmission gas ranges from 4 to 7 pounds per MMSCF.  Based upon the above examples, we would have two very different dehydration problems as a result of temperature alone.  There are many other important pieces of design information required to accurately size a dehydration system. These include pressures, flow rates and volumes. 286
  287. 287. HYDRATES IN NATURAL GAS  All gasses have the capacity to hold water in a vapor state. This water vapor must be removed from the gas stream in order to prevent the formation of solid ice-like crystals called hydrates.  Hydrates can block pipelines, valves and other process equipment.  The dehydration of natural gas must begin at the source of the gas in order to protect the transmission system. 287
  288. 288. ELIMINATION OF WATER  The source of the gas moved through the transmission lines may be producing wells or developed storage pools.  Pipeline drips installed near well heads and at strategic locations along gathering and trunk lines will eliminate most of the free water lifted from the wells in the gas stream.  Multi stage separators can also be deployed to insure the reduction of free water that may be present. 288
  289. 289. PIPELINE DRIPS  Natural gas transmission pipelines often contain liquids that can interfere with the proper operation of the pipeline and related equipment such as compressors, regulators, filters, meters and valves.  The liquid contaminants normally include hydrocarbon condensations, lubrication oils, produced water, and chemicals used in production, treatment, compression or dehydration of the gas.  Gas transmission pipelines have typically used below grade liquid separators known as “drips” that are installed in the pipeline at regular intervals to collect the liquids carried in a gas stream. 289
  290. 290. PIPELINE DRIPS290
  291. 291. MULTISTAGE SEPARATOR291
  292. 292. INDUSTRIAL PROCESSES TO REMOVE WATER  Water vapor moved through the system must be reduced to acceptable industry levels.  Typically, the allowable water content in gas transmission lines ranges from 4 lb. to 7 lb. per MMSCF.  There are basically three methods employed to reduce this water content. These are:  1. Joule-Thomson Expansion  2. Solid Desiccant Dehydration  3. Liquid Desiccant Dehydration 292
  293. 293. JOULE THOMSON VALVE  Joule-Thomson Expansion utilizes temperature drop to remove condensed water to yield dehydrated natural gas.  The principal is the same as the removal of humidity from outside air as a result of air conditioning in your house.  In some cases glycol may be injected into the gas stream ahead of the heat exchanger to achieve lower temperatures before expansion into a low temperature separator. 293
  294. 294. SOLID DESICCANT DEHYDRATION  Solid desiccant dehydration, also known as solid bed, employs the principal of adsorption to remove water vapor.  Adsorbents used include:  silica gel (most commonly used),  molecular sieve (common in NGV dryers),  activated alumina and  activated carbon. 294
  295. 295. 295
  296. 296. ADSORPTION PROCESS  The wet gas enters into an inlet separator to insure removal of contaminants and free water.  The gas stream is then directed into an adsorption tower where the water is adsorbed by the desiccant.  When the adsorption tower approaches maximum loading, the gas stream is automatically switched to another tower allowing the first tower to be regenerated. 296
  297. 297. REGENERATION  Heating a portion of the mainstream gas flow and passing it through the desiccant bed regenerates the loaded adsorbent bed.  The regeneration gas is typically heated in an indirect heater. This unsaturated regeneration gas is passed through the bed removing water and liquid hydrocarbons.  The regeneration gas exits the top of the tower and is cooled most commonly with an air-cooled heat exchanger.  Condensed water and hydrocarbons are separated and the gas is recycled back into the wet gas inlet for processing. 297
  298. 298. TEG METHOD  The third method of dehydration is via liquid desiccant and is most common in the Northeast United States.  This method removes water from the gas stream by counter current contact in a tray type contactor tower with tri-ethylene glycol (TEG)  Natural gas enters the unit at the bottom of the adsorber tower and rises through the tower were it intimately contacted with the TEG solution flowing downward across bubble trays.  Through this contact, the gas gives up its water vapor to the TEG. 298
  299. 299. TEG METHOD  The water laden TEG is circulated in a closed system, where the water is boiled from the TEG.  The regenerated TEG then is recirculated to the contacting tower. 299
  300. 300. TEG DEHYDRATION UNIT300
  301. 301. PRINCIPLE OF THE PROCESS  Glycol dehydration is a liquid desiccant system for the removal of water from natural gas and natural gas liquids (NGL). It is the most common and economic means of water removal from these streams.  Glycols typically seen in industry include:  1) Triethylene glycol (TEG), TEG is the most commonly used glycol in industry.  2)Diethylene glycol (DEG),  3) Ethylene glycol (MEG), and  4) Tetraethylene glycol (TREG). 301
  302. 302. OBJECTIVE OF THE PROCESS  The purpose of a glycol dehydration unit is to remove water from natural gas and natural gas liquids.  When produced from a reservoir, natural gas usually contains a large amount of water and is typically completely saturated or at the water dew point.  This water can cause several problems for downstream processes and equipment. At low temperatures the water can either freeze in piping or, as is more commonly the case, form hydrates with CO2 and hydrocarbons (mainly methane hydrates). 302
  303. 303. PLUGGING AND CORROSION  Depending on composition, these hydrates can form at relatively high temperatures plugging equipment and piping. Glycol dehydration units depress the hydrate formation point of the gas through water removal.  Without dehydration, a free water phase (liquid water) could also drop out of the natural gas as it is either cooled or the pressure is lowered through equipment and piping.  This free water phase will contain some portions of acid gas (such as H2S and CO2) and can cause corrosion. 303
  304. 304. PROCESS DESCRIPTION  Lean, water-free glycol (purity >99%) is fed to the top of an absorber (also known as a "glycol contactor") where it is contacted with the wet natural gas stream.  The glycol removes water from the natural gas by physical absorption and is carried out the bottom of the column.  Upon exiting the absorber the glycol stream is often referred to as "rich glycol". The dry natural gas leaves the top of the absorption column and is fed either to a pipeline system or to a gas plant.  Glycol absorbers can be either tray columns or packed columns. 304
  305. 305.  After leaving the absorber, the rich glycol is fed to a flash vessel where hydrocarbon vapors are removed and any liquid hydrocarbons are skimmed from the glycol.  This step is necessary as the absorber is typically operated at high pressure and the pressure must be reduced before the regeneration step.  Due to the composition of the rich glycol, a vapor phase having a high hydrocarbon content will form when the pressure is lowered.  After leaving the flash vessel, the rich glycol is heated in a cross-exchanger and fed to the stripper (also known as a regenerator 305

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