New PPT Template for operations on field.pptx

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1. CNPC Niger Petroleum S.A. CNPC Global Solutions Co. Ltd. CNPC Niger Petroleum S.A. Operation Items of Oil Pipeline Operators Lecture 1: Patrol inspection and parameter acquisition of electric pump well

2. Contents 2 Lecture 1: Patrol inspection and parameter acquisition of electric pump well Introduction to Oil & Gas Industry Separation & Storage System Identification, Prevention & Control Measures of Hazard Factors Preparation Operation Procedure Technical Requirements

3. Introduction to Oil & Gas Industry 3 Introduction to Oil & Gas Industry

4. Introduction to Oil & Gas Industry 4 The global economy is based on an infrastructure that depends on the consumption of petroleum. Petroleum is a mixture of hydrocarbon molecules and inorganic impurities that can exist in the solid, liquid(oil) or gas phase. Our purpose here is to introduce you to the terminology used in petroleum industry . The oil and gas industry is usually divided into three major sectors: Upstream, Midstream and Downstream. Upstream refers to exploration and production of crude oil and natural gas, midstream is the primary oil/gas treating, transportation, storage of crude oil and natural gas, downstream refers to the conversion of crude oil and natural gas into thousands of finished products.

5. Introduction to Oil & Gas Industry 5 The oil and gas industry facilities and systems are broadly defined, according to their use in the oil and gas industry production stream: Exploration: Includes prospecting, seismic and drilling activities that take place before the development of a field is finally decided. Upstream: Typically refers to all facilities for production and stabilization of oil and gas. The reservoir and drilling community often uses upstream for the wellhead, well, completion and reservoir only, and downstream of the wellhead as production or processing. Exploration and upstream/production together is referred to as E&P. Midstream: Broadly defined as gas treatment, LNG production and regasification plants, and oil and gas pipeline systems.

6. Introduction to Oil & Gas Industry 6 Refining: Where oil and condensates are processed into marketable products with defined specifications such as gasoline, diesel or feedstock for the petrochemical industry. Refinery offsites such as tank storage and distribution terminals are included in this segment, or may be part of a separate distributions operation. Petrochemical: These products are chemical products where the main feedstock is hydrocarbons. Examples are plastics, fertilizer and a wide range of industrial chemicals.

7. 1. Overview 7

8. Separation & Storage System 8 Separation & Storage System

9. Separation 9 Hydrocarbon ( In organic chemistry, a hydrocarbon is an organic compound consisting entirely of hydrogen and carbon) streams as produced at the wellhead are composed of a mixture of gas, liquid hydrocarbons, and free water . In most cases, it is desirable to separate these phases as soon as possible after bringing them to the surface and handle or transport the two or three phases separately. This separation of the liquids from the gas phase is accomplished by passing the well stream through an gas/oil or gas/oil/ water separator. Different design criteria must be used in sizing and selecting a separator for a hydrocarbon stream based on the composition of the fluid mixture .

10. S eparators 10 A separator is a vessel in which a mixture of fluids that are not soluble in each other, are segregated from one to another. All separation processes rely on physical or chemical differences of the substances to be separated. The type and amount of force necessary to affect the separation is determined by these differences in both physical and chemical properties.

11. Gas liquid separation fundamentals 11 Crude oil is a complex mixture of hydrocarbons , its density is ranges from 40 Lb / ft3 up to 55 Lb / ft3. Gas is a complex mixture of hydrocarbons ,its density is based on the pressure & temp. ,where for typical gas at pressure 750 psig has a density of 2.3 Lb / ft3 and at standard conditions will has a density of 0.1 Lb / ft3. Free gas is a hydrocarbon mixture which found at gaseous status under the reservoir condition from pressure and temperature, and also still a gas at the standard condition of pressure temperature. Dissolved gas is dissolved in oil under the reservoir pressure and temperature and it is liberated as the pressure drop or/and temperature increased. Water also usually produced with gas or oil and may be free water or emulsified water, usually formation water is a brine with a density higher that the fresh water, typical produced water density is 67 Lb / ft3.

12. Separator Types 12 Separator Types (According to No. of Phases) Three Phase Separator Two Phase Separator

13. Separator Types 13 Separator types (according to function) flash tank (gas boot): a vessel used to separate the gas evolved from liquid flashed from a higher pressure to a lower pressure. scrubber or knockout: a vessel designed to handle streams with high gas-to liquid ratios. the liquid is generally entrained as mist in the gas or is free-flowing along the pipe wall. these vessels usually have a small liquid collection section. the terms are often used interchangeably. separator: a vessel used to separate a mixed-phase stream into gas and liquid phases that are "relatively" free of each other. other terms used are scrubbers, knockouts, line drips. slug catcher: a particular separator design able to absorbsustained inflow of large liquid volumes at irregular intervals. “slugging handling”

14. Separator Types 14 The vertical separator has the advantage that it will handle greater slugs of liquid without carry over to the gas outlet, and the action of the liquid level control is not quite as critical. Some disadvantages are that it is more difficult and expensive to fabricate and ship this type of separator in skid mounted assemblies , and it takes a larger diameter separator for a given gas capacity than a horizontal vessel . From this it can be seen that this type of separator is most often used on fluid streams with low gas-oil ratios ; in other words, handling considerably more liquid than gas.

15. Separator Types 15 The horizontal separator in both the double tube and single tube configuration has several advantages over the vertical separator as it is easier to skid mount , less piping is required for field connections, and a smaller diameter is required for a given gas capacity. This type of vessel also has a larger interface area between the liquid and gas phases which aids in separation. When gas capacity is a design criterion , the horizontal vessel is more economical in high pressure separators, due the increased wall thickness required with larger diameters

16. Separator Types 16 Spherical separators offer a compact vessel arrangement . However, this type of vessel has very limited surge space and liquid settling section . The placement and action of the liquid level control in this type of vessel is also very critical.

17. Internal Structure of Separators 17 The principal items of construction that should be present in a good liquid-gas separator are the same regardless of the overall shape or configuration of the vessel. Some of these features are itemized as follows: 1. An inlet device where the primary separation of the liquid and gas is made; 2 . A large settling section of sufficient length or height to allow liquid droplets to settle out of the gas stream with adequate surge room for slugs of liquid; 3 . A mist extractor or eliminator near the gas outlet that will coalesce small particles of liquid that will not settle out by gravity; 4. Adequate controls consisting of level controller, liquid dump valve, gas back pressure valve, safety relief valve, pressure gauge, level gauge, instrument gas regulator and piping. 5. A vortex Breakers

18. Internal Structure of Separators

19. Inlet Diverters 19 Inlet diverters are used to cause the initial bulk separation of liquid and gas . The most common type is the baffle plate diverter , which could be in the shape of a flat plate , a spherical dish , or a cone . Another type, is the centrifugal diverter ; it is more efficient but more expensive. The diverter provides a means to cause a sudden and rapid change of momentum (velocity and direction) of the entering fluid stream. This, along with the difference in densities of the liquid and gas, causes fluids separation

20. Wave Breakers 20 Wave Breakers: In long horizontal separators, waves may develop at the gas–liquid interface . This creates unsteady fluctuations in the liquid level and would negatively affect the performance of the liquid level controller. To avoid this, wave breakers, which consist of vertical baffles installed perpendicular to the flow direction , are used

21. De-foaming Plates 21 Foam at the interface may occur when gas bubbles are liberated from the liquid. Depending on the type of oil and presence of impurities , foam may form at the gas–liquid interface . Foam will occupy a large space in the separator that otherwise would be available for the separation process; therefore, the separator efficiency will be reduced unless the separator is oversized to allow for the presence of foam. The foam, having a density between that of the liquid and gas, will disrupt the operation of the level controller.

22. Sand Jets and Drains 22 Formation sand may be produced with the fluids. Some of this sand will settle and accumulate at the bottom of the separator . This takes up separator volume and disrupts the efficiency of separation . In such cases, vertical separators will be preferred over horizontal separators . However, when horizontal separators are needed, the separator should be equipped with sand jets and drains along the bottom of the separator. Normally, produced water is injected though the jets to fluidize the accumulated sand, which is then removed through the drains.

23. Vortex Breaker 23 The liquid outlets from the separator will be equipped with vortex breakers to reduce disturbance on the liquid table inside. This is basically a flange trap to break any vortex formation and ensure that only separated liquid is tapped off and not mixed with oil or water drawn in through these vortices.

24. Demister 24 A mist extractor or eliminator near the gas outlet that will coalesce small particles of liquid that will not settle out by gravity ; Several types of mist extractors are available: Wire-Mesh Mist Extractor: Vane Mist Extractor Centrifugal Mist Extractor :

25. Factors Affecting Separation 25 There are several basic factors which will affect the operation and separation between the liquid and gas phases in a separator. 1. Separator operating pressure ; 2. Separator operating temperature; 3. Gravity . 4. Retention time 5. Etc..

26. Factors Affecting Separation: Temperature 26 Temperature differences between fluids will affect their relative volatilities due to changing solubility and vapor pressure levels, which changes their equilibrium compositions during separation. Heavier oils have higher viscosity and lower vapor pressure than lighter oils at a given temperature, so they tend to accumulate near the bottom of an oil/water emulsion when the temperature is increased, resulting in improved separation efficiency compared to operating at low temperatures where both phases are more volatile . For example, if a separation occurs by heating oil from refinery streams using heat exchangers before sending it into a thermal separator tower equipped with steam coils through which cooling water flows, the vapor being produced from the lighter oil will have a lower boiling point than that of heavier oils at a given temperature. Temperature changes go hand-in-hand with pressure changes when it comes to separation in a hydrocarbon containing system or vessel.

27. Factors Affecting Separation: Pressure 27 This is the most important principle of oil separation. The pressure change required to separate a light oil from a heavy oil may be different, but there will always be some pressure change involved in separating two or more components of any mixture. Depending on what needs to be done, pressure on a hydrocarbon containing vessel may be manipulated to enhance the separation process. If the vapor pressure in a vessel containing hydrocarbons is decreased, some of the lighter hydrocarbons will flash from the liquid phase into the vapor phase.

28. Factors Affecting Separation 28 Retention time of the oil in the separator can be used to determine how much gas can be recovered. The greater the retention time, the more oil that will be removed. This is due to the fact that as long as oil remains in contact with inert gas, it will not rise. The longer the contact time between the inert gas and liquid, the larger amount of oil will dissolve into the vapor phase. The amount of time a liquid stays in vessel Gravity , or more specifically, the difference in specific gravity of the components being separated is the biggest factor in the time it takes for the components to separate.

29. Storage 29 Storage tanks for crude oil are needed in order to receive and collect oil produced by wells, before pumping to the pipelines as well as to allow for measuring oil properties, sampling, and gauging

30. Storage 30

31. Storage 31 Storage tanks containing organic liquids can be found in many industries, including petroleum producing and refining, petrochemical and chemical manufacturing, bulk storage and transfer operations, and other industries consuming or producing organic liquids. Depending of the type of tank roof, internal and external structure differs. The most common components related to the roof are described below:

32. Types of Storage Tanks 32 The main features of some of the common types of storage tank used by the petroleum industry in general are presented in the next slid(table). The atmospheric tank, or standard storage tank , is one that is designed to be used within plus or minus a few pounds per square inch of atmospheric pressure. It may be open to the atmosphere (vented) or enclosed. As will be explained next, an effective method of preventing vent loss in a storage tank is to use one of the many types of variable-volume tank (next slid). These are built under API Standard 650. They may have floating roofs of the double-deck or single-deck type.

33. Types of Storage Tanks 33 These are lifter-roof types in which the roof either has a skirt moving up and down in an annular seal or is connected to the tank shell by a flexible membrane. Six basic types of designs are used for organic liquid storage tanks: Fixed roof (vertical and horizontal), External floating roof, Domed external (or covered) floating roof, Internal floating roof, Variable vapor space, and Pressure (low and high)

34. Fixed roof tank 34 This type of tank consists of a cylindrical steel shell with a permanently affixed roof, which may vary in design from cone or dome shaped to flat. Losses from fixed roof tanks are caused by changes in temperature, pressure, and liquid level. Fixed roof tanks are either freely vented or equipped with a pressure/vacuum vent. The latter allows the tanks to operate at a slight internal pressure or vacuum to prevent the release of vapors during small changes in temperature, pressure, or liquid level. Fixed roof tanks may have additional vents or hatches, referred to as emergency vents, to provide increased vent flow capacity in the event of excessive pressure in the tank. Of current tank designs, the fixed roof tank is the least expensive to construct and is generally considered the minimum acceptable equipment for storing organic liquids.

35. Fixed roof tank 35

36. External Floating Roof Tanks 36 A typical external floating roof tank (EFRT) consists of an open-top cylindrical steel shell equipped with a roof that floats on the surface of the stored liquid. The floating roof consists of a deck, deck fittings, and a rim seal system. Floating decks that are currently in use are constructed of welded steel plate and are most commonly of two general types: pontoon or double-deck. Pontoon-type and double-deck-type external floating roof tanks are shown here and in the next slid With all types of external floating roof tanks, the roof rises and falls with the liquid level in the tank. External floating decks are equipped with a rim seal system, which is attached to the deck perimeter and contacts the tank wall. The purpose of the floating roof and rim seal system is to reduce evaporative loss of the stored liquid.

37. External Floating Roof Tanks 37

38. Internal Floating Roof Tanks 38 An internal floating roof tank (IFRT) has both a permanent fixed roof and a floating roof inside. There are two basic types of internal floating roof tanks: tanks in which the fixed roof is supported by vertical columns within the tank, and tanks with a self-supporting fixed roof and no internal support columns. Fixed roof tanks that have been retrofitted to use a floating roof are typically of the first type. Internal floating roof tank.

39. Domed External Floating Roof Tanks 39 Domed external (or covered) floating roof tanks have the heavier type of deck used in external floating roof tanks as well as a fixed roof at the top of the shell like internal floating roof tanks. Domed external floating roof tanks usually result from retrofitting an external floating roof tank with a fixed roof. This type of tank is very similar to an internal floating roof tank with a welded deck and a self-supporting fixed roof.

40. Vapor Recovery Units (VRU) 40 The loss of hydrocarbon vapors formed above crude oil or its products—when stored—could be minimized using what is called vapor recovery units (VRUs). If allowed to escape to the atmosphere, these vapors will not only cause a loss of income due to loss of hydrocarbon volume and change in the API of the oil but will also lead to pollution and fire hazards.

41. Vapor Recovery Units (VRU) 41 The three main functions for the vapor recovery system are as follows: To collect vapor from storage/loading facilities; To re-liquefy vapors; To return liquid hydrocarbons to storage.

42. Vapor Recovery Units (VRU) 42 Basically, when we talk about a VRU, what we are looking for is to hook our storage tanks to a ‘‘breather’’ system such as the following: During the day, when the temperature rises and vaporization of the hydrocarbons occur, excess vapors can be released and collected by the VRU; At night, when the vapors cool and condensation takes place leading to partial vacuum, vapors from the VRU will be admitted into the tanks; While pumping in and pumping out liquids to and from the storage tanks, vapors could be vented, [i.e., collected and drawn in, respectively, by such a breather system (VRU)].

43. Types of Storage Loss 43 In general, hydrocarbon losses in storage tanks are identified as follows: Working losses: Filling; Emptying. Other losses: Breathing; Standing; Boiling. Filling losses occur when vapors are expelled from a tank as it is filled, no matter how the vapors are produced. This loss occurs when the pressure inside the tank exceeds the relief-valve pressure. For API tanks, the relief pressure is low and, therefore, filling losses can be relatively high. Emptying losses are experienced by the vapors that are expelled from a tank after the liquid is removed from it.

44. Types of Storage Loss 44 Because vaporization lags behind the expansion of the vapor space during withdrawal, the partial pressure of a hydrocarbon vapor drops. Enough air enters during the withdrawal to maintain the total pressure at the barometric value. However, when vaporization into the new air reaches equilibrium, the increase in the vapor volume will cause some vapor expansion. Breathing losses occur when vapors are expelled from a tank under one of the following conditions: 1. The thermal expansion of the existing vapors 2. An expansion caused by barometric pressure changes 3. An increase in the amount of vapors from added vaporization in the absence of a liquid level change

45. Types of Storage Loss 45 Breathing losses take place in most types of tanks and occurs when the tank’s limits of pressure or volume changes are exceeded. The fixed-roof API type tanks used to store stock tank oil are designed for only for a few inches of water pressure or vacuum and suffer relatively large breathing losses Standing losses are losses of vapor which result from causes other than breathing or a change in liquid level in tanks. Sources of standing losses are vapor escape from hatches or other openings and from glands, valves, and fittings. Boiling losses occur when liquid boils in a tank and vapors are expelled. In other words, the vapor pressure of the liquid exceeds the surrounding pressure

46. Pumps 46 Pumps

47. Pumps 47 Pumps are machines that supply energy to a liquid in order to move it from one place to another. centrifugal pump

48. Pumps 48

49. Pumps 49 What is the main difference between dynamic and positive displacement pumps? The main difference between dynamic and positive displacement pumps lies in the method of fluid transfer.

50. Dynamic Pumps 50 A dynamic pump imparts velocity energy to the fluid, which is converted to pressure energy upon exiting the pump casing

51. Centrifugal pump 51 Why use a centrifugal pump? Available in a wide range of sizes Handle a wide range of head Centrifugal pump is widely used in the refinery production

52. Centrifugal pumps used to transport fluids by the conversion of rotational kinetic energy to the hydrodynamic energy of the fluid flow by virtue centrifugal force. The rotational energy typically comes from an engine or electric motor. The fluid enters the pump impeller along or near to the rotating axis and accelerated by the impeller, flowing radially outward into a diffuser or volute chamber (casing), Axial flow centrifugal pump has higher specific speed than others radial and mixed flow. Centrifugal pumps work by converting kinetic energy into potential energy measurable as static fluid pressure at the outlet of the pump. Bernoulli's describes this action Principle. With the mechanical action of an electric motor or similar, the rotation of the pump impeller imparts kinetic energy to the fluid through centrifugal force. Pumps

53. Pumps 53 the fluid is drawn from the inlet piping into the impeller intake eye and is accelerated outwards through the impeller vanes to the volute and outlet piping. As the fluid exits the impeller, if the outlet piping is too high to allow flow, the fluid kinetic energy is converted into static pressure. If the outlet piping is open at a lower level, the fluid will be released at greater speed.

54. Centrifugal pump 54 Single Stage Multi-Stage

55. Centrifugal pumps can be classified based on the manner in which fluid flows through the pump. It is not classification based on the impeller alone, but it is based on the design of pump casing and the impeller. ● Axial Flow Pump ● Radial Flow Pump ● Mixed Flow Pump The three types of flow through a centrifugal pump are: Centrifugal pump

56. An axial flow pump has a propeller type of impeller running in a casing. The pressure is developed by the flow of liquid over the blades of impeller. The fluid is pushed in a direction parallel to the shaft of the impeller, that is, fluid particles, in course of their flow through the pump; do not change their radial locations. It allows the fluid to enter the impeller axially and discharge the fluid nearly axially Axial Flow Pump Centrifugal pump

57. A centrifugal pump is a rotodynamic pump that uses a rotating impeller to increase the pressure and flow rate of a fluid.The Figure shows the fluid enters the pump impeller along or near to the rotating axis and is accelerated by the impeller, flowing radially outwards into a diffuser or volute chamber, from where it exits into the downstream piping system. In contrast to axial flow pumps, in which the fluid exits the pump axially, the flow deflections in the impellers of radial flow pumps generate higher centrifugal forces. This results in higher heads but also lower flow rates in radial flow pumps. Radial Flow Pump Centrifugal pump

58. Radial flow pumps are in-line centrifugal pump that operate on a horizontal plane in relation to the flow direction of the water. Axial flow pumps are the opposite—they are in-line pumps that work on a vertical plane in relation to the water. Mixed flow pumps as shown in figure are a cross between the two. The impeller sits within the pipe and turns, but the turning mechanism is essentially diagonal, using centrifugal force to move the water along while accelerating it further with the push from the axial direction of the impeller. This creates enough force to generate high rates of flow Mixed Flow Pump Centrifugal pump

59. Main Components of Centrifugal Pumps There are a few components that virtually every centrifugal pump has in common (figure 7). These components include: ● Impeller ● Pump shaft ● Shaft sleeve ● Pump Bearings ● Coupling ● Shaft sealing arrangement ● Casing Main components of centrifugal pumps

60. Figure 7 Main components of centrifugal pumps

61. MAIN COMPONENTS OF CENTRIFUGAL PUMPS The impeller is the main rotating part that provides the centrifugal acceleration to the fluid. Impellers usually made of iron, steel, bronze, brass, aluminum or plastic . Impellers serves to convert mechanical energy of the pump from into velocity energy speed of fluid which is pumped continuously, so that the liquid on the suction side can continually fill the empty caused by the displacement of fluid that entered previously. Impeller Number of impellers = number of pump stages Main components of centrifugal pumps

62. Impellers classified in many ways as following : Impeller ● Based on the pump suction type Single-suction : a single-suction impeller allows liquid to enter the center of the blades from only one direction Double-suction: double-suction impeller allows liquid to enter the center of the impeller blades from both sides simultaneously. This reduces forces exerted on the shaft . Main components of centrifugal pumps

63. ● Based on mechanical construction Open impeller;   No wall to enclose the vanes , have the vanes free on both sides, Open impellers are structurally weak. They are typically used in small-diameter Semi- open impeller; the vanes are free on one side and enclosed on the other. The shroud adds mechanical strength. They also offer higher efficiencies than open impellers. Closed impeller ; the vanes are located between the two discs, all in a single casting. They are used in large pumps with high efficiencies and low required Net Positive Suction Head. Main components of centrifugal pumps

64. Pump Shaft The impeller is mounted on a shaft. The shaft is usually made of steel or stainless steel and is sized to support the impeller. The pump shaft connects to the driver shaft. When the driver turns the pump shaft, the pump starts. It transmit the toques and supporting the impeller and other rotating parts. Shaft Sleeve In most pumps, the portion of the shaft that is under the sealing arrangement is covered with a shaft sleeve. The shaft sleeve is a sleeve of metal, usually bronze or stainless steel, that is designed to either slide or thread onto the shaft. The shaft sleeve is used to position the impeller correctly on the shaft. Pump shafts are usually protected from erosion , corrosion , and wear at the seal chambers, leakage joints, internal bearings, and in the waterways by renewable sleeves. Unless otherwise specified, a shaft sleeve of wear, corrosion, and erosion resistant material shall be provided to protect the shaft. Main components of centrifugal pumps

65. 65 Main components of centrifugal pumps

66. Pump Bearings Centrifugal pumps are equipped with standard ball-type anti-friction bearings . These are the same bearings used in everything from electric motors, to roller skates , to automobiles, and they are lubricated by grease or oil . The pump shaft is supported and held in place by the bearings, which have to be designed to handle all of the loads created by the rotation of the impeller, and sized to provide a reasonable service life. MAIN COMPONENTS OF CENTRIFUGAL PUMPS The bearing housing encloses the bearings mounted on the shaft. The bearings keep the shaft or rotor in correct alignment with the stationary parts under the action of radial and transverse loads. The bearing house also includes an oil reservoir for lubrication, constant level oiler, jacket for cooling by circulating cooling water.

67. Pump Bearings Figure 10 MAIN COMPONENTS OF CENTRIFUGAL PUMPS

68. Couplings can compensate for axial growth of the shaft and transmit torque to the impeller. Shaft couplings can be broadly classified into two groups: rigid and flexible. A-coupling guard is used to protect personnel from accidentally contacting the rotating equipment. Coupling ● Rigid drive coupling uses a flange and bolts to connect the driver shaft to the pump shaft There are two types of drive coupling, these are: ● Flexible drive coupling A flexible drive coupling can move a little to correct the alignment of the driver shaft and pump shaft MAIN COMPONENTS OF CENTRIFUGAL PUMPS

69. 69 MAIN COMPONENTS OF CENTRIFUGAL PUMPS Rigid drive coupling Flexible drive coupling

70. Casing Pump casings serve to seal off the inside of the pump from atmosphere to prevent leakage and retain pressure. In the case of centrifugal pumps, they surround the pump rotor, which transmits energy to the fluid handled via the impeller(s) mounted on the rotating shaft. The inlet and outlet nozzles serve to direct the fluid handled into and out of the pump and are often classified (by their function) as inlet or suction nozzle and discharge nozzle. They are attached to the piping (e. g. using flanges, pipe unions). MAIN COMPONENTS OF CENTRIFUGAL PUMPS

71. Diffuser In some pumps, diffusers are used. Figure 15 shows a floating ring of stationary guide vanes surrounding the impeller. The purpose of the diffuser is to increase the efficiency of the centrifugal pump by turbulent area for the liquid to reduce in velocity, converting kinetic energy into pressure energy. MAIN COMPONENTS OF CENTRIFUGAL PUMPS

72. Shaft Sealing Arrangement Sealing elements, or seals, are components or constructions, which help to limit or prevent the unintentional transition of substances from one space to another. There are many types of sealing elements are specially designed and manufactured to cater for a whole range of different applications such as packing seal ( staffing box ) and mechanical seal MAIN COMPONENTS OF CENTRIFUGAL PUMPS

73. Stuffing Box Figure shows one of the simplest types of shaft seal is the stuffing box. The stuffing box is a cylindrical space in the pump casing surrounding the shaft. Rings of packing material are placed in this space. Packing is material in the form of rings or stands that is placed in the stuffing box to form a seal to control the rate of leakage along the shaft. The packing rings are held in place by a gland and studs with adjusting nuts. As the adjusting nuts are tightened, they move the gland in and compress the packing to expand radially, forming a tight seal between the rotating shaft and the inside wall of the stuffing box MAIN COMPONENTS OF CENTRIFUGAL PUMPS

74. MAIN COMPONENTS OF CENTRIFUGAL PUMPS

75. Mechanical Seal If packing material is not adequate for sealing the shaft. Mechanical seals are used as an alternative method for sealing the shaft. Mechanical seals consist of two basic parts, rotating element attached to the pump shaft and a stationary element attached to the pump casing. Each of these elements has a highly polished sealing surface. The polished faces of the rotating and stationary elements meet each other to form a seal that prevents leakage along the shaft MAIN COMPONENTS OF CENTRIFUGAL PUMPS Mechanical seals vary in design, performance, and cost. The simplest seal consists of just a few parts: a stationary face , a rotating face , a gland , and a spring. The gland fits around the pump shaft and bolts directly to the face of the stuffing box directly onto the pump casing. The stationary seal ring, sometimes called the mating ring, is sealed to the gland and held in place around the pump shaft by the gland The rotating seal ring, sometimes called the primary ring, is sealed to the shaft by an elastomeric element, and is pressed against the stationary mating ring by the spring

76. Mechanical Seal MAIN COMPONENTS OF CENTRIFUGAL PUMPS

77. Parts of Mechanical Seal Rotating and fixed face To support stationary components, contain throttle bushing, allow for seal setting, provide centering of seal components, and to provide port location for flushing Gland and compression springs Between the two faces of the mechanical seal the secondary seals, known as shaft and insert mountings, like O-rings inserted. Secondary sealants The rotating and the fixed faces are the two vital parts of the mechanical seals. The rotating face is connected to the rotating shaft while the fixed face is connected to the pump housing MAIN COMPONENTS OF CENTRIFUGAL PUMPS

78. MAIN COMPONENTS OF CENTRIFUGAL PUMPS

79. 79 1.Motor 2.Coupling guard 3.Coupling 4.Front bearing housing 5.Pump casing 6.Pump bonnet 7.Rear bearing housing 8.Pump bearing 9.Base MAIN COMPONENTS OF CENTRIFUGAL PUMPS

80. Positive Displacement Pumps: 80 A positive displacement pump moves a fixed volume of fluid within the pump casing by applying a force to moveable boundaries containing the fluid volume.

81. Positive Displacement Pumps: 81 Positive Displacement Pump has an expanding cavity on the suction side of the pump and a decreasing cavity on the discharge side. Liquid is allowed to flow into the pump as the cavity on the suction side expands and the liquid is forced out of the discharge as the cavity collapses.

82. Reciprocating pump 82 It is often used where a relatively small quantity of liquid is to be handled and where delivery pressure is quite large. In reciprocating pumps, the chamber in which the liquid is trapped.

83. Reciprocating pump 83 Structure of reciprocating pumps 1- Cylinder 2- Piston or plunger 3- Piston rod 4- Inlet check valve 5- Discharge check valve

84. Reciprocating pump 84 Sing le-acting reciprocating pump

85. Reciprocating pump 85 Double-acting reciprocating pump

86. Gear Pump 86 Working principle As the gears rotate they separate on the intake side of the pump, creating a void and suction which is filled by fluid. The fluid is carried by the gears to the discharge side of the pump, where the meshing of the gears displaces the fluid. External gear pump design for hydraulic power applications Internal gear pump design for high viscosity fluids

87. Screw Pump 87 Working Principle: A screw pump is a positive-displacement (PD) pump that use one or several screws to move fluids or solids along the screw(s) axis.

88. Lobe Pump 88 Working Principle They are similar to external gear pumps in operation in that fluid flows around the interior of the casing. Unlike external gear pumps, however, the lobes do not make contact. Lobe contact is prevented by external timing gears located in the gearbox.

89. Vacuum pump 89

90. Diaphragm pump 90 Flexible diaphragm is used (rubber, thermo-plastic, metal) Can handle highly viscous liquids Can handle toxic or corrosive liquids

91. Metering System 91 Metering System

92. Metering System 92 Oil and gas metering or measurement is the phase along the hydrocarbon supply value chain where exploration and production (E&P) efforts turn into profits for operators, investors, and other relevant stakeholders. Hydrocarbon metering is carried out using specialized and high-precision equipment to ensure accuracy.

93. Oil and gas measurement 93 Oil and gas measurement is the process of quantifying the mass or volume of hydrocarbons produced as the oil & gas is sold to a buyer along the supply chain. Before custody transfer, the operator will separate oil or natural gas. Entrained solids, water vapor, and other impurities are removed from crude oil before it is quantified and sold. Similarly, water vapor, sulfur, and other contaminants are extracted from natural gas. After cleanup, the oil and gas must meet a certain specification in order to qualify to be sold.

94. Oil and gas measurement 94 Crude oil is an unrefined mix of hydrocarbon fluid that has been obtained from an oil well. This liquid is primarily what is sold as a commodity. The unit of sale is barrels of crude (BBL) which is equivalent to 42 US gallons. After separating water molecules and sediment from crude, the volume can be ascertained using one of two methods: For small volumes (1-100 barrels of oil per day), oil measurement is carried out directly from storage tanks in runs.  For large volumes (100-100,000 barrels of oil per day), operators typically use an automated measurement system called a LACT unit.

95. Oil and gas measurement : Run Method 95 A run is the process of drawing oil drawn from a lease location and transporting it off-site for treatment. First, we take a sample of crude and place it in a centrifuge for a ‘shake-out’ test which separates the water molecules and sediments from the mixture.

96. Oil and gas measurement : Run Method 96 Afterward, the volume of a run is measured by lowering a measuring strap into the storage tank. This device is weighted on one end and contains an outlet valve which opens to discharge fluid into a pipeline or truck nearby. When the storage tank is almost empty, a second measuring strap reading is taken (and the volumes compared) to find the exact volume of oil drawn

97. Oil and gas measurement : Metering Technology 97  Wide range of equipment for oil and gas flow measurement are available on the market. Selecting the right equipment will depend on the type of fluid to be metered. Some common examples are: LACT Metering Skid etc

98. Oil and gas measurement : LACT 98 Lease Automatic Custody Transfer (LACT) units measure the net volume and quality of hydrocarbons during product transfer in midstream oil and gas operations. 

99. Oil and gas measurement : LACT 99 LACT units  are automated systems for measurement, sampling, and transfer of liquid hydrocarbons with volumes ranging from 100 – 1000 barrels/hour between a stock tank and feed line.

100. Oil and gas measurement : Metering Skid 100 A metering skid is an automated system for measuring crude or natural gas comprising several measurement instruments assembled on a steel frame. They are used to determine financial estimates during custody transfer metering. Metering skids usually consist of several flow meters for metering fluid flow, proving system and a gas chromatograph for analyzing and metering gaseous hydrocarbons.

101. Oil and gas measurement : Metering Skid 101 Some ancillary instruments that may be found on a metering skid include Coriolis flow meters, turbine or positive displacement flow meters, densitometer, back pressure and thermal relief valves, air eliminator, prover connections, and PLC control systems.

102. Oil and gas measurement: Coriolis flow-meter 102 A Coriolis flow-meter is a special type of flow meter that measures a mass of fluid based on inertia. The ‘Coriolis effect’ is a physical phenomenon where inertia created by a mass of fluid flowing through an oscillating tube cause the tube to twist proportionally to mass flow-rate.

103. Oil and gas measurement: Coriolis flow-meter 103 In practice, hydrocarbon liquid or natural gas flows through the inlet tube on a Coriolis flow-meter is vibrated with an actuator that causes turbulence in the fluid to be measured.

104. Oil and gas measurement Coriolis flow-meter 104 Coriolis flow-meters are widely regarded as some of the most accurate metering instruments in the industry. However, these instruments can have a margin of error when the fluid under test contains bubbles.

105. Oil and gas measurement Positive displacement flow-meters 105 Other oil and gas flow-meter types include turbine or positive displacement (PD) flow-meters. These are special oil and gas measurement instruments that determine the volume of fluid flowing through them by repeatedly trapping a quantity of the fluid and releasing it.

106. 106 Positive displacement flow-meters utilize multiple rotating parts that ‘mesh’ together like a pair of gears. PD flow-meters can measure the volumetric flow through pipelines for a variety of fluids including water, hydrocarbons, corrosive liquids, etc Oil and gas measurement Positive displacement flow-meters

107. Fiscal metering 107 While the terms fiscal metering and custody transfer are often used interchangeably, it’s important to differentiate between the two. In some scenarios they can be swapped without but for oil and gas experts, it’s best to understand the difference. Partners, authorities and customers all calculate invoices, taxes and payments based on the actual product shipped out. Often custody transfer also takes place at this point, means a transfer of responsibility or title from the producer to a customer, shuttle tanker operator or pipeline operator. Although some small installations are still operated with dipstick and manual records, larger installations have analysis and metering equipment

108. Fiscal metering 108 To make sure readings are accurate, a fixed or movable prover loop for calibration is also installed. The illustration here(picture) shows a full liquid hydrocarbon (oil and condensate) metering system. The analyzer instruments on the left provide product data such as density, viscosity and water content. Pressure and temperature compensation is also included.

109. Fiscal metering 109

110. Fiscal metering 110 To obtain the required accuracy, the meters are calibrated. The most common method is a prover loop. A prover ball moves though the loop, and a calibrated volume is provided between the two detectors (z) . When a meter is to be calibrated, the four-way valve opens to allow oil to flow behind the ball.

111. Fiscal metering 111 The number of pulses from it passes one detector Z to the other and is counted. After one loop, the four-way valve turns to reverse flow direction and the ball moves back, providing the same volume in reverse, again counting the pulses. From the known reference volume, number of pulses, pressure and temperature the flow computer can calculate the meter factor and provide accurate flow measurements using formulas from industry standard organizations such as API MPMS and ISO 5024. The accuracy is typically ± 0.3% of standard volume.

112. Fiscal metering 112 Orifice plates are sensitive to a build-up of residue and affect the edges of the hole (Picture). Larger new installations therefore prefer ultrasonic gas meters that work by sending multiple ultrasonic beams across the path and measure the Doppler effect

113. Process Control: valves and instruments 113 Process Control: valves and instruments

114. 114 Before getting marketable products we have to process the crude oil. Before processing the crude oil, we have to understand how the process is controlled. Before understanding the process control, we have to master control equipments such as valves, control valves, pressure transmitters/Gauges, temperatures transmitters/Gauges, flow-meters..etc. Process Control: valves and instruments

115. 115 Common flow-sheet symbols Process Control: valves and instruments

116. Valves 116 A valve is a mechanical device that controls the flow of fluid and pressure within a system or process. A valve controls system or process fluid flow and pressure by performing any of the following functions: Stopping and starting fluid flow Varying (throttling) the amount of fluid flow Controlling the direction of fluid flow Regulating downstream system or process pressure Relieving component or piping over pressure

117. Basic Parts of Valves 117 There are many valve designs and types that satisfy one or more of the functions identified above. A multitude of valve types and designs safely accommodate a wide variety of industrial applications. Regardless of type, all valves have the following basic parts: the body, bonnet, trim (internal elements), actuator, and packing.

118. Basics Parts of Valves 118

119. Types of Valves 119

120. Types of Valves 120 1.Base of Internal Structure Because of the diversity of the types of systems, fluids, and environments in which valves must operate, a vast array of valve types have been developed. Examples of the common types are the globe valve, gate valve, ball valve, plug valve, butterfly valve, diaphragm valve, check valve, pinch valve, and safety valve . Each type of valve has been designed to meet specific needs. Some valves are capable of throttling flow, other valve types can only stop flow, others work well in corrosive systems, and others handle high pressure fluids. Each valve type has certain inherent advantages and disadvantages

121. Ball Valves 121 Ball valves allow quick, quarter turn on-off operation and have poor throttling characteristics.

122. Globe Valves 122 Globe valves are used in systems where good throttling characteristics and low seat leakage are desired and a relatively high head loss in an open valve is acceptable.

123. Gate Valves 123 Gate valves are generally used in systems where low flow resistance for a fully open valve is desired and there is no need to throttle the flow.

124. Butterfly Valves 124 Butterfly valves provide significant advantages over other valve designs in weight, space, and cost for large valve applications.

125. Check Valves 125 Check valves automatically open to allow flow in one direction and seat to prevent flow in the reverse direction. Swing Tilting disc Lift

126. Safety/Relief Valves 126 Safety/relief valves are used to provide mechanical over-pressurization protection for a system Safety Relief

127. Types of Valves 127 2. Base on the Actuator By themselves, valves cannot control a process. Manual valves require an operator to position them to control a process variable. Valves that must be operated remotely and automatically require special devices to move them. These devices are called actuators. Actuators may be manual, pneumatic, hydraulic, or electric (solenoids or motors).

128. Pneumatic actuators 128 Pneumatic actuators use air pressure on either one or both sides of a diaphragm to provide the force to position the valve.

129. Hydraulic actuators 129 Hydraulic actuators use a pressurized liquid on one or both sides of a piston to provide the force required to position the valve.

130. Solenoid actuators 130 Solenoid actuators have a magnetic slug attached to the valve stem. The force to position the valve comes from the magnetic attraction between the slug on the valve stem and the coil of the electromagnet in the valve actuator

131. Electric actuators 131 Electric motor actuators consist of reversible electric motors connected to the valve stem through a gear train that reduces rotational speed and increases torque.

132. Pressure Measurement Devices  Burdon Tube Pressure Gauge  Diaphragm Pressure Gauge  Bellow Pressure Gauge The most common pressure sensing elements are: Pressure Measurement

133. Burdon Tube Pressure Gauge Bourdon tube is a metal tube that is sealed on one end. When pressure is applied to the inlet, the Bourdon tube changes shape (straightens). A bourdon tube changes shape with increasing and decreasing pressure. The Bourdon tube is connected to a gear mechanism and pointer. When the bourdon tube straightens, the gear mechanism moves the pointer around the scale Pressure Measurement

134. Diaphragm Pressure Gauge A diaphragm is a flexible metal disk that moves out when pressure is applied to one side. The metal disk is connected to a pointer. As the diaphragm moves out, the pointer moves around the scale. Pressure Measurement

135. Bellows Pressure Gauge A bellows is a flexible metal can that moves out when pressure is applied to one side. The bellows is connected to a pointer. As the bellows moves out, the pointer moves around a scale. Pressure Measurement

136. Overview Level measurements are needed for inventory and accounting or product storage, inventory and distribution or raw material for processes and proper operation or fractionating towers and distillation columns, controlling water level in boiler drums and other similar process control applications where accurate level determinations are required. Level control is used to: Obtain process material balances when variations occur in raw material flow rates. Proper functioning of fractionating towers, settling tanks, reactors and other equipment's. Regulate the flow of intermediate and finished products to and from temporary storage facility. Level Measurement

137. Measurement Devices  Level Sight Glass  Hand Reel & Tape  Radar Level Gauge  Ultrasonic Level Gauge  Differential Pressure Level Gauge Level Measurement

138. Hand Reel & Tape The hand reel tape (like a measuring tape) is the simplest way to obtain a manual level measurement. It involves lowering a hand reel tape down into a vessel. A weight pulls the tape to the bottom of the vessel. After the tape hits the bottom, it is reeled back. Level Measurement

139. Sight Glass Figure shows a sight glass (also called a gauge glass). It is a glass tube mounted on the outside of a vessel. It is connected to the top and bottom of the vessel. Liquid in the vessel flows into the sight glass— the liquid level in the sight glass is the same as the liquid level in the vessel. Level Measurement

140. Radar Level Gauge Figure (A) shows a radar level indicators are similar to ultrasonic level indicators. Instead of sound waves, a radar level indicator uses low energy electromagnetic waves to detect the level of liquid in a vessel. The time it takes for electromagnetic waves to go down to the liquid and bounce back up is measured and used to calculate the level in the vessel. Level Measurement

141. Ultrasonic Level Gauge It is suitable for a wide range of applications/process conditions and tank types. Figure (A) shows movement of the waves from a detector to the object and reflected again to the detector . The time it takes for the sound waves to go down to the liquid and back to the indicator is measured. This time is used to calculate the height of the liquid in the vessel. Level Measurement

142. Differential Pressure Level Gauge A differential pressure Level indicator measures the differential pressure between the top and bottom of a vessel. This differential pressure is used to calculate the height of the liquid inside the vessel. Level Measurement

143. Flow measurement Overview Flow measurement is the quantification of bulk  fluid  movement. Flow can be measured in a variety of ways. Positive-displacement flow meters accumulate a fixed volume of fluid and then count the number of times the volume is filled to measure flow. Other flow measurement methods rely on forces produced by the flowing stream as it overcomes a known constriction, to indirectly calculate flow. Flow may be measured by measuring the velocity of fluid over a known area. Flow measurement

144. Flow Rate Measurement Devices There are many types of flow meters. The most common types are:  Variable Area Flow Meter ( rotameter )  Magnetic Flow Meter  Turbine Flow Meter  Orifice Flow Meter  Venturi Flow Meter  Ultrasonic Flow Meter  Coriolis flow meter Flow measurement

145. Variable Area Flow Meter Figure shows a variable area flow meter (also called a rotameter) consists of a tapered tube with a float inside. A scale on the tube shows flow rate. When fluid flows up through the tube, the float is pushed by fluid flow As the float moves, there is more area around the float Flow measurement

146. Magnetic Flow Meter The fluid in the pipe is the conductor. As it moves through the magnetic field, it creates voltage. The faster the fluid, the higher the voltage. The voltage is measured and used to calculate flow in the pipe. The flow is converted into an electrical signal and sent to a digital display or a process control system Flow measurement

147. Turbine Flow Meter The turbine flow meter uses a turbine to sense flow in a pipe. A turbine is like an electric fan, if it is turned off, any wind will make the fan blades spin. The faster the wind, the faster the fan blades will turn.  A turbine flow meter works the same way. As fluid flows through the turbine meter, the turbine starts to spin. A flow straightener Makes the fluid flow in straight lines. This helps improve accuracy of the flow meter. Flow measurement

148. Orifice Plate Flow Meter Figure shows an orifice plate, there's a hole in the middle of the plate. The plate is put inside a pipe to create pressure drop. Pressure drop occurs when the fluid in the pipe has to squeeze through the hole in the middle of the orifice plate. Pressure gauges before (upstream) and after (downstream) the orifice plate are used to measure pressure as shown in figure. The upstream pressure is higher than the downstream pressure. The difference between the two pressures (differential pressure) is used to calculate the flow rate. Flow measurement

149. Venturi Tube Flow Meter A venturi tube is a restriction in a pipe as shown in figure. Instead of a plate with a hole, the diameter of the venturi tube gets smaller. Pressure measurements are taken upstream of the restriction and in the middle of the venturi tube (when the diameter is smallest). This differential pressure is used to calculate flow rate. Flow measurement

150. Ultrasonic Flow Meter An  ultrasonic flow meter  is a type of flow meter that measures the velocity of a fluid with ultrasound to calculate volume flow. Using ultrasonic transducers, the flow meter can measure the average velocity along the path of an emitted beam of ultrasound, by averaging the difference in measured transit time between the pulses of ultrasound propagating into and against the direction of the flow or by measuring the frequency shift from the Doppler effect. Flow measurement

151. Temperature Measurement Devices Temperature measurement devices (temperature indicators) are installed in a process to measure temperature. Temperature measurements ensure that the process is operating efficiently. They are one of the first process variables to respond if there is a problem with the process or there is an unsafe condition. There are many types of temperature indicators. The type depends on how it operates. Temperature measurement

152. Measurement Devices  Glass Thermometer  Filled – System Thermometer  Bimetallic Thermometer  Resistance Temperature Detector (RTD)  Thermocouple The most common temperature indicators are: Temperature measurement

153. Glass Thermometer A glass thermometer as shown in figure is a sealed glass bulb with a capillary tube. The glass bulb is filled with a liquid and a temperature scale is marked on the capillary tube. When the glass bulb is heated, the liquid expands into the capillary tube. The temperature is read from the scale when the liquid has stopped rising in the capillary tube. Temperature measurement

154. Filled-System Thermometer A filled-system thermometer as shown in the figure consists of a reservoir (or bulb), capillary tube, and temperature display. The capillary tube allows the temperature display to be located where it is convenient for an operator to read. It also allows the bulb to be installed far inside a closed vessel. Temperature measurement

155. Bimetallic Thermometer A bimetallic thermometer consists of a temperature sensor and temperature display. This thermometer has scale on the temperature display.   A bimetallic thermometer uses a bimetallic strip to sense temperature. A bimetallic strip is made of two strips of different metals that are bonded together. When heat is applied to a bimetallic strip, the metals expand at different rates. This causes the bimetallic strip bends when heated.   Temperature measurement

156. Thermocouple A thermocouple consists of two wires that are joined together at one end (called the hot junction). The other ends of the wires (called the cold junction) are attached to a meter that measures electricity (called volt meter—it measures voltage). The wires in a thermocouple are made of different metals. When the hot junction is heated, the wires generate voltage. The voltage is measured by the volt meter. Temperature measurement

157. Thermo Resistances Resistance temperature detectors are attractive alternatives to thermocouples when high accuracy and stability. They work on the principle that the resistivity of metals is dependent upon temperature; a temperature increases, resistance increases. Platinum is usually used, because it is stable at higher temperatures and provides a near-linear temperature-to resistance response. The Figure shows a resistance temperature detector (RTD) consists of an electrical circuit that includes an RTD, source of electricity (like a battery), and a meter that measures electricity called ammeter, measures current. Temperature measurement

158. Vibration Monitoring Vibration Monitoring for oil and gas machines and equipment Safely monitoring vibration on machinery operating in hazardous oil and gas operations . Vibration measurement can be performed by fixed vibration sensors or by movable device by Condition monitoring engineer. The importance of Vibration Monitoring devices that expect the mechanical problems of the machines in early stage of happening. Typical oil and gas machines/equipment where vibration monitoring products are used include: Blowers, Centrifuge, chillers, compressors. Fans, gearboxes, mixers, motors, pumps. Reciprocating compressors, turbines.

159. Vibration Monitoring Vibration Sensors

160. Process Automation 160 A process automation can be described as a system that can control the output quantity. Basically, it is a device or a set of the device which can manage, command, and regulate the operation of the other device or a system that uses control loops. So this system can control and regulate the operation of another system. A system consists of different elements and devices that are interconnected to do a process.

161. Process Automation 161 The process automation system is formed by the component interconnection and thus a system configuration is achieved and it will control the system. The major components of a process automation are actuators, sensors, reference input, and the system. The system is the process or plant which needs to be controlled and the actuator would convert the control signal to a power signal. The sensor would measure the system output and the reference input represents the required output.

162. Automation control 162 During the early years of industrial manufacturing, the process variables were controlled manually.

163. Automation control 163 The diagram of the manual process

164. Automatic control 164 Manually control loop

165. Automatic control 165 Nowadays ,the process operations are performed by automated systems that require only minimal human intervention.The hardware used in an automated system is called instrumentation equipment. Distributed Control System

166. Automatic control 166 The automatic control loop

167. Automatic Control: Purposes 167

168. Automatic Control: Structure 168 A utomatic control and monitor systems application Measurement Instruments Engineering station Operator station Actuator Controller Industrial control system

169. Measurements Instruments 169 Measurements consists of several elements which are used to carry out particular functions.These functional elements are: Sensor Signal processor Data presentation Sensor

170. Measurements Instruments 170

171. Measurements Instruments: Types of Instruments 171 “You can’t control what you don’t measure” is an old adage, meaning that instrumentation is a key component of a safe and optimised control system. We have several types of intruments depending of the function/service to perform.

172. Measurements Instruments: Performance term : 172 The perfomance of an instrument is ralated to many qualities such as:

173. Performance term : Accuraccy 173 Accuracy is the indicator of how close the value give by a measurement system can be expected to be to the true value. Accuracy is one of critical performance terms to identify instruments quality. What is the accuracy grade to this pressure gauge from the left picture ? Answer: Accuracy is ± 2.5% Pressure gauge

174. Performance term : Stability 174 The stability of a system is its ability to give the same output when used to measure a constant input over a period of time. The term zero drift is used for the changes that occur in output when there is zero input.

175. Performance term : Repeatability 175 The term repeatability is used for the ability of ameasurement system to give the same value for repeated measurements of the same value of a variable. Not accurate, but repeatable Not accurate, and not repeatable Accurate&Repeatable

176. Performance term : Sensitivity 176 Sensitivity(For pointer gauge) Sensitivity: pointer displacement/input variable Sensitivity limits indicates instruments minium input variability to drive pointer to move.

177. Controller/ Actuators 177 The mechanism that physically moves the element ,which restricts flow in a control valve ,is the actuator.

178. Controller/ Actuators 178 Actuator is the main element in process control loop

179. Controller/ Actuators 179 Actuator allow control valve(control loop) to regulate: pressure, flow, temperature, level.

180. Controller/Actuators 180 Depending of the type of process and the environmental conditions we use many type of actuators

181. Industrial control system 181 Industrial control system (ICS) is a general term that encompasses several types of control systems, including supervisory control and data acquisition (SCADA) systems, distributed control systems (DCS) and other smaller control system configurations such as skid-mounted Programmable Logic Controllers (PLC) often found in the industrial sectors and critical infrastructures.

182. Industrial control system 182 ICSs are typically used in industries such as electrical, water, oil and gas, chemical, transportation, pharmaceutical, pulp and paper, food and beverage, and discrete manufacturing (e.g., automotive, aerospace, and durable goods.)

183. SCADA System 183 SCADA systems are highly distributed systems used to control geographically dispersed assets, often scattered over thousands of square kilometers, where centralized data acquisition and control are critical to system operation. They are used in distribution systems such as water distribution and wastewater collection systems, oil and gas pipelines, electrical power grids, and railway transportation systems. A SCADA control center performs centralized monitoring and control for field sites over long-distance

184. SCADA System 184 communications networks, including monitoring alarms and processing status data. Based on information received from remote stations, automated or operator-driven supervisory commands can be pushed to remote station control devices, which are often referred to as field devices.

185. SCADA System 185 Field devices control local operations such as opening and closing valves and breakers, collecting data from sensor systems, and monitoring the local environment for alarm conditions.

186. DCS System 186 DCSs are used to control industrial processes such as electric power generation, oil and gas refineries, water and wastewater treatment, and chemical, food, and automotive production. DCSs are integrated as a control architecture containing a supervisory level of control overseeing multiple, integrated subsystems that are responsible for controlling the details of a localized process.

187. DCS System 187 Product and process control are usually achieved by deploying feed back or feed forward control loops whereby key product and/or process conditions are automatically maintained around a desired set point.

188. DCS System 188 To accomplish the desired product and/or process tolerance around a specified set point, specific programmable controllers (PLC) are employed in the field and proportional, integral, and/or differential settings on the PLC are tuned to provide the desired tolerance as well as the rate of self-correction during process upsets. DCSs are used extensively in process-based industries.

189. PLC System 189 PLCs are computer-based solid-state devices that control industrial equipment and processes. While PLCs are control system components used throughout SCADA and DCS systems, they are often the primary components in smaller control system configurations used to provide regulatory control of discrete processes such as automobile assembly lines and power plant soot blower controls. PLCs are used extensively in almost all industrial processes.

190. PLC System 190 The process-based manufacturing industries typically utilize two main processes: Continuous Manufacturing Processes. These processes run continuously, often with transitions to make different grades of a product. Typical continuous manufacturing processes include fuel or steam flow in a power plant, petroleum in a refinery, and distillation in a chemical plant.

191. PLC System 191 Batch Manufacturing Processes. These processes have distinct processing steps, conducted on a quantity of material. There is a distinct start and end step to a batch process with the possibility of brief steady state operations during intermediate steps.

192. PLC System 192 The discrete-based manufacturing industries typically conduct a series of steps on a single device to create the end product. Electronic and mechanical parts assembly and parts machining are typical examples of this type of industry. Both process-based and discrete-based industries utilize the same types of control systems, sensors, and networks. Some facilities are a hybrid of discrete and process-based manufacturing. While control systems used in oil & gas industries are very similar in operation, they are different in some aspects. One of the primary differences is that DCS or PLC-controlled subsystems are usually located within a more confined factory or plant-centric area, when compared to geographically dispersed SCADA field sites.

193. PLC System 193 DCS and PLC communications are usually performed using local area network (LAN) technologies that are typically more reliable and high speed compared to the long-distance communication systems used by SCADA systems. In fact, SCADA systems are specifically designed to handle long-distance communication challenges such as delays and data loss posed by the various communication media

194. PLC System 194 DCS and PLC systems usually employ greater degrees of closed loop control than SCADA systems because the control of industrial processes is typically more complicated than the supervisory control of distribution processes.

195. 195 Heaters Heaters

196. 196 Heat Transfer Mechanisms There are three mechanisms of heat transfer Conduction Convection Radiation Conduction Conduction of heat occurs by the excitation of adjacent molecules where said molecules have little or no movement. Conduction thus is the primary mechanism in solids and may be an important component mechanism with some liquids at low flow rates. Heat Transfer Mechanisms

197. 197 Convection Convection is that mechanism where heat energy is transferred by the physical movement of molecules from place to place. Any factor which enhances or hinders this movement affects the rate of heat transfer by convection. Radiation Radiation is the process whereby a body emits heat waves that may be absorbed, reflected or transmitted through a colder body. Heat Transfer Mechanisms

198. 198 Types Of Heat transfer equipment

199. 199 Functions of heat transfer equipment in petroleum industry:- Cooler: Cooler reduce the temperature of liquid or gas using water or air to remove heat. Heater: Heaters increase the temperature of a liquid or gas by adding heat using condensing steam, hot oil etc. Condenser: Condensers remove heat from gas, changing it to a liquid. Vaporizer: Vaporizers add heat to a liquid, changing it to a gas. Reboiler: Reboilers provide heat to a liquid in the bottom of a distillation tower. Types Of Heat transfer equipment

200. 200 Chiller: Chillers cool a liquid or gas using a refrigerant instead of water. Exchanger: Exchangers perform basically two functions. They can heat a cold process stream by using a hot process fluid, or they can cool a hot process stream by using a cold process fluid. Types Of Heat transfer equipment

201. Heaters 201 Heaters Heaters are vessels used to raise the temperature of the liquid before it enters a gun-barrel, wash tank, or horizontal flow treater. They are used to treat crude oil emulsions. The two types of heaters commonly used in upstream operations are indirect fired heaters and direct fired heaters. Both types have a shell and a fire tube. The fire tube contains within it a flame caused by the mixture of air and natural gas ignited by a pilot light and the hot exhaust gases which result from this combustion. The hot external surface of the fire tube heats a bath of liquid in which it is immersed. Indirect heaters have a third element, which is the process flow coil. Heaters have standard accessories such as burners, regulators, relief valves, thermometers, temperature controllers, etc.

202. 202 Indirect Fired Heaters: Oil flows through tubes that are immersed in water, which in turn is heated by a fire tube. Alternatively, heat may be supplied to the water bath by a heating fluid medium, steam, or electric immersed heaters instead of a fire tube. Indirect heaters maintain a constant temperature over a long period of time and are safer than direct heaters. Hot spots are not as likely to occur on the fire tube if the calcium content of the heating water is controlled. The primary disadvantage is that these heaters require several hours to reach the desired temperature after they have been out of service. Indirect Fired Heaters

203. 203 Indirect Fired Heaters

204. Direct Fired Heaters 204 Direct Fired Heaters: Oil flows through an inlet distributor and is heated directly by a fire box. Alternatively, heat may be supplied to the oil flow by a heating fluid medium, steam, or an electric immersed heater instead of the fire tube. Direct fired heaters are quick to reach the desired temperature, are efficient (75 to 90%), and offer a reasonable initial cost. Direct fired heaters are typically used where fuel gas is available and high volume oil treating is required. Oil flows through an inlet distributor and is heated directly by a fire box. Alternatively, heat may be supplied to the oil flow by a heating fluid medium, steam, or an electric immersed heater instead of the fire tube. Direct fired heaters are quick to reach the desired temperature, are efficient (75 to 90%), and offer a reasonable initial cost. Direct fired heaters are typically used where fuel gas is available and high volume oil treating is required.

205. Direct Fired Heaters 205 On the other hand, they are hazardous and require special safety equipment. Scale may form on the oil side of the fire tube, which prevents the transfer of heat from the fire box to the oil emulsion. Heat collects in the steel walls under the scale, which causes the metal to soften and buckle. The metal eventually ruptures and allows oil to flow into the fire box, which results in a fire. The resultant blaze, if not extinguished, will be fed by the incoming oil stream.

206. Direct Fired Heaters 206

207. Heaters Classification 207 Classification based on fuel Gas firing Oil firing Combination firing

208. Heaters Classification 208 Classification based on Draft Natural Draft- Forced Draft - using F.D fan Induced Draft – using I.D fan and drop out doors. Balanced Draft – using F.D and I.D fans.

209. Heaters 209 Draft is the difference in pressure which causes the flow of air into the furnace and flue gases through the heater. The pressure differential is caused by the difference in densities of the flue gas in the heater and stack and the air surrounding the furnace. Positive draft means flue gas pressure is below ambient pressure. Negative draft means fluid pressure is above ambient pressure at the same elevation. Draft is controlled by stack damper or by ID fan. Ideal draft in a natural draft furnace is -1 mm wc .

210. Heaters 210 Complete Combustion Complete combustion occurs when 100% of the energy in the fuel is extracted There must be enough air in the combustion chamber for complete combustion to occur. The combustion process is extremely dependent on time, temperature, and turbulence. Excess Air In order to ensure complete combustion, combustion chambers are Fired with excess air. Excess air increases the amount of oxygen and nitrogen entering the flame increasing the probability that oxygen will find and react with the fuel. ( Nox formation) Addition of excess air greatly lowers the formation of CO.

211. Burners 211 Burners Classification based on fuel Fuel gas burner. Fuel oil burner. Combination burner. Classification based on draft Natural draft. Forced draft

212. 212 Corrosion and Cathodic Protection Corrosion and Cathodic Protection

213. 213 What's Corrosion? Corrosion is an electrochemical process in which a current leaves a structure at the anode site, passes through an electrolyte , and re-enters the structure at the cathode site . For example, one small section of a pipeline may be anodic (positively charged) because it is in a soil with low resistivity compared to the rest of the line. Current would leave the pipeline at that anode site, pass through the soil, and re-enter the pipeline at a cathode (negatively charged) site. Current flows because of a potential difference between the anode and cathode. That is, the anode potential is more negative than the cathode potential, and this difference is the driving force for the corrosion current. The total system (anode, cathode, electrolyte, and metallic connection between anode and cathode) is termed a corrosion cell . Corrosion and Cathodic Protection

214. 214 How common is that? Corrosion is actually very common. It can happen to most of the structures that exist in an electrolytic medium. From Sea lines to Pipelines to tanks, ships, and any other metals, corrosion can occur leaving significant damage that maybe, in some cases, irreparable!!! How does corrosion work?! Corrosion happens following the Electrochemical Series. The same thing mainly happens in a galvanic Cell. The cathode, the pipeline, or the tank, gets corroded in the presence of elements or compounds of elements that are more active according to the Electrochemical Series, Sometimes the Cathode and Anode exist on the same pipeline resulting in a Galvanic Corrosion. Corrosion and Cathodic Protection

215. 215 Galvanic Corrosion? The Anode and Cathode are on the same surface of the pipe. The soil, or medium, is the electrolyte. A closed electric circuit exists in an ionic current flowing between Cathode and Anode in the soil, then electronic current between cathode and anode inside the metal. Possible Solutions? Plan A: Coating. Especially with Zinc-rich coatings. It's a possible solution. But its disadvantages are that it's not a sufficient way of protection against corrosion. Moreover, scratches at installation, periodic repainting, and hardships of repainting of some structures, all of that make it really hard to rely on Coating alone. Plan B: Cathodic Protection. Corrosion and Cathodic Protection

216. 216 What's Cathodic Protection? Cathodic Protection is a method to reduce corrosion by minimizing the difference in potential between anode and cathode. This is achieved by applying a current to the structure to be protected using some method that'll later be explained. When enough current is applied, the whole structure will be at one potential; thus, anode and cathode sites will not exist. Cathodic Protection is commonly used on many types of structures, such as pipelines, underground storage tanks, locks, and ship hulls. Then, let's make a GALVANIC CELL. 1. Cathode (the structure to be protected). 2. Anode (to supply protective current). 3. Electrolyte (soil or water). There're two methods of applying Cathodic Protection. But before that, let's talk about Corrosive Medium. Corrosion and Cathodic Protection

217. 217 Corrosive Medium: Soil consists of solid particles and pores filled with moisture and air. Soils with a high proportion of sand have very limited storage capacity for water, whereas clays are excellent in retaining water. Soils with high moisture content, high electrical conductivity, high acidity, and high dissolved salts will be most corrosive. For water, it's a matter of mineral content. The more the minerals, the less the resistivity, the more the corrosivity Corrosion and Cathodic Protection

218. 218 Galvanic Protection ( Sacrifical Anode): A more active metal than steel can act as Sacrifical Anode. But the execution is a bit tricky.The Galvanic Series indicate that Mg, Zn, and Al are more active than steel. So, a number of anodes are electrically connected to the steel structure to be protected to provide the needed current. The amount of output current needed is increased by increasing the number of anodes. Anodes are packaged in porous bags prefilled with backfill materials such as Clay to: - ensure absorption of moisture from soil, and reduce anode resistance of anode/electrolyte. - distribute the anodic reaction all over the anode. - Increase the life of the anode Corrosion and Cathodic Protection

219. 219 Impressed Current Cathodic Protection (ICCP) method: An external power source is used to supply needed current. This way, we're not obliged to use anodes with certain characteristics that fall at a certain position on the Electrochemical series. In this method, a Transformer is needed to convert HV AC voltage to a reduced DC voltage. Then a Rectifier is used to convert the reduced DC voltage into pulsating DC. A Junction Box is then used as a distributor to distribute current to anode ground bed. Corrosion and Cathodic Protection

220. 220 ICCP is preferably used when high current is required or the electrolyte's resistivity is high. As it provides better protection, ICCP is used on Piplelines , Tanks, and well-casing Corrosion and Cathodic Protection

221. Chemicals and additives 221 Chemicals and additives

222. 222 Corrosion inhibitor is injected in export pipelines and storage tanks. Exported oil can be highly corrosive, leading to corrosion of the inside of the pipeline or tank. The corrosion inhibitor protects by forming a thin film on metal surfaces. Emulsion Breakers: (De- mulsifier ) Production of Oil usually involves the co-production of large quantities of water.Natural surfactants present in the oil or water, other chemicals such as corrosion inhibitors combined with the shearing effect from turbulent flow and pumps may create emulsions. De- mulsifiers are used to resolve water-in-oil emulsions. Paraffin Control Agents and Pour Point Depressants: Crude oils may contain varying degrees of long chain paraffin or waxes that tend to form deposits if the oil is subjected to changes in temperature, pressure or other conditions. Dispersants/detergents are used to remove deposits already formed and inhibitors to interfere with wax crystal growth and formation. Chemicals and additives

223. 223 Drag reducers improve the flow in pipelines. Fluid near the pipe tries to stay stationary while fluid in the center region of the pipe is moving quickly. This large difference in fluid causes turbulent bursts to occur in the buffer region. Turbulent bursts propagate and form turbulent eddies, which cause drag. Drag-reducing polymers are long-chain, ultra-high molecular weight polymers from 1 to 10 million u), with higher molecular weight polymers giving better drag reduction performance. With only parts-per-million levels in the pipeline fluid, drag-reducing polymers suppress the formation of turbulent bursts in the buffer region. The net result of using a drag-reducing polymer in turbulent flow is a decrease in the frictional pressure drop in the pipeline by as much as 70%. This can be used to lower pressure or improve throughput. Chemicals and additives

224. Pipelines operations 224 Pipelines operations

225. 225 Pipelines can measure anywhere from 6 to 48 inches (15-120 cm) in diameter. In order to ensure their efficient and safe operation, operators routinely inspect their pipelines for corrosion and defects. This is done with sophisticated pieces of equipment known as “pigs.” Pigs are intelligent robotic devices that are propelled down pipelines to evaluate the interior of the pipe. Pigs can test pipe thickness, roundness, check for signs of corrosion, detect minute leaks, and any other defect along the interior of the pipeline that may either restrict the flow of gas, or pose a potential safety risk for the operation of the pipeline. Sending a pig down a pipeline is fittingly known as “pigging.” The export facility must contain equipment to safely insert and retrieve pigs from the pipeline as well as depressurization, referred to as pig launchers and pig receivers. Loading on tankers involves loading systems, ranging from tanker jetties to sophisticated single-point mooring and loading systems that allow the tanker to dock and load the product, even in bad weather. Pipelines operations

226. 226 Pipeline operations Safe and economic operation of a pipeline system requires that various routine activities be performed on a regular basis. Certain special operations or tests are performed to monitor the integrity of the pipeline system and to properly maintain it. This chapter will provide a brief description of these operations. Pipelines operations

227. 227 Pipeline commissioning Commissioning a pipeline begins when the pipeline is connected to the upstream facility source and the downstream delivery point, after completing the hydrostatic pressure testing and all required pre-commissioning has been completed. Commissioning refers to the initial “start-up” period, when the pipeline system is tested and put into operation. During this period, performance of the entire system is checked, against specified operating conditions, per pipeline specifications and design. Depending on the product to be transported, the following parameters are monitored during the commissioning period to ensure that no hydrate formation or corrosion will take place in the future: Liquid pipelines Operating pressure, flow rate, temperature, and moisture content Product contaminants, sediments, or deposits The presence of corrosive components Corrosion rate Effectiveness of corrosion control system General condition of the pipeline system Pipelines operations

228. 228 Routine operations Specific routine and special operations are essential in order to maintain an efficient, reliable, and economic pipeline operation. These operations may be caused by the following special pipeline conditions: Hydrate formation Formation of inorganic deposits Formation of waxy deposits Corrosivity of the transported fluid Transported product contamination Pipelines operations

229. 229 Pipeline cleaning The buildup of potentially corrosive products or other deposits, for example, wax, gradually increases the internal roughness of the pipeline and reduces the pipeline internal diameter that, in turn, increases pressure losses and reduces flow rate. This, in turn, requires increased horsepower to move the fluids that increases the OPEX. Routine pipeline cleaning is of vital importance in maintaining the pipeline in optimum condition. Routine pipeline cleaning will prevent loss of efficiency, reduce the risk of corrosion, ensure effectiveness of inspection tool survey, facilitate effective corrosion inhibition. Pipelines operations

230. 230 Brush and scraper pigs. Pipelines operations

231. 231 A pig launcher is a system used to send a PIG through a pipeline. PIGs are devices that are inserted into pipelines and used to clean, inspect, or maintain the pipeline as they pass through it. Pipelines operations

232. 232 A pig receiver is a device to receive a pipeline pig out of the pipeline without interrupting the flow. Pipelines operations

233. 233 PIGs are devices that are inserted into pipelines and used to clean, inspect, or maintain the pipeline as they pass through it. Pipelines operations

234. 234 Corrosion inhibition: Inhibition of pipelines is performed to control internal corrosion. Special corrosion inhibitor chemicals are either injected continuously and mixed into the transported fluid or transported as a batch or slug. When continuous injection is carried out, the upstream and downstream inhibitor concentrations are monitored to ensure that the inhibitor is steadily received at the end of the pipeline and thus applied throughout the pipeline. When applied as a batch or slug, the inhibitor is mixed with a carrier and sent down the pipeline between two spheres or cupped pigs. The objective is to apply a coating to the internal surface of the pipe, forming a protective layer. Selection of an appropriate inhibitor depends upon the type of the transport fluid (gas, liquid, and two-phase) and its operating pressure and temperature. Normally, it is determined after testing. Figure 14.2 illustrates an inhibitor injection system. Pipelines operations

235. 235 Liquid removal: It is not uncommon for liquid to settle out in low spots along a pipeline flowing natural gas or two-phase flow. The liquid drops out when the gas velocity is insufficient for entrainment or during an intermittent fluid-phase pattern. Liquid may also drop out when the pressure-temperature-related solubility of the transported fluid changes as the pressure or temperature condition changes in the pipeline. The fluids that settle out may upset flow conditions, cause hydrate formation, and be corrosive. Removal of such fluids is essential for the proper operation and long-term protection of the pipe- line. Periodic pigging is the normal procedure for liquid removal. Pipelines operations

236. 236 Pipeline integrity assessment: Pipelines are considered the safest means of transporting hydrocarbon; some failures do occur that result in spillage, loss of revenue, and possible impact on health, safety, and environment. Continuity of operation is an essential requirement for successful operation of a pipeline. Hence, the pipeline integrity program is a very important part of pipeline operations. An integrity program is required to identify potential pipeline failures that may result in leaks and spillage. Several activities are required to continuously assess the integrity of a pipeline and to monitor its condition. They include the following: Pipeline inspection Pipeline corrosion monitoring Pipeline pigging Pipeline leak detection Pipelines operations

237. 237 Pipeline inspection: For onshore pipelines, surveillance through visual inspection is undertaken by flying, driving, and walking along the right-of-way. The purpose of this periodic inspection is to obtain early detection of events that might cause pipeline failure or create hazardous conditions. Aerial surveillance, by low-flying planes or helicopters, is the most commonly used visual method. During the surveillance, the inspectors watch for any development or changes on or adjacent to the right-of-way. These include civil construction near or on the pipeline, soil erosion, stream, bed changes, and growth of brush and trees along the right-of-way. One of the primary responsibilities of the surveillance is to look for leaks by observing the discoloration of vegetation and then reporting their location. When the pipeline is located in densely populated areas or where weather prevents air surveillance or where low flying is not permitted, pipeline walkers inspect the right-of-way at ground level. Inspection of offshore pipelines is conducted by diver intervention at selected spots or by using remote-operated vehicles (ROVs) as shown in Figure. Pipelines operations

238. 238 Pipelines operations

239. 239 Pipeline corrosion monitoring: Corrosion of steel in process piping and pipelines is very common. When buried, as shown in Figure 14.4, steel invariably will suffer external corrosion degradation unless adequately protected. Figure 14.5 illustrates how a corrosion cell is formed, when a pipeline is buried, and how corrosion takes place. Pipelines are usually coated to protect the external surfaces of the steel pipeline against corrosion. Unfortunately, no coating system is, however, perfect. It must be supplemented by a cathodic protection system. For further discussion on pipeline corrosion, material selection, coating selection, and corrosion prevention. Pipelines operations

240. 240 Pipeline pigging: Pipeline pigs and pipeline pigging are discussed extensively in Chapter 13. Using the correct type of pig and establishing the proper pigging program maintain the integrity and optimize the efficiency of the pipeline while safeguarding both the environment and company assets. Pipeline pigs are used extensively in gas, liquid, and two-phase pipeline operations for a variety of purposes. A pig is a mechanical device, which is forced through the pipeline by the pressure of the flowing fluid. It moves through the pipeline with the fluid. The pig normally consists of a cylindrical or spherical body,usually made of steel with rubber or plastic cups, attached on either end of the pig seal against the inner wall of the pipe. Pipeline operations are conducted to: Pipelines operations

241. 241 remove wax and paraffin from the inner wall of the pipeline to improve flow efficiency; reduce liquid that has accumulated at low spots in two-phase flow; control liquid placement ensuring full water column during hydrostatic testing and during the dewatering after the text; separate products and reduce mixing between different types of products transported in the pipeline; facilitate batching of corrosion inhibitors, biocides, and chemical film lining; inspect pipeline for dents, buckles, leaks, or corrosion using gauging, caliper , or intelligent pigs. Pipelines operations

242. 242 Pigs are categorized as either utility pigs or intelligent pigs. Utility pigs have very few moving parts and they are primary used for cleaning and sealing (product separation). Figure shows the different types (forms) of utility pigs that include Pipelines operations

243. 243 Pipeline leak detection: Leak detection is often required under pipeline safety codes to: assure safety in operations, protect the environment, avoid the loss of transported product, minimize third party damage, minimize loss or damage to the pipeline users. Pipelines operations

244. 244 Traditionally, leak detection has been performed by visual inspection of the pipeline. This was done either by traversing the pipeline route on the ground or by surveying the route with low-flying light aircraft. While aerial inspections are still conducted, instrumentation and monitoring equipment are also used for rapid and precise location of leaks and potential leaks. These methods rely on monitoring and analysis or pipeline flow and pressure changes or pressure transients using simulated computer software. Pipelines operations

245. 245