SPOM.S1.0223.01 Oil & Gas Production Operations Module PDF

ADNOC Classification: Internal THE CONTENTS OF THIS DOCUMENT ARE [PROPRIETARY AND CONFIDENTIAL] [Process Operations Specialization] [SPOM.S1.0223.01] [Oil & Gas Production Operations] VERSION: 0.1 DOCUMENT OWNER: [Academic Services] ADNOC Classificat...

ADNOC Classification: Internal THE CONTENTS OF THIS DOCUMENT ARE [PROPRIETARY AND CONFIDENTIAL] [Process Operations Specialization] [SPOM.S1.0223.01] [Oil & Gas Production Operations] VERSION: 0.1 DOCUMENT OWNER: [Academic Services] ADNOC Classification: Internal TABLE OF CONTENTS 1. INTRODUCTION TO CRUDE OIL CHEMISTRY AND PROPERTIES............................................ 5 1.1 Crude oil History 5 1.2 Crude oil chemistry 6 1.3 Main crude oil properties 8 2. OIL AND GAS PRODUCTION FACILITIES................................................................................... 10 2.1 Offshore Production Facilities 10 2.2 Onshore Production Facilities 12 2.3 Sections of Main Processing Facility 13 3. CRUDE OIL DEHYDRATION, DESALTING, & STABLIZATION................................................... 21 3.1 Crude Oil After Three-Phase Separation 21 3.2 Heating wet crude oil 22 3.3 Desalting Train 23 3.4 Chemical Injection 24 3.5 Wash-water System 25 3.6 Storage Tanks 29 3.7 Crude oil stabilization 30 4. NATURAL GAS SWEETENING PROCESS................................................................................... 31 4.1 Importance of natural gas sweetening 31 4.2 Description of Natural Gas Sweetening Process 31 5. NATURAL GAS DEHYDRATION PROCESS................................................................................ 38 5.1 Introduction 38 5.2 Importance of natural gas dehydration 38 5.3 Gas Hydrates Formation 39 5.4 Technologies used for dehydration 40 ADNOC Classification: Internal MODULES IN THIS COURSE 1 Introduction to Crude Oil Chemistry and Properties 2 Oil and Gas Production Facilities 3 Crude oil dehydration, desalting, and stabilization 4 Natural Gas Sweetening processes 5 Natural Gas Dehydration Processes [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 3 ADNOC Classification: Internal OUTCOME 1 Describe the basic chemistry and properties of crude oil. Performance Criteria a. Describe the main classes of hydrocarbons found in crude oil. b. Describe the main crude oil properties OUTCOME 2 Describe the main Oil and Gas production facilities Performance Criteria a. Describe the Offshore production facilities b. Describe the Onshore production facilities c. Describe the sections of main processing facility. OUTCOME 3 Describe the processes of crude oil dehydration, desalting, and stabilization. Performance Criteria a. Describe the purpose and operation of crude oil dehydration and desalting process. b. Describe the purpose and operation of crude oil stabilization process. OUTCOME 4 Explain the purpose and operation of natural gas sweetening process. Performance Criteria a. Explain the purpose of natural gas sweetening. b. Describe the process of natural gas sweetening. OUTCOME 5 Explain the purpose and operation of natural gas dehydration process. Performance Criteria a. Explain the purpose of natural gas dehydration. b. Describe the two main processes of natural gas dehydration. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 4 ADNOC Classification: Internal 1. INTRODUCTION TO CRUDE OIL CHEMISTRY AND PROPERTIES 1.1 Crude oil History Oil has been used for lighting purposes for many thousands of years. In areas where oil is found in shallow reservoirs, seeps of crude oil or gas may naturally develop, and some oil could simply be collected from seepage or tar ponds. It was not until 1859 that "Colonel" Edwin Drake drilled the first successful oil well, with the sole purpose of finding oil. The Drake Well was located in the middle of quiet farm country in north western Pennsylvania and sparked the international search for an industrial use for petroleum (Figure1). Figure1.1 Drake Well, Titusville, PA These wells were shallow by modern standards, often less than 50 meters deep, but they produced large quantities of oil. In this picture of the Tarr Farm, Oil Creek Valley, the Phillips well on the right initially produced 4,000 barrels per day in October 1861, and the Woodford well on the left came in at 1,500 barrels per day in July 1862. The oil was collected in the wooden tank pictured in the foreground. As you will no doubt notice, there are many different-sized barrels in the background. At this time, barrel size had not been standardized. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 5 ADNOC Classification: Internal 1.2 Crude oil chemistry Crude oil is a mixture of hydrocarbon molecules, which are organic compounds containing carbon and hydrogen atoms that may include from one to more than sixty carbon atoms. Crude oil contains mainly three classes of hydrocarbons: paraffins, Naphthenes and aromatics. Paraffins: The paraffinic series of hydrocarbon compounds found in crude oil have the general formula CnH2n+2 and can be either straight chains (normal) or branched chains (isomers) of carbon atoms. Here are some examples of straight chain paraffin molecule. Figure 2 Some examples of paraffins [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 6 ADNOC Classification: Internal Naphthenes Naphthenes are saturated hydrocarbon compounds with the general formula CnH2n, arranged in the form of closed rings (cyclic) and found in all fractions of crude oil except the very lightest. Single-ring Naphthenes with five and six carbon atoms predominate. Figure1. 3 Naphthenes Examples Aromatics Aromatics are unsaturated ring-type (cyclic) compounds which react readily because they have carbon atoms that are deficient in hydrogen. All aromatics have at least one benzene ring (a single-ring compound characterized by three double bonds alternating with three single bonds between six carbon atoms) as part of their molecular structure. Figure 1.4 Aromatics Examples [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 7 ADNOC Classification: Internal 1.3 Main crude oil properties API Gravity Specific gravity is a measure of how heavy or how light petroleum liquid is compared to water. API gravity as a function of specific gravity is defined by the following formula: Figure 1.5 Crude oil samples with different API6 gravities Cloud Point Cloud point is the temperature at which dissolved solids are no longer completely soluble, precipitating as a second phase giving the fluid a cloudy appearance. In the petroleum industry, cloud point refers to the temperature below which wax in crude oil form a cloudy appearance. Pour Point Pour point is the temperature at which the crude oil becomes semi solid and ceases to flow. Pour points depressants are chemicals used to decrease the pour point of crude oil and other heavy products. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 8 ADNOC Classification: Internal Reid Vapour Pressure Reid Vapour Pressure (RVP) is measured is a very important property of crude oil and oil products. To measure RVP, a sample is placed in a chamber at a constant temperature of 100 °F. RVP is therefore the vapour pressure at the given temperature of 100 °F. Crude stabilization is a process of removing volatile components from crude oil to reduce its vapour pressure so as to avoid vaporization in storage tanks and pipeline transmission. Figure 1.6 ASTM D323 Reid Vapor Pressure Apparatus for Crude Oil Asphaltenes content Asphaltenes are molecular substances in crude oil that are insoluble in low boiling hydrocarbon liquids such as heptane and are also non-distillable. These molecules are made up of aromatic clusters containing a polar heteroatom group. In large molecules the aromatic rings are interconnected by paraffinic groups and by sulphur as shown below. Figure 1.7 Example of Asphaltene chemical structure [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 9 ADNOC Classification: Internal 2. OIL AND GAS PRODUCTION FACILITIES. The oil and gas production industry consists mainly of onshore and offshore production facilities. 2.1 Offshore Production Facilities The oil and gas produced from the reservoir under the bed of sea (off of the shore) is called offshore. The offshore production facilities deliver well fluids containing oil and gas by pipelines to the onshore processing facility. Alternatively, oil may be delivered by ocean-going tanker to the onshore terminal. A wide range of different structures is used in constructing offshore facilities depending on size and water depth. 2.1.1 Bottom Supported and Vertically Moored Structures Figure 2.1 Bottom supported and vertically moored structures Fixed Platform (FP) FP Consists of a jacket (a tall vertical section made of tubular steel) with a deck placed on top, providing space for crew quarters, a drilling rig, and production facilities. The fixed platform is economically feasible for installation in water depths up to 500 meters. Compliant Tower (CT) Consists of a narrow, flexible tower and a piled foundation that can support a conventional deck for drilling and production operations Unlike the fixed platform, the compliant tower withstands large lateral forces by sustaining significant lateral deflections and is usually used in water depths between 300 to 600 meters. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 10 ADNOC Classification: Internal Tension Leg Platform (TLP) Consists of a floating structure held in place by vertical, tensioned tendons connected to the sea floor by pile-secured templates. Tensioned tendons provided for to limit vertical motion. It is used for water depths up to 1200 meter. Mini-Tension Leg Platform (Mini-TLP) By its name it’s a floating mini-tension leg platform of relatively low cost and used for smaller deep-water reserves. It is used as additional platform for a large platform facility. 2.1.2 Floating Production and Subsea Systems Figure 2.2 Floating production and subsea system SPAR Platform (SPAR) Consists of a large diameter single vertical cylinder supporting a deck. It has a typical fixed platform topside (surface deck with drilling and production equipment), three types of risers (production, drilling, and export), and a hull which is moored using a stretched six to twenty lines anchored into the seafloor. SPAR platforms are used in water depths 900 -2000 meters. Floating Production System (FPS) Consists of a semi-submersible unit which is equipped with drilling and production equipment. It is anchored in place with wire rope and chain or can be dynamically positioned using rotating thrusters. Production from subsea wells is transported to the surface deck through production risers designed to accommodate platform motion. FPS is used in water depths 200 to 2000 meters [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 11 ADNOC Classification: Internal Subsea System (SS) Subsea System (SS) ranges from single subsea wells producing to a nearby larger platform. These systems are presently used in water depths greater than 2000 meters. Floating Production, Storage & Offloading System (FPSO) FPSO consists of a large tanker type vessel moored to the seafloor. They designed to slow production from nearby subsea wells and to periodically offload the stored oil to a smaller shuttle tanker. The shuttle tanker then transports the oil to an onshore facility for further processing. An FPSO may be suited for marginally economic fields located in remote deep-water areas where a pipeline infrastructure does not exist. 2.2 Onshore Production Facilities The oil and gas produced and processed in main land are called onshore production facilities. ADNOC Onshore fleet consists of 73 land rigs of varying specifications, including several high- capacity workover rigs, empowering the company to drill a wide range of oil and gas wells and handle the most challenging drilling programs effectively and efficiently. Figure 2.3 One example of ADNOC Onshore drilling Rig.. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 12 ADNOC Classification: Internal 2.3 Sections of Main Processing Facility The main objective of a production facility is to process the well fluids into clean, marketable products. A typical oil, natural gas production facility consists of the following systems Well head Manifolds Production and Test separators Gas compression Storage Tanks Shipping pumps Water treatment plant Figure 2.4 A typical main processing facility [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 13 ADNOC Classification: Internal 2.3.1 Well head It is a structure that is installed at the top of a natural oil or gas well. Its main function is to ensure a safe operation and manage the flow of oil or gas from the well into the gathering-system. Well head provides the Control mechanism between down-hole and surface equipment. It forms a seal to prevent well fluids from blowing or leaking at the surface. It should withstand wide range of temperature, pressure, and corrosive agents. Wellhead equipment generally consists of the following components: Casing head and hangers, Tubing heads and hangers, Tubing head adapters and Christmas tree. Figure 2.4 Typical wellhead and Christmas tree assembly [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 14 ADNOC Classification: Internal 2.3.2 Production and Test Manifolds Oil & gas from fluids from different wells of the reservoir are collected into one large pipe called a “Production Manifold”.The production manifold sends the collected oil & gas streams to to the G.O.S.P’s (Gas Oil Separation Plants) via one pipeline. The Test Manifold is used to measure the output of oil, gas, and Water from a single well by routing it into a “Test Separator”. After certain production time, the output of each well will fall and the data from the test separator will determine if the well needs to be stimulated or even re-drilled. Figure 2.5 Production and Test Manifolds 2.3.3 Separation process of well effluent constituents Production separators The production separators are very important equipment where the well fluid stream is generally separated by gravity into three phases (oil, gas and water). The commonly used type of separator is the horizontal one. Test separator Test separator is a two or three phase separator used to test the performance of individual wells. It measures the net oil, water and gas produced. In modern facilities, Multi-Phase Flow Meter (MPFM) are used instead of test separator. Multiphase flow meters are devices used to measure the individual oil, water, and gas flow rates without separation. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 15 ADNOC Classification: Internal 2.3.4 Gas Compression. The process of increasing the pressure of natural gases separated from the production separators is called gas compression. The gas leaving the upper section of the separators consists of mixture C1, C2, C3, C4+ gases is sent to Gas compressor. The Gas compressor is a two-stage compressor which increases the pressure of the gas for transporting it to various locations through gas transmission pipelines. A scrubber is installed in the section of each stage to remove any liquid carryover in the gas by gravity separation. Gas from production separators has generally lost so much pressure that it must be recompressed to be transported. The quantity and quality of the oil and gas transferred to the end user are measured in a meter station consisting of oil and gas mass flow meter (MFM) and Volumetric flow meter. The volume of Natural gas export/ transferred is expressed in Standard Cubic Foot (SCF). The standard volume unit for crude oil measurement is the barrel (bbl.). Figure 2.6 standard unit for oil measurement [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 16 ADNOC Classification: Internal 2.3.5 Water treatment plant The water separated from the well fluid in the production separators is called produced water. The produced water contains traces of oil, gases, and organic impurities hence it is treated further to remove the impurities in a water treatment plant that meets the specification environmental regulation. The water treatment plant removes the impurities present in produced water, finally the treated water is sent for disposal by using a water injection system consists of injection wells. The treated water is injection back to the reservoir to replace produced fluids and thus maintain or increase the reservoir pressure, there by stimulate production. A typical water injection system is shown below. Figure 2.7 A typical water injection system. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 17 ADNOC Classification: Internal 2.3.6 Pigging Pipe inspection gauge (PIG) is tool used for pipeline cleaning and inspection purpose. The pig is first placed in the pig launcher, then launched into the pipeline. The pig is pushed through the pipeline by a driving fluid. The pipeline is cleaned along the way by the brushing action from the pig. On the other end, the pig tool is received by a pig receiver. Pig launcher can be of a horizontal, vertical or inclined type. Horizontal pig traps are selected for easy operation. When space constraints become critical, vertical, or inclined pig traps are installed instead of horizontal. The schematic shown below is for a horizontal pig launcher. Figure 2.7 basic components of a pig launcher. The main parts of a pig launcher are as follows: Major barrel & minor barrel Quick opening door Main line Bypass line Kicker line Vent and drain valve [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 18 ADNOC Classification: Internal Figure 2.8 Typical pig launcher main parts 2.3.7 Artificial lift Based on the nature of their fluids flow, wells are classified into Natural and Artificial flow wells. Natural flow wells: This type of well uses the natural pressure from the formation to force the oil or gas from the reservoir to the surface without requiring a pump. Most reservoirs are initially at pressures high enough to allow a well to flow naturally. Pwf = Bottom hole flowing pressure, psi PR= Reservoir pressure, psi PSEP= Separator pressure, psi PTH= Tubing head / Well head pressure, psi Figure 2.9 typical Natural flow well [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 19 ADNOC Classification: Internal Artificial flow wells. The flow of well fluids from the formation to the surface depends mainly depends on reservoir pressure and vertical height of the tubing reaching the formation. When reservoir pressure declines due to draw of oil and gases, or water fraction increases, the well’s natural flow rate may be inadequate and artificial lift processes are implemented to increase or maintain rate. Although there are several methods to achieve artificial lift, the two main categories of artificial lift include pumping systems and gas lifts. The artificial lifts are used on oil wells to reduces the bottom hole flow pressure and enhance oil flow to the surface Figure 2.10 types of artificial lift systems [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 20 ADNOC Classification: Internal 3. CRUDE OIL DEHYDRATION, DESALTING, & STABLIZATION 3.1 Crude Oil After Three-Phase Separation After separation, the crude oil may contain very small drops (droplets) of salt water. Many droplets are surrounded by and held in suspension by a thin film of oil. These droplets are tightly bound. The oil may contain other droplets that are not surrounded by a film of oil but are freely suspended. Figure 3.1 shows water droplets suspended in oil. The droplets are too small and too light to break through the film of oil or to fall out of suspension without processing. To separate the salt water droplets, four different treatments are used. These are: 1- Heat 2- Chemical Injection 3- Wash water Injection 4- Electrostatic Coalescence These treatments are performed by a wet crude handling plant or by the desalting system in a Gas oil separation plant (GOSP). Figure 3.1 Water Droplets Suspended in Oil [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 21 ADNOC Classification: Internal 3.2 Heating wet crude oil Wet crude oil from the Gas Oil Separation Plant (GOSP) must be heated before water andsalt can be separated. A heater is a shell and tube heat exchanger that is used to increase the temperature of the wet crude oil. Hot fluid (product) from a process flows through the tubes of the exchanger which warms the cooler crude oil flowing through the shell side. Figure 3.2 Shell & Tube Heat Exchanger Heat is provided by the warm crude oil output from the desalter and hot diesel oil from another process. Heating the crude oil lowers its viscosity, makes it thinner. Thin crude oil cannot hold water droplets in suspension. Figure 3.2 Wet Crude Oil Heating System [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 22 ADNOC Classification: Internal Scale Inhibitor Salt water tends to form hard scale deposits when it is heated. The scale inhibitor is a chemical treatment used to control or prevent scale deposits in heat exchangers. The chemical inhibitor is injected into the wet crude before it enters the second heat exchanger. The inhibitor prevents the formation of scale in the exchangers as the wet crude is heated. 3.3 Desalting Train Wet crude oil flows through three main vessels of the desalting train. These are the dehydrator and two desalters.( figure 3.3). The purpose of the dehydrator and desalters is to remove saltwater droplets from the wet crude oil. The dehydrator and desalters are similar in construction and operation. Figure 3.4 shows a diagram of a dehydrator. The dehydrator receives hot wet crude from the heat exchanger. The crude is input through the distributor and spreads across a tray under an electrical grid. The electrical grid is called the electrostatic coalescer. When leaving second stage desalter, crude oil is called dry crude and is normally free from salt water. Continuous monitoring of water and salt contents in dry crude is ensured before sending it to storage tanks. If dry crude is off specifications, it is recycled back to the feed and mixed with wet crude oil. Figure 3.3 Crude oil Desalting Train [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 23 ADNOC Classification: Internal Figure 3.4 Typical Dehydrator A high voltage is applied to the electrical grid (coalescer) to create a strong electrostatic charge. The electrostatic charge attracts the saltwater droplets in the crude, causing them to rise and join together (coalesce). As the droplets join, larger drops are formed. When the drops get large enough, they fall out of suspension and settle at the bottom of the vessel. The water is then removed from the vessel and sent to a storage tank for disposal. 3.4 Chemical Injection Each desalter like the dehydrator uses an electrostatic coalescer. However, electrostatic treatment alone will not remove enough salt to meet dry crude specifications. Chemicals and wash water must be added to remove more of the saltwater droplets. There are two demulsifier injection systems in the desalting train. The slugging demulsifier system located before the dehydrator is normally shut down and isolated. It is used only when the incoming wet crude has an extremely high salt content. The interstage system constantly injects demulsifier into the crude before the first and second-stage desalters. A demulsifier dissolves the oil film around tightly bound water droplets in the crude which makes it easier to separate the salt water by electrostatic coalescence. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 24 ADNOC Classification: Internal 3.5 Wash-water System Washwater is added to the crude before each desalter. The purpose of the washwater is to dilute the salt concentration in the crude. The resulting salty water is then separated from the crude oil and removed from the desalters. This carries the excess salt away from the crude stream. The washwater is recycled between the desalting vessels. Fresh washwater is used for second-stage desalting. Salty water from the bottom of the second-stage desalter is then recycled to the first-stage. The recycled water is used in the first-stage desalter. Water from the bottom of the first-stage desalter has a higher concentration of salt. Some of this salty water is added to the recycle water, to pass through the first-stage desalter again. Most of the water, however, is sent to a disposal tank. Mixing Valves Differential pressure control valves are located before the dehydrator and desalters. These valves are used to mix the demulsifier and washwater with the wet crude oil. The purpose of this process is to: Set the water droplets in motion Disperse the demulsifier throughout the crude. Distribute the washwater to rinse the salt out of the crude. The mixing valve for the dehydrator is normally bypassed. The mixed crude, demulsifier, and rinse water is input to the desalters. The purpose of the desalters is to remove the tightly bound water droplets from the wet crude to reduce its salt water content. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 25 ADNOC Classification: Internal First Stage Desalter The first-stage desalter receives crude oil from the dehydrator. Demulsifier and recycled washwater from the secondstage desalter flow through a mixing valve before it enters the desalter (figure 3.5). Figure 3.5 First Stage Desalter Salty water separates from the oil and falls to the bottom of the vessel. The salty water leaves the first-stage desalter and mixes with washwater from the second-stage desalter.Part of this mixed salty water is recycled to the input of the first-stage desalter. The rest of the water goes to the storage tank for disposal. The crude oil from the first-stage desalter flows to the second-stage desalter. Demulsifier and fresh washwater are added to the crude and flows through a mixing valve before it reaches the secondstage desalter. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 26 ADNOC Classification: Internal Second Stage Desalter Crude oil from the first-stage desalter and fresh water is input through the mixing valve. This is shown in figure 3.6. The desalter removes enough of the remaining salty water to meet dry crude specifications. Figure 3.6 Second-stage Desalter It operates on the same principle as the dehydrator and first-stage desalter: The demulsifier breaks down the oil film around the remaining water droplets. Fresh water mixes with the incoming wet crude to dilute the salty water. The electrostatic grid causes the water droplets to coalesce and sink to the bottom of the vessel. Part of the salty water is recycled from the bottom of the vessel back to the second-stage desalter input. Most of the recycle water is used as washwater for the first-stage. Clean washwater flows opposite to the direction of the crude oil. It starts at the second-stage desalter and recycles to the first-stage desalter. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 27 ADNOC Classification: Internal Dry Crude Coolers The dry hot crude from the desalting train passes through the shell side of the pre-heater in the wet cold crude/dry hot crude heat exchangers as shown in figure 3.7. From these heat exchangers, the dry crude oil flows through a set of dry crude coolers. These coolers use seawater to reduce the temperature of the dry crude ( figure 3.8). Figure 3.7 wet cold crude/dry hot crude heat exchanger Figure 3.8 Dry Crude Cooler (using sea water) [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 28 ADNOC Classification: Internal 3.6 Storage Tanks The dry crude from the second-stage desalter is constantly monitored for total salt and water content. The dry crude must contain: Less than 0.3% water content. Less than 10 pounds of salt per thousand barrels of oil. If the dry crude meets specifications, it is sent to a storage tank. A typical storage tank is shown in figure 3.9. From the storage tank, the dry crude is sent to a stabilizing plant to remove any remaining H2S and CO2. If the dry crude does not meet specifications, it is recycled to the wet crude storage tank so that it can return through the wet crude handling process. Figure 3.9 Dry Crude Storage Tank [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 29 ADNOC Classification: Internal 3.7 Crude oil stabilization Crude oil stabilization is the removal of light components from a hydrocarbon liquid to lower its vapor pressure to a desired level. Stabilization may be used to meet a required pipeline sales contract specification or to minimize the vaporization of the liquid hydrocarbons stored in an atmospheric storage tank. The process of crude stabilization and sweetening aims: To separate light hydrocarbon gases (C1 to C4) that are dissolved in the crude oil. The separated gases are compressed and sent for further treatment and processing. To remove acid gas (H2S) from the crude oil. When H2S has been removed, the crude oil is referred to as sweet crude. This process is called crude oil sweetening. After stabilization, sweet crude oil can be refined more easily. Sour crude from the GOSP is routed to the stabilization plant. The plant consists of a spheroid, stabilization column, two reboilers, and a fin-fan cooler. A typical stabilization plant is shown in figure 3.10. The outputs from the stabilization column are routed as follows: From the top of the column, the light gases are compressed and sent to further treatment sections. From the bottom of the column sweet crude oil is sent to storage. Figure 3.10 Crude Oil Stabalization Plant [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 30 ADNOC Classification: Internal 4. NATURAL GAS SWEETENING PROCESS Most natural gas from a gas oil separation plant (GOSP ) contains hydrogen sulfide (H2S) and carbon dioxide (CO2) and is called sour gas. The process used to remove H2S and CO2 from sour natural gas is called gas sweetening. The obtained purified gas is called sweet gas. If not removed, acid gases (CO2 & H2S) can cause serious problems in gas processing facilities. 4.1 Importance of natural gas sweetening There are many reasons behind removing acidic gases (H2S and CO2) from natural gas: H2S gas has to be removed from natural gas because: It is a toxic gas and flammable It forms acids (H2SO4) when reacting with water which cause severe corrosion problems. During the combustion, burning hydrogen sulphide (H2S) in fired heaters may produce sulphur dioxide (SO2), a toxic and highly flammable gas. CO2 gas has to be removed because: CO2 reacts with moisture to form carbonic acid (H2CO3) which is highly corrosive. CO2 presence in natural gas lowers its heating value (calorific value). 4.2 Natural Gas Sweetening Process Description Diffent types of aqueous amine solutions can be used to sweeten sour natural gas. The gas sweetening process is based on the two following principles: At low temperature and high pressure, amine solution (lean amine) absorbs H2S and CO2 but will not react with light hydrocarbon gases. At a high temperature and low pressure, H2S and CO2 separate from amine solution (rich amine), as shown in Figure 4.1. Rich amine is regenrated, filtered, cooled down, and finaly recycled back into amine contactor. Figure 4.1 Gas Sweetening Process [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 31 ADNOC Classification: Internal 5.2.1 Major components and their functions The major components of gas sweetening process are the contactor, flash drum, regeneration system, filtering, and reclaiming. Amine contactor The purpose of the contactor is to provide direct contact between sour gas and lean amine which results in the sweetening of sour gas. Figure 4.2 shows an amine contactor column. Lean amine is fed to the top part of the contactor, and flows downward to the bottom. Sour gas near ambient temperature is fed from the bottom part of the column just below the first tray. Amine solution flowing down the column absorbs the H2S and CO2 as the sour gas flows up the column. Both streams experience counter contact inside the column. The temperature at the bottom of the contactor is higher than the temperature at the top. This is because when amine bonds with H2S and CO2, heat is produced due to the exothermic nature of this chemical reaction. Figure 4.2 Amine Contactor Column [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 32 ADNOC Classification: Internal Inside the contactor column, amine flows downward filling and overflowing each tray. Sour gas flows up the column, through the holes in each tray. At each tray, the rising sour gas flows through the falling amine. This is shown in figure 4.3. As the amine contacts the sour gas, it absorbs the acidic gases, i.e., H2S and CO2. At low temperature and high pressure, H2S and CO2 are easily removed by amine solution. More and more H2S and CO2 are absorbed as amine flows down through each tray. By the time amine reaches the bottom of the column, it is almost saturated with H2S and CO2. Amine saturated with CO2 and H2S is called rich amine. When the gas reaches the top of the column, it contains little or no H2S and CO2 is called sweet gas. Figure 4.3 Flow patterns inside the Amine Contactor [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 33 ADNOC Classification: Internal Flash Drum The purpose of the flash drum is to separate the dissolved hydrocarbons (and some acidic gases) from rich amine. Figure 4.4 shows a flash drum. As rich amine flows into the flash drum, its pressure drops to about 400 KPa. This pressure drop causes dissolved hydrocarbons (and some acidic gases) to flash off from rich amine. The gases leave the drum as overhead product, and flared later. Rich amine flows from the bottom of the drum and routed to the regenerator, where H2S and CO2 are removed. Figure 4.4 Flash Drum Regeneration Section The function of the regeneration section is to separate H2S and CO2 from rich amine and return back lean amine to the contactor. Figure 4.5 shows the regeneration system which consists of a regenerator, reboiler, overhead condenser, and reflux drum.. Figure 4.5 Regeneration System [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 34 ADNOC Classification: Internal Regenerator Inside the regenerator, pressures are lower and temperature is higher than in the contactor. This low-pressure, high-temperature environment breaks the bonds between H2S and CO2, and amine. Rich amine flows down the column and is heated by hot rising vapors from the reboilers. As the temperature increase, more absorbed gases are released. The gases flow out of the column as overhead product. The column overhead also contains steam from washwater that has vaporized in the column. Rich amine enters the regenerator at 75°C. Lean amine leaves the bottom of the regenerator at 140°C. Reboilers In the regenerator, heat must be provided to break the bonds between H2S, CO2, and amine. The reboilers supply the heat required for this purpose. Figure 5.7 shows the arrangement of the bottom of the regenerator and the reboilers. Part of the lean amine in the bottom circulates through the reboilers, where it is heated. The heated amine returns to the column as a vapor. The hot vapors rise in the column, removing sour gas from the rich amine. Figure 4.6 Regenerator and Reboilers [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 35 ADNOC Classification: Internal Overhead Condenser and Reflux Drum Sour gases (H2S and CO2) and steam leave the top of the column as overhead product. The vapors are cooled and condensed in the overhead condensers. The acid gases are separated from the steam condensate in the reflux drum. This is shown in figure 5.8 Condensate from the reflux drum (water) is pumped back into the column to cool the top. The cool washwater condenses the amine vapors in the gas stream which prevents amine from leaving the column as overhead. Figure 4.7 Overhead Condenser and Reflux Drum Lean Amine Cooler Lean amine from the bottom of the regenerator is divided into two streams. The main stream (90% of the flow) returns to the contactor through the fin-fan cooler. The cooler drops the temperature of amine before it enters the contactor. This is shown in figure 4.8 below. Figure 4.8 Lean Amine Cooler [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 36 ADNOC Classification: Internal Filters The secondary amine stream (10 % of flow) goes through the filters. As amine circulates in the system, it picks up particles from the process pipelines and solids from the sour gas. These particles are removed by the filters. This is shown in figure 4.9. The filters remove solid particles from the lean amine. After filtering, most of the lean amine flows through the recirculation pumps to the contactor. A small sidestream is sent to the reclaimer. Figure 4.9 Lean Amine Filter Reboiler (Reclaimer) As amine circulates through the system, chemical impurities are formed. The reclaimer removes these impurities. The reclaimer is a kettle reboiler as shown in figure 5.10. The reclaimer heats amine stream to a temperature that vaporizes it. The heat causes the compounds to break down into pure amine and sour gases. The vapors produced in this reaction leave the reclaimer as overhead gas and return to the regenerator. Chemical impurities that do not vaporize are collected in the bottom of the reclaimer and are drained to the sewer. About 10% of the lean amine from the filters is continuously cycled through the reclaimer. Figure 4.10 Reboiler (Reclaimer). [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 37 ADNOC Classification: Internal 5. NATURAL GAS DEHYDRATION PROCESS 5.1 Introduction Nearly all hydrocarbon reservoirs are at high pressures, high temperatures & have significant quantities of water in them. At these conditions of temperature & pressure, water present in the gas is in the vapour phase & gas is likely to be saturated with water vapour. The maximum amount of water vapour present in the gas is function of its pressure and temperature. Natural gas is often produced from the reservoirs saturated (in equilibrium) with water. In addition, the gas often contains CO2, H2S and heavy hydrocarbons which requires removal before exporting the natural gas to the consumers. As the gas flows to the surface & experiences reduction in temperature & pressure, some of the water vapour in the gas undergoes a phase change & condenses. This condensed water is called as produced water. Some part of the water from Oil/Gas wells always accompany with the well fluid which is termed as formation water. It is normally saline in nature. Water entrained in the gas is called as free water. The water content of gas is usually expressed in units of milligram of water per standard meter cube of gas (mg/Sm3) or in ppm or Kilogram per Million standard cubic meter Kg/MMscm. At a given pressure & temperature, the water content of the gas is at equilibrium with the gas; when the gas is fully saturated with water, it is called as “ wet gas”. By lowering the gas temperature, water vapor in the wet gas stream condenses & forms a dew. This temperature is called the "dew point" of the gas. 5.2 Importance of natural gas dehydration The presence of water in the natural gas can cause: Corrosion problems especially in the presence of CO2 or H2S. Slugging (two-phase flow) and erosion. Increase in specific volume and decrease in the heating value of gas. Freezing in cryogenic and refrigerated absorption plants. Accumulation of water in the lines which reduces the effective diameter of the pipeline and lowers its capacity. Solid hydrate formation under certain conditions. Sudden release of hydrate plugs, which could result in line failure and subsequent accidents and equipment damage. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 38 ADNOC Classification: Internal Dehydration of natural gas is very important, as it is required to: Prevent hydrates formation in equipment and pipelines, Prevent condensation of free water in processing and transportation facilities, Prevent corrosion and erosion of equipment and pipelines, Meet water content specification as per sales gas agreement. 5.3 Gas Hydrates Formation Hydrates are solid, ice-like crystallized compounds (show in Figure 5.1) formed of hydrocarbons and water. Hydrate formation occurs in high-pressure well streams with a low temperature. Hydrates can form, however, at temperatures above the freezing point. Hydrates cause freezing and blocking of pipelines, valves, and other equipment, bringing production to a halt. Hydrates may cause a serious damage to pipelines as shown in Figure 5.2. Figure 5.1 Hydrate Structure Figure 5.2 Hydrates hitting and breaking different parts in pipelines [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 39 ADNOC Classification: Internal Gas hydrates, are created when a light hydrocarbon molecule (commonly methane) is frozen in the molecular structure of ice. They are classified as clathrates, compounds formed by the inclusion of one molecule within cavities in the crystal lattice of another. A unique property of clathrates is the absence of chemical bonding, which makes it possible to separate them relatively easily. When hydrates are warmed or depressurized, it will revert back to water and natural gas. The best conditions for hydartes to form are low temperature, high pressure, moisture, and a light hydrocarbon molecule such as methane. Hydrates in natural gas can be extracted in different methods such as: Heat Application Depressurization Direct Removal Inject Inhibitor such as methanol or CO2 5.4 Technologies used for dehydration There are different techniques used for dehydrating natural gas. However, only two types of dehydration techniques are commonly used nowadays: Adsorption by solid desiccants Absorption by liquid desiccants 4.4.1 Dehydration by Adsorption Method Adsorption is a surface phenomenon. It is the process by which ions, atoms or molecules of gas adhere to the surface of a solid material. Solid surfaces show strong affinity for gas molecules that come in contact with them, and some of them are trapped on the surface. In an adsorption process, the solid is called the adsorbent and the solute is known as the adsorbate as shown in Figure 5.3 Figure 5.3 Gas Adsorption on solid surface [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 40 ADNOC Classification: Internal Dehydration by Adsorption Process Description Adsorption (or solid bed) dehydration is the process where a solid desiccant is used for the removal of water vapor from a gas stream as shown in Figure 44. The solid desiccants commonly used for gas dehydration are those that can be regenerated and, consequently, used for several adsorption–desorption cycles. Figure 5.4:Gas Dehydration by Solid desiccants Following are the steps of natural gas deydration by adsorption process: 1. Adsorber A is in line and wet gas passing through it and became dry gas. 2. Adsorber B is in regeneration, means Adsorber B bed is saturated with moisture (water). It’s time to remove saturated water from Adsorber B bed for next use. 3. Removing saturated water from bed is called regeneration. 4. When Adsorber A bed saturated with water vapor than Adsorber B will be on line for duty and Adsorber A bed will go for regeneration 5. For regeneration, Hot Fuel Gases will be used. Furness or heater will be use to heat up the fuel gas heating to get require regeneration temperature. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 41 ADNOC Classification: Internal Types of solid desiccants Three basic materials (shown in Figure 45) are used most commonly because they possess these characteristics in a satisfactory manner: (i) Activated alumina (ii) Silica gel and silica-alumina gel (iii) Molecular sieves Figure 5.5 Different Types of Adsorption Material 4.4.2 Absorption by liquid desiccants Gas dehydration by absorption method is based on contacting the gas stream with a hygroscopic liquid, which has a greater affinity for the water vapour than the gas. Ethylene Glycol is the best hygroscopic material for gas dehydration because of its non-hazardous nature and excellent water removing characteristics. Contactor pressure is subject to economic evaluation usually influenced by water removal duty, required water dew point, vessel diameter and wall thickness. After contacting the gas with Glycol, the water-rich glycol is regenerated by heating at approximately atmospheric pressure to a temperature high enough to drive off virtually all the absorbed water. The regenerated glycol is then cooled and recirculated back to the contactor. Liquid desiccants commonly used in the gas dehydration absorption process are Mono ethylene Glycol (MEG), Diethylene Glycol (DEG) and Tri-ethylene Glycol (TEG). [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 42 ADNOC Classification: Internal The block diagram of gas dehydration using liquid desiccants unit is shown in the figure 5.6. The unit consists of two main sections named Absorption and Regeneration. Figure 5.6 Glycol dehydration block diagram Gas dehydration Gas dehydration is generally carried out in a contactor tower called Glycol contactor or absorber. Wet Gas is introduced in the bottom and dry gas leaves from the top of contactor. Lean or pure Glycol is introduced from the top and impure or rich Glycol leaves from the bottom. Glycol contactor is operated at high pressure and low temperature whereas the glycol regenerator is operated at elevated temperature and low pressure. Glycol regeneration. Regeneration circuit involves a flash vessel, regenerator, still column, surge vessel and associated heat exchangers and pumps. In the regeneration section rich glycol is again converted in to lean glycol by driving away absorbed moisture from the Glycol stream. [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 43 ADNOC Classification: Internal A basic process flow diagram of glycol gas dehydration unit is shown in figure 5.7. More details are given in this diagram including the inlet separator, gas/ glycol heat exchanger, phase separator ( flash tank), regenerator ( still & reboiler), and surge tank. Figure 5.7 Gas Dehydration by liquid Desiccant (Glycol solution) [SPOM.S1.0223.01] [Oil & Gas Production Operations] Version: 0.1 44