Dr. Pavel Spirov Petroleum Engineering

Dr. Pavel Spirov Petroleum engineering

Separation processes Lecture 1 Dr. Pavel Spirov Petroleum engineering

Outline of the course 1,2 Theoretical

Practical

• Oil and gas processing • Oil and gas separators • Emulsion treating • Water treating facilities in oil and gas operations • Gas treating and processing • Pumps • Compressors • Piping and Pipelines • Safety systems • Oil storage

Aspen HYSYS In practical: Working in groups

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Introduction to course

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Literature and requirements: • HYSYS tutorial • Oil and gas production handbook • Petroleum Engineering Handbook Vol. 3 • Chemical engineering thermodynamics • PVT : Ali Danesh

For exercises: - PC - Installed Excel - Internet connection

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Oil and gas processing • Oil or gas wells produce a mixture of hydrocarbon gas, condensate, or oil; water with dissolved minerals, usually including a large amount of salt; other gases, including nitrogen, carbon dioxide (CO2), and possibly hydrogen sulfide (H2S); and solids, including sand from the reservoir, dirt, scale, and corrosion products from the tubing or the hydrocarbons (gas or liquid) to be sold, they must be separated from the water and solids, measured, sold, and transported by pipeline, truck, rail, or ocean tanker to the user. • Gas is usually restricted to pipeline transportation but can also be shipped in pressure vessels on ships, trucks, or railroad cars as compressed natural gas or converted to a liquid and sent as a liquefied natural gas (LNG). This chapter discusses the field processing required before oil and gas can be sold.

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Oil and gas processing • The goal is to produce oil that meets the purchaser’s specifications that define the maximum allowable water, salt, or other impurities. Similarly, the gas must be processed to meet purchaser’s water vapor and hydrocarbon dewpoint specifications to limit condensation during transportation.

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Oil and gas processing • The equipment between the wells and the pipeline, or other transportation system, is called an oilfield facility. An oilfield facility is different from a refinery or chemical plant in a number of ways. The process is simpler in a facility, consisting of phase separation, temperature changes, and pressure changes, but no chemical reactions to make new molecules • In a refinery, the feed-stream flow rate and composition are defined before the equipment is designed. For a facility, the composition is usually estimated based on drillstem tests of exploration wells or from existing wells in similar fields. The design flow rates are estimated from well logs and reservoir simulations. Even if the estimates are good, the composition, flow rates (gas, oil, and water), pressures, and temperatures change over the life of the field as wells mature and new wells are drilled.

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Oil and gas processing • Facilities have a design rate that is a best-guess maximum flow based on the number of wells, production profiles, and total oil or gas that can be produced from the reservoir. The actual production rates for a facility increase as the wells are completed up to the design rate.

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Definitions and terms • Crude oil is a liquid hydrocarbon produced from a reservoir. Condensate is liquid hydrocarbon that condenses from the gas as pressure and temperatures decrease when the gas is produced from the reservoir up the tubing and out the wellhead choke. • Condensate is usually lighter in color and lower in molecular weight and viscosity than crude oil; however, a light crude oil could have properties similar to a condensate.

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Definitions and terms • Hydrocarbons are composed of many different “components” or molecules of carbon and hydrogen atoms. Starting with the lightest molecular weight, they are methane (CH4), ethane (C2H6), propane (C3H8), butane (C4H10), pentane (C5H12), hexane (C6H14), and so on. • As the ratio of carbon to hydrogen atoms increases, the molecules become “heavier” and have a greater tendency to exist as a liquid rather than a gas

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Definitions and terms • A process simulation is a calculation, usually done with a computer program that predicts how the components that make up the well fluids react to changes in pressure and temperature as they are processed through the facility. This is not a chemical reaction, but rather a simple phase change as liquids flash to vapor or vapors condense into liquid. As the pressure is reduced or the temperature is increased, the lighter molecules, such as methane and ethane, tend to boil off into the vapor phase, taking some of the midrange components with them. The remainder of the midrange and most of the heavier molecules stabilize as liquid.

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Conventional oils make up 30%, heavy oils 15%, extra heavy oils 25% and tar sands 30%. Light oil Conventional oil    

Medium oil

Oil with API gravity greater than 25°. Oil with API gravity greater than 20°API but less than or equal to 25°API.

30% 30%

25%

      Unconventiona l oil

Heavy oil

Extra heavy oil

Oil with API gravity between 10°API and 20°API inclusive and a viscosity greater than 100 cP.   Oil whose API gravity is less than 12° and whose viscosity is commonly greater than 10,000 cP.

15%

conventional oil extra heavy oil

heavy oil tar sand

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14

Function of a Facility • Main Process - The main function of an oil facility is to separate the oil, gas, water, and solids; treat the oil to meet sales specifications • Secondary Process. - In addition to processing the oil and gas for sale, the produced water and solids must be treated for disposal. • Auxiliary Systems - In addition to the process systems, auxiliary process heating and cooling may be required. Lecture 1

Example Oil Facility • Separation

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Pressure [bar] Slug catcher P1 =25 High pressure P2 =15 separator (HP) Low pressure P3 = 5 separator(LP)

Temperatu re [ºC] T1 = 40 T2 = 40 T3 = 40 Lecture 1

Separation

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Oil Treating. • No separation is perfect, there is always some water left in the oil. Water content can range from less than 1% water to more than 20% water in the oil by volume. The lower the API gravity , the less efficient the separation.

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Produced-Water Treating. • As mentioned previously, separation is not perfect, and the amount of oil left in the water from a separator is normally between 100 and 2,000 ppm by mass. This oil must be removed to acceptable levels before the water can be disposed of. Lecture 1

Gas facility

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Gas treating • Heating. • Gas wells are often high pressure • This pressure must be reduced to the appropriate pipeline pressure at the point at which the gas flows through a wellhead choke. • When gas pressure is reduced, the gas cools, liquids can condense, and hydrates can form.

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• Hydrates are crystalline solids made up of hydrocarbon and water molecules and form in the presence of hydrocarbon gas and liquid water at temperatures significantly higher than the freezing point of water. These hydrates can plug the choke and flowline, so highpressure gas wells usually require a line heater that contains the flowline and choke inside a hot water bath to keep the well from freezing. • Hydrate formation can be inhibited by injecting a solvent, such as methanol, into the flowline. Lecture 1

Gas treating • Separation. The separator provides a place for any liquid to settle out from the gas. The separator pressure is set higher than the pipeline pressure so that the gas can go through the required cooling, treating, dehydration, and gas processing—each with some pressure drop— and arrive at the required pipeline pressure.

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Gas treating • Gas Treating. • Natural gas may have a number of impurities, such as H2S and CO2, which are referred to as “acid gases.” • Natural gas containing H2S is called a sour gas; if the gas contains no H2S, or if the H2S has been removed, it is “sweet gas.” The process of removing the H2S, and possibly CO2, is referred to as “sweetening.” H 2S gas is highly toxic. • CO2 forms a strong acid that is highly corrosive in the presence of water. Combined, they are corrosive; if the corrosion results in a leak, they can be deadly. • A common way to remove H2S and CO2 from natural gas is with an amine system, which uses a contact tower with trays or structured packing to pass the sour gas through the amine liquid, absorbing the H2S and some of the CO2.

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Process Control

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