University project guidance
CHEMSYS offers project gudaince for University students of Chemical/ Petrochemical Engineering in following subjects:
Early Production Facility:
The Basic Engineering will cover conceptual design, heat and material balance utilizing latest version of HYSYS, development of Process Flow Diagram (PFD), Piping and Instrument Diagram (P&I D), and preliminary Plot Plan. The major equipments will be sized and specified. The control philosophy will be developed and instrumentation requirements will be specified.
The oil wells flow lines are collected in four manifolds. The configuration of the field dictates that three manifolds to be in satellite stations and one manifold in the gathering center (GOSP). The manifolds are manual type with provisions for future automation. The production fluid is routed to either the production header or the test header. A drain header is also provided to prevent oil spillage in the environment.
The design foresees two stage separation processes. In the first stage the fluid will be flashed at 600 psig where the released gas is collected and sent to the flare regulating the separator pressure by pressure control system. The two liquid phases namely oil and water, are separated using the predetermined sufficient resident time in the vessel and discharged under level control system. The separated water which contains less than 1000 ppm oil will be skimmed off of oil to less than 10 ppm in an oil skimmer system and collected in the production water tanks. The oil which contains less than 5% water by volume flows into the second stage separator. The released gas in this stage is also sent to the flare system regulating the vessel pressure at about 100 psig utilizing pressure control system. The separated water will be directed to skimmer system to reduce the oil content to less than 10 ppm and collected in the water tank. The crude oil will be further treated in a Heater Treater where the fluid temperature rises to 120 ⁰F. The required heat is supplied by the associated gas from the production separator. The electro static section ensures efficient separation of the water and oil phases. The water is directed to the oil skimmer system and the oil is mixed with fresh water to dilute the salt content before entering the Desalter.
In the Desalter, the water smaller droplets are coalesced into droplets large enough to settle from crude oil to the desired level by virtue of electro static treating. The water content of the crude oil is guaranteed not to exceed 0.1% by volume and the salt will be less than 5 PTB.The oil is stabilized in the degassing both associated with the crude storage tanks where shipping pumps will transfer the crude oil to the consumer. The metering station equipped with the flow computer and the prover will totalize the amount of sold crude oil.
The project scope of supply also includes two gas power generators and one stand by diesel generator. The instrument air package, as well as fire and safety system is also included.High pressure and low pressure flare system ensures low emission of pollutant to the environment before future gas utilization project comes into effect.A control building with optional SCADA system is supplied to enable the end user to have supervisory control and data acquisition from remote control station.
Glycol Dehydration Unit:
Glycol dehydration is a liquid desiccant system for the removal of water from natural gas and natural gas liquids (NGL). It is the most common and economic means of water removal from these streams. Glycols typically seen in industry include triethylene glycol (TEG), diethylene glycol (DEG), ethylene glycol (MEG), and tetraethylene glycol (TREG). TEG is the most commonly used glycol in industry.
An example process flow diagram for this system is shown below:ter from natural gas and natural gas liquids. When produced from a reservoir, natural gas usually contains a large amount of water and is typically completely saturated or at the water dew point. This water can cause several problems for downstream processes and equipment. At low temperatures the water can either freeze in piping or, as is more commonly the case, form hydrates with CO2 and hydrocarbons (mainly methane hydrates). Depending on composition, these hydrates can form at relatively high temperatures plugging equipment and piping Glycol dehydration units depress the hydrate formation point of the gas through water removal.
Without dehydration, a free water phase (liquid water) could also drop out of the natural gas as it is either cooled or the pressure is lowered through equipment and piping. This free water phase will contain some portions of acid gas (such as H2S and CO2) and can cause corrosion.
For the above two reasons the Gas Processors Association sets out a pipeline quality specification for gas that the water content should not exceed 7 pounds per million cubic feet . Glycol dehydration units must typically meet this specification at a minimum, although further removal may be required if additional hydrate formation temperature depression is required, such as upstream of a cryogenic process or gas plant.
Process description :-Lean, water-free glycol (purity >99%) is fed to the top of an absorber (also known as a "glycol contactor") where it is contacted with the wet natural gas stream. The glycol removes water from the natural gas by physical absorption and is carried out the bottom of the column. Upon exiting the absorber the glycol stream is often referred to as "rich glycol". The dry natural gas leaves the top of the absorption column and is fed either to a pipeline system or to a gas plant. Glycol absorbers can be either tray columns or packed columns.
After leaving the absorber, the rich glycol is fed to a flash vessel where hydrocarbon vapors are removed and any liquid hydrocarbons are skimmed from the glycol. This step is necessary as the absorber is typically operated at high pressure and the pressure must be reduced before the regeneration step. Due to the composition of the rich glycol, a vapor phase having a high hydrocarbon content will form when the pressure is lowered.
After leaving the flash vessel, the rich glycol is heated in a cross-exchanger and fed to the stripper (also known as a regenerator). The glycol stripper consists of a column, an overhead condenser, and a reboiler. The glycol is thermally regenerated to remove excess water and regain the high glycol purity.
The hot, lean glycol is cooled by cross-exchange with rich glycol entering the stripper. It is then fed to a lean pump where its pressure is elevated to that of the glycol absorber. The lean solvent is cooled again with a trim cooler before being fed back into the absorber. This trim cooler can either be a cross-exchanger with the dry gas leaving the absorber or an aerial type cooler.
Enhanced Stripping Methods:- Most glycol units are fairly uniform except for the regeneration step. Several methods are used to enhance the stripping of the glycol to higher purities (higher purities are required for dryer gas out of the absorber). Since the reboiler temperature is limited to 400F or less to prevent thermal degradation of the glycol, almost all of the enhanced systems center on lowering the partial pressure of water in the system to increase stripping.
Common enhanced methods include the use of stripping gas, the use of a vacuum system (lowering the entire stripper pressure), the DRIZO process, which is similar to the use of stripping gas but uses a recoverable hydrocarbon solvent, and the Coldfinger process where the vapors in the reboiler are partially condensed and drawn out separately from the bulk liquid.
Amine gas treating:
Amine gas treating, also known as gas sweetening and acid gas removal, refers to a group of processes that use aqueous solutions of various alkylamines (commonly referred to simply as amines) to remove hydrogen sulfide (H2S) and carbon dioxide (CO2) from gases.[1][2] It is a common unit process used in refineries, and is also used in petrochemical plants, natural gas processing plants and other industries.
Processes within oil refineries or chemical processing plants that remove hydrogen sulfide and/or mercaptans are commonly referred to as sweetening processes because they result in products which no longer have the sour, foul odors of mercaptans and hydrogen sulfide.
There are many different amines used in gas treating:
• Monoethanolamine (MEA)
• Diethanolamine (DEA)
• Methyldiethanolamine (MDEA)
• Diisopropylamine (DIPA)
• Aminoethoxyethanol (Diglycolamine®) (DGA®)
The most commonly used amines in industrial plants are the alkanolamines MEA, DEA, and MDEA.Amines are also used in many oil refineries to remove sour gases from liquid hydrocarbons such as liquified petroleum gas (LPG).
Description of a typical amine treater:Gases containing H2S or both H2S and CO2 are commonly referred to as sour gases or acid gases in the hydrocarbon processing industries.The chemistry involved in the amine treating of such gases varies somewhat with the particular amine being used. For one of the more common amines, monoethanolamine (MEA) denoted as RNH2, the chemistry may be simply expressed as:
A typical amine gas treating process (as shown in the flow diagram below) includes an absorber unit and a regenerator unit as well as accessory equipment. In the absorber, the down flowing amine solution absorbs H2S and CO2 from the up flowing sour gas to produce a sweetened gas stream (i.e., an H2S-free gas) as a product and an amine solution rich in the absorbed acid gases. The resultant "rich" amine is then routed into the regenerator (a stripper with a reboiler) to produce regenerated or "lean" amine that is recycled for reuse in the absorber. The stripped overhead gas from the regenerator is concentrated H2S and CO2. In oil refineries, that stripped gas is mostly H2S, much of which often comes from a sulfur-removing process called hydrodesulfurization. This H2S-rich stripped gas stream is then usually routed into a Claus process to convert it into elemental sulfur. In fact, the vast majority of the 64,000,000 metric tons of sulfur produced worldwide in 2005 was byproduct sulfur from refineries and other hydrocarbon processing plants. Another sulfur-removing process is the WSA Process which recovers sulfur in any form as concentrated sulfuric acid. In some plants, more than one amine absorber unit may share a common regenerator unit.
The amine concentration in the absorbent aqueous solution is an important parameter in the design and operation of an amine gas treating process. Depending on which one of the following four amines the unit was designed to use and what gases it was designed to remove, these are some typical amine concentrations, expressed as weight percent of pure amine in the aqueous solution:
• Monoethanolamine: About 20 % for removing H2S and CO2, and about 32 % for removing only CO2.
• Diethanolamine: About 20 to 25 % for removing H2S and CO2
• Methyldiethanolamine: About 30 to 55% % for removing H2S and CO2
• Diglycolamine: About 50 % for removing H2S and CO2
The choice of amine concentration in the circulating aqueous solution depends upon a number of factors and may be quite arbitrary. It is usually made simply on the basis of experience. The factors involved include whether the amine unit is treating raw natural gas or petroleum refinery by-product gases that contain relatively low concentrations of both H2S and CO2 or whether the unit is treating gases with a very high percentage of CO2 such as the offgas from the steam reforming process used in ammonia production or the flue gases from power plants. Both H2S and CO2 are acid gases and hence corrosive to carbon steel. However, in an amine treating unit, CO2 is the stronger acid of the two. H2S forms a film of iron sulfide on the surface of the steel that acts to protect the steel. When treating gases with a very high percentage of CO2, corrosion inhibitors are often used and that permits the use of higher concentrations of amine in the circulating solution. Another factor involved in choosing an amine concentration is the relative solubility of H2S and CO2 in the selected amine.
The choice of the type of amine will affect the required circulation rate of amine solution, the energy consumption for the regeneration and the ability to selectively remove either H2S alone or CO2 alone if desired.The current emphasis on removing CO2 from the flue gases emitted by fossil fuel power plants has led to much interest in using amines for that purpose. (See also: Carbon capture and storage and Conventional coal-fired power plant.)In the specific case of the industrial synthesis of ammonia, for the steam reforming process of hydrocarbons to produce gaseous hydrogen, amine treating is one of the commonly used processes for removing excess carbon dioxide in the final purification of the gaseous hydrogen.