Assignment and Project

8/13/2019 Assignment and Project

1/7

INDUSTRIAL PROCESS CONTROL

ASSIGNMENT

Max Marks: 05

Submission: 13th

Dec 2012 at 2:30pm

This is not a group task but individual performance will be evaluated

There will be a viva at the time of submission so avoid any plagiarism


2/7

Question#01:

Amine treatment plant is shown in the attached process flow diagram (PFD). Redraw the same

PFD using MS Visio and assign some suitable naming convention to tag each of the instruments,

vessels, pipes used in the diagram.


3/7

Details of Amine gas treating

Amine gas treatingrefers to a group of processes that use aqueous solutions of various alkanols

(commonly referred to as simply "amines") to remove hydrogen sulfide (H2S) and carbon dioxide

(CO2) from gases. It is a common process unit used in petroleum refineries, natural gasprocessing plants, petrochemical plants and other industries. The process is also known as acid

gas removaland gas sweetening.

Processes within petroleum refineries or natural gas processing plants that remove hydrogensulfide 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) Diglycolamine (DGA)

The most commonly used amines in industrial plants are MEA, DEA, and MDEA.

Amines are also used in many petroleum refineries to remove sour gases from liquid

hydrocarbons such as liquified petroleum gas (LPG).

1DescriptionofatypicalaminetreaterGases containing H2S or both H2S and CO2are commonly referred to as sour gasesor acid gases

in the hydrocarbon processing industries. The chemistry involved in the amine treating of suchgases varies somewhat with the particular amine being used. For one of the more common

amines, methanolamine (MEA) denoted as RNH2, the chemistry may be simply expressed as:

RNH2+ H2SRNH3HS

A typical amine gas treating process (as shown in the process flow diagram below) includes anabsorbercolumn and a regenerator column as well as accessory equipment. In the absorber, the

downflowing amine solution absorbs H2S and CO2from the upflowing 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 distillation column called 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 petroleum

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 intoa Claus unit to convert it into elemental sulfur. In fact, the vast majority of the 68,000,000 metric

tons of sulfur produced worldwide in 2010 was byproduct sulfur from petroleum refineries,

natural gas processing plants and other hydrocarbon processing plants. In some plants, more than

one amine absorber unit may share a common regenerator unit.


4/7

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 followingfour 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 % forremoving 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. Thefactors 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 CO2or whether the

unit is treating gases with a very high percentage of CO2such as the offgas from the steamreforming process used in ammonia production or the flue gases from power plants that use

fossil fuels. Both H2S and CO2 are acid gases and hence corrosive to carbon steel. However, in

an amine treating unit, CO2is the stronger acid of the two. H 2S 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 percentageof 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 the relative solubility of H2S and CO2in the selected amine. For more information aboutselecting the amine concentration, the reader is referred to Kohl and Nielson's book.

The choice of the type of amine will affect the required circulation rate of amine solution, theenergy consumption for the regeneration and the ability to selectively remove either H2S alone or

CO2alone if desired.

The current emphasis on removing CO2from the flue gases emitted by fossil fuel power plantshas led to much interest in using amines for that purpose.

In the steam reforming of hydrocarbons such as natural gas or petroleum naphtha to producegaseous hydrogen for subsequent use in the industrial production of ammonia, amine treating is

one of the commonly used processes for removing excess by-product carbon dioxide in the final

purification of the gaseous hydrogen.


5/7

Question#02

The oil that is extracted from the natural reservoir contains oil, gas as well as water

contents. The following diagram shows a simple 3 phase separator used in oil industry to

separate oil, gas and water.

a. Redraw the same P&ID using MS Visio and assign some suitable tags according to the

standard naming convention to each of the instruments, vessels, controllers, valves, and otherinstruments used in the diagram.

b. Describe the whole process in your own words

c. Identify the pressure relief valve and what is its function?


6/7

INDUSTRIAL PROCESS CONTROL

SIMULATION PROJECT

Max Marks: 05

Submission: 13th

Dec 2012 at 2:30pm

This is not a group task but individual performance will be evaluated

There will be a viva at the time of submission so avoid any plagiarism


7/7

Automation Task:

You are required to automate the separator process using Siemens S7-300 PLC. You can use the

simulator.

Gas should be allowed to pass through PV if P>200psi.

PRV should be operated at 220psi

Oil should be extracted if the level reaches above 5ft and the LV should be closed if level

reaches below 4ft

Water should be extracted if the water level reaches 4ft and water side LV should be closed if

water level goes below 3.5ft

Documents

Assignment and Project