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II. Gas processing plant Gas-oilseparators

Condensate

separator

Dehydration

Sweetening

Fractionation1/169

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1. Gas-oil separators

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Many cases pressure relief at the wellhead will cause a natural

separation of gas from oil (using a conventional closed tank, where gravityseparates the gas HC from the heavier oil)

Some cases a

multi-stage gas-oil

separation process

is needed to

separate the gas

stream from the

crude oil.

Multi-stage gas-

oil separation

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Vertical Separator

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Spherical Separator

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Condensates are most often removed from the gas stream at the

wellhead through the use of mechanical separators.

In most cases, the gas flow into the separator comes directly fromthe wellhead, since the gas-oil separation process is not needed

The condensate obtained on compression or refrigeration of

wet gas is termed as Naturalgasoline

2 Condensate separator

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3. Dehydration

Introduction

Necessity for gas dehydration

Preventative dehydration processes

Gas dehydrate methods

Operating Considerations

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Nearly all gas streams contain (or saturate) water vapor

The amount of water vapor depends on:

The temperature and pressure of the gas in the formation

The composition (or the density) of gas

A dehydration process is needed to eliminate water which may

cause the formation of hydrates

Sale gas is dehydrated because it must be dry enough to meet

contract specifications

The most important specs of sales gas (for pipeline transmission) is

water content

3. Dehydration

Introduction

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WATER CONTENTOF NATURAL GAS

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Example 1

Determine the water content of a natural gas which

has the density (compare with air) 0,6 at T= 50oC

and P = 20 bar?

Solution:

P = 20 bar = 2000 kPa

T = 50oC

P = 2000 kPa

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Wo= 4,6 g/Sm3kh

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Example 2

Determine the water content of a natural gas whichhas the density d = 0,8 at T= 50oC and P = 20 barand the salinity of Brine = 3,5%.

Gii: P = 20 bar = 2000 kPa T = 50oC

P = 2000 kPa

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W0cb= 4,6 g/Sm3kh

d = 0,8 CG= 0,99

Salinity= 3,5% Cs= 0,92

Vy: W = W0x CGx CS= 4,6 0,99 0,92

= 4,19 g/Sm3of gas

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Water present in the residue gas gas transmission difficulties:

3. Dehydration

Necessity for gas dehydration

Plugging the lines

Pressure control devices

Formation of hydrates

Expensive service disruptions Expensive line repairs

Corrosion - Erosion

Reducing the flow capacity of the lines

Condense in the pipeline andaccumulate at low points

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?Hydrate are ice-like mixtures

of water and hydrocarbons

which form at low temperature

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Structure of Hydrates

Nature of Hydratessolid solution

They have 2 types of

structure: I and II The structure of all

both types are basedon the Unit cell,which is pentagonaldodecahedron (D) 512

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Hydrate condition formation

The stable formation region of Hydrates is above these lines

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Example 3

A natural gas has d = 0,6 at P = 1,5MPa Hydrateforming temperature?

3,2oC

A natural gas has d = 0,6, if we increase P from 1,5Mpa to 2,5 Mpa Hydrate forming temperature willrise from3,2oCto

8,9oC

If the gas density increase from 0,6 to 0,8 Hydrate forming temperature will rise from3,2oCto

9,3oC

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For preventing hydrate formation:

1. Reduction of line P to permit the evaporation of the ice forming

particles.

2. Use of line heaters to elevate the gas T above that which would allow

hydrate formation.

3. Injection of certain inhibitors or chemicals (ammonia, alcohol, glycols)

into it to lower the freezing point of the water

For dehydrating: Removal of enough water from the gas to achieve a

dewpoint lower than any T the gas may encounter during transmission or

distribution.

3. Dehydration

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Alcohol:

Methanol and ethanol (methanol more effective than ethanol)

They are pumped into the system or forced in by means of

pressure chambers connected in the line.

Dewpoint depression is in direct ratio to the quantity of inhibitors

added

Injection of the chemical at controlled rates is important for its

uniform distribution and evaporation into the gas stream.

3. Dehydration

Preventative dehydration processes

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Ammonia:

Combination with the CO2in the gas forming ammonium carbonate

lower the transmission efficiency of the pipeline and system

Glycol:

Excellent anti-ice agent

Very difficult to recover especially when used in the field.

3. Dehydration

Preventative dehydration processes

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Dehydration by refrigeration with an inhibitor

Dehydration by absorption

Dehydration by adsorption

Dehydration by osmosis

3. Dehydration

Gas dehydrate methods

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Very popular for use

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Desiccants must fulfill certain requirements:

High affinity for water

Ability to be regenerated and yield the absorbed water

Non-corrosiveness

Low vapor pressure

Low viscosity

Low cost

Ease of regeneration

3. Dehydration

Gas dehyd rate methods

Absorption By Liquid Desiccants

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Absorption By Liquid Desiccants:

The most prominent physical dehydrating methods

Used extensively in Western Canada

Accomplished with many types of liquid desiccants (sulphuric

acid, calcium and lithium chloride solutions, glycerine and

others)

3. Dehydration

Gas dehyd rate methods

Absorption By Liquid Desiccants

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Desiccants: glycols(EG, DEG and TEGthe most common glycol used )

The solutions employed in plant dehydration processes are based on:

The contact temperature

Glycol concentration

Dewpoint temperature requirements

3. Dehydration

Gas dehyd rate methods

Absorption By Liquid Desiccants

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Effect of the TEG

concentration and

the contact

temperature on the

Dew point of gas

A greater dew point

depression can be

achieved by Increasing

glycol purity

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Diethylene Glycol Dehydration Plant

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Triethylene Glycol Dehydration Plant

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Flow Diagram of a Triethylene-Dessicant Unit

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Triethylene Glycol Dehydration Plant

Tinlet glycolshould be 10 15oF warmer than Tinlet ga

5.5

8.3oC

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In general, the absorbers run most efficiently at high pressure and low

temperature

The absorption of water vapor by TEG is fovarized at low T (10 40oC):

Lower 10oC glycol viscosity difficult to column operation

Upper 40oC dehydration effect + vaporization losses of TEG

The regeneration is fovarized at:

high T (but lower than the decomposition temperature of Glycols: (EG:

165oC, DEG: 164oC, TEG: 206oC, T4EG: 238oC)

Low P (but higher than the atmospheric pressure for preventing of leak

air into the regenerator flammable risk

3. Dehydration Operating Considerations

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A glycol circulation rate of 30 - 50 l/kg water removed is considered

adequate

Reconcentrate a dilute glycol solution (Regeneration) by heating it Glycol

purity is primarily determined by T of reboiler

Water and TEG have widely varying boiling points (100C and 287C

respectively) Separated easily by fractional distillation (use the packed

tower or stripper)

3. Dehydration

Operat ing Cons iderat ions

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3. Dehydration

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The cause(s) of reducing glycol purities:

A leak in a heat exchanger

The packing in the still column is partially plugged

Steam from the reboiler black-flows into the accumulator

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The essential components of installation:

A regeneration gas cooler for condensing water from the hot

regeneration gas.

A regeneration gas separator to remove water from the regeneration

gas stream.

Piping, manifolds, switching valves and controls to direct and control

the flow of gases according to process requirements.

3. Dehydration

Dehydration by adsorption

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The following terms apply to the technology:

Wet gas (gas containing water vapor)

Dry gas (dehydrated gas)

Regeneration gas (wet gas that has been heated in the

regeneration)

Desiccant is a solid (A typical desiccant might have as much as

0.82 m of surface area /mg)

3. Dehydration

Operat ing Cons iderat ions

Sol id Desicc ant Dehydrators

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Two Tower Solid Desiccant Dehydration Unit

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Zeolite (Molecular sieve), Activated alumina (bauxite) or a silica gel type

desiccant is used in most dehydration systems

They can reduce effectively the water content:

< 10 ppm with silica gel

< 0.1 ppm with Activated alumina

< 0.03 ppm with Zeolite

The degree of adsorption is a function of operating T and P:

Adsorption increases with pressure increases

Adsorption decreases with a temperature increase

3. Dehydration

Operat ing Cons iderat ions

Sol id Desicc ant Dehydrators

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A bed may be regenerated by:

Decreasing its pressure

Or increasing its temperature by hot gas (practice)

The hot natural gas:

Supplies heat

Carrier to remove the water vapor from the bed

3. Dehydration

Operat ing Cons iderat ions

Sol id Desicc ant Dehydrators

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Two Tower Solid Desiccant Dehydration Unit

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Three Drum Solid Desiccant Unit

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Regeneration Gas Temperature Versus Desiccant Bed

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Regeneration Gas Temperature Versus Desiccant Bed

Temperature in a Dry Desiccant Dehydrator

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When the bed is completely saturated with water vapor, the outlet gas

would be just as wet as the inlet gas

the towers must be switched from adsorb cycle to regenerationcycle before the bed has become completely saturated with water.

The usable life of a desiccant may range from one to four years in

normal service.

Abnormally fast degradation occurs through blockage of the small

pores and capillary openings

3. Dehydration

Dehydration by adsorption

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3 D h d ti

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Lubricating oils, amines, glycols, corrosion inhibitors, and other

contaminants (CANNOT be removed during the regeneration cycle)

eventually win the bed

H2S poisons the desiccant and reduces its capacity

Light liquid hydrocarbons may accumulate if adequate regeneration

temperatures are not attained

The cause of desiccant breakage:

High gas velocities

Slugs of free water reaching the desiccant

Sudden pressure surges

Install a special filter in the main gas stream behind the desiccant beds

3. Dehydration

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Dehydration by adsorption

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Severe fouling of the dry desiccant bed may occur in a very short time

when treating a gas stream containing both H2S and CO2

If CO2and H2S are present, corrosion may occur in the regeneration

gas heat exchanger

Occasionally corrosion is combatted by the injection of ammonia

ahead of the regeneration gas cooler

Help to control the pH

Ammonia and CO2react to form an unstable white solid plugs

up the pores of the desiccant

3. Dehydration

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Dehydration by adsorption

Flowsheet of a basic two tower dry desiccant unit

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Flowsheet of a basic two-tower dry desiccant unit

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4 Acid gas removal

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H2S

CO2

Acidgas

4. Acid gas removal

4 A id l

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4. Acid gas removal

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CO2

Corrosivematerial

Non-combustible

Catalystpoisoning

Capturessolar

radiation

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4 A id l

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ComponentMole percent

Sour gas Acid gas

CO2 8.50 18.60

H2S 13.54 78.71

CH4 77.26 1.47

C2H6 0.21 0.09

C3+ 0.23 0.11

COS 0.02 0.05

RSH 0.01 0.04

H2O 0.01 0.04

N2

0.34 0.00

Typical acid gas

and sour gas

constituents

Introduction

4. Acid gas removal

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4. Acid gas removal

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4 methods:

Absorption

Adsorption

Permeability

Distillation at low T

Very popular for use

Limited for use caused by the very

high selectivity of the membrane

For CO2removing

A id l b d ti

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Acid gas removal by adsorption

Chemical adsorption Physical adsorption

Process

Solvent

Process

Solvent

With Alkanolamine:

MEA

DEA

DIPA

DGA

Monoethanolamine

Diethanolamine

Diisopropanolamine

Diglycolamine

Selexol Dimethylether of

polyethylene glycol

(DMEPEG)

With K2CO3:

Normal

Bentild

Vetrocokk

Stretford

Hot K2CO3 solution

Hot K2CO3 solution + 1,8%

DEA

K3AsO3solution

2,6 - 2,7 antraquinonsulfonic

acid

Sulfinol Solution of sulfolane and

DiIsoPropanolAmine (DIPA)

Rectisol Methanol at low temperature

Purisol N - methyl - 2 - pirrolidone

(NMP)

Fluor Carbonate of propylene

4 Acid gas removal

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Absorption of Acid Gases Chemical Solvents

Carbonate Process

4. Acid gas removal

Hot potassium carbonate is used to remove both CO2, H2S and also COS

The reactions:

K2

CO3

+ CO2

+ H2

O 2KHCO3

K2CO3+ H2S KHS + KHCO3

High CO2partial pressure (the range of 26 bar) and temperature between

110116oC, are required to keep KHCO3, KHS in solution.

This process CANNOTbe used for streams that contain H2S only

Because: KHS is very hard to regenerate unless a considerable amount of

KHCO3is present.

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4 Acid gas removal

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The difference in H2S and CO2physical solubility gives the solvents their

selectivity.

Organic solvents are used in these processes to absorb H2S more than

CO2at high pressures and low temperatures.

Regeneration is carried out by releasing the pressure step by step

Selexol Process

Not rely on a chemical reaction with the acid gases

Use the dimethyl ether of polyethylene glycol (DMEPEG)

Requires less energy than the amine-based processes

It has high selectivity for H2S over CO

2that equals to 910

Absorption of Acid Gase Physical Solvents

4. Acid gas removal

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Selexol Process

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Selexol Process

4 Acid gas removal by permeability

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Selective permeation for gases occurs depending on the solubility at

the surface contact between the gas and the membrane.

The acid gas basically diffuses through the membrane if high

pressure is maintained to ensure a high permeation rate.

4. Acid gas removal by permeability

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Inlet gas Treated gas

Membrane

Impurities

4 Acid gas removal

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Absorption of Acid Gases

Membrane Absorption

The rate of permeation of the gas depends on the partial

pressure gradient as follows:

=

where PA: the gas permeability

Am : the membrane surface areat : the membrane thickness

PA: the partial pressure gradient of gas A above and

below the membrane.

4. Acid gas removal

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Spiral-Wound Membrane

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Hollow fiber membrane

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5 Fractionation

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5. Fractionation

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Cryogenic processing and absorption methods are some of

the ways to separate methane from natural gas liquids (NGLs). The cryogenic method is better at extraction of the lighter liquids,

such as ethane, than is the alternative absorption method.

Essentially, cryogenic processing consists of lowering the

temperature of the gas stream to around -120oF (-84.4oC)

While there are several ways to perform this function, the turbo

expander process is most effective, using external refrigerants to

chill the gas stream.

The quick drop in temperature that the expander is capable of

producing, condenses the hydrocarbons in the gas stream, but

maintains methane in its gaseous form.

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5. Fractionation

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The absorption method uses a leanabsorbing oil to separate the C1

from the NGLs. While the gas stream is passed through an

absorption tower, the absorption oil soaks up a large amount of the

NGLs.

The enrichedabsorption oil, now containing NGLs, exits the tower

at the bottom.

The enriched oil is fed into distillers where the blend is heated to

above the boiling point of the NGLs, while the oil remains fluid.

The oil is recycled while the NGLs are cooled and directed to afractionator tower.

Another absorption method that is often used is the refrigerated

absorption method where the lean oil is chilled rather than heated, a

feature that enhances recovery rates somewhat.

5 Fractionation

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5. Fractionation

The stripper bottom product from the LPG extraction plant

consists of propane, butane and natural gasoline with someassociated ethane and lighter components.

This is the feed to the LPG fractionation plant where it is

separated into a gas product, propane, butane and NGL.