Oil Gas Technologies 1

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Feker Engineering Training Center 25 June 2015

Oil & Gas Technologies


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Presentation content

Introduction to oil and gas processing

Oil & Gas separatoin plant typical block scheme

Central processing facilities (CPF) / Inlet Facilities overview

Oil treatment train ( Oil stabilization / Dehydration / Storge ang

export )

Gas treatment train (Gas Dehydration /Sweetening /compression)

NGL Recovery & Fractionation

Sulphur Recovery


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export )

Gas treatment train (Gas Dehydration /Sweetening /compression)


Sulphur Recovery


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IntroductionIt was not until 1859 that "Colonel" Edwin Drake drilled the first successfuloil well, with the sole purpose of finding oil.

The Drake Well was located in the middle of quiet farm country in

northwestern Pennsylvania, and sparked the international search for an

industrial use for petroleum

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 onthe left came in at 1,500 barrels per day in

July, 1862.


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Crude Oil Products


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Usage of oil internationally



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World wide Oil production Crude Oil Locations



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World wide Oil Production

Where is Natural Gas?



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World wide Oil Production

Natural Gas world demand



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Reservoir and wellheads

Reservoir:There are three main types of conventional wells. The most common is an oil well

with associated gas. Natural gas wells are drilled specifically for natural gas, and

contain little or no oil. Condensate wells contain natural gas, as well as a liquid

condensate.



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Oil & Gas formation & composition

Crude Oil: Crude Oil is a complex mixture consisting of up to 200 or more different organic compounds, (hydrocarbons & Non hydrocarbons) The hydrocarbons in crude oil are mostly (alkanes, cycloalkanes, aromatic- hydrocarbons)

The other organic compounds contain nitrogen, oxygen and sulfur, and trace amounts of metals (Fe,

Ni, Cu, etc.)

Meanwhile Non Hydrocarbons are ( Carbon Dioxide, Hydrogen Sulfide, Nitrogen, Mercury, Hydrogen,

Argon, Helium, etc.) Crude Oil is always associated with water and gaseous hydrocarbons. The API (American petroleum institute) gravity of a

particular crude is merely a measure of its specific gravity, or density

Crude oil API gravities typically range from 7 to 52 corresponding to

about 970 kg/m3 to 750 kg/m3, but most fall in the 20 to 45 API

gravity range

API < 35 (Heavy Oil)

API > 35 (Light Oil)


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Oil & Gas formation & compositionThe reservoirs fluids stratify to Natural Gas, Oil, Water

Natural gas found at the wellhead, although still composed primary methane, is by no means as pure. Raw natural gas comes from three types of wells: oil wells, gas wells, and condensate wells.

Natural Gases are classified as follows: Natural gas that comes from oil wells is typically termed associated gas (free gas / dissolved gas). Natural gas from gas and condensate wells is termed non associated gas


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Wellheads

The wellhead sits on top of the actual oil or gas

well leading down to the reservoir.

A wellhead may also be an injection well, used to

inject water or gas back into the reservoir to

maintain pressure and levels to maximizeproduction.

Manifolds/gathering

Gas gathering systems collect wet natural gas or

crude oil from the wellheads located at well pads where

they are diverted to manifolds and transport it to (CPF )

Central Process Facilities .


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Gathering systems can be very simple, short-distance flow control piping systems

for the output of just a few wells, or complex systems requiring thousands of

miles of piping and valves to control the pressure and flow of more than 100 gas

wells.


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GOSP definitionGOSP means Gas-Oil Separation Plant.

GOSP is the first facility downstream wellheads/flowlines. Scope of this plant is to

provide first separation of Crude Oil in Oil, associated Gas and associated Water

and delivers those products, at defined conditions, to downstream facilities

(refinery) for further

treatments.


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Typical Block Flow Diagram

Inlet

Separation

Stabilized Oil

to storage & delivery

Gas to other Plants

or to re-injection

Gas

CompressionUnit

De-hydration

and

Desalting Unit

STABILIZATION

Unit

WOSEP Water

to re-injection

M

A

NI

F

O

L

D


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Introduction to oil and gas processing Oil & Gas separatoin plant typical block scheme


Oil treatment train ( Oil stabilization / Dehydration / Storge

ang export )

Gas treatment train (Gas Dehydration/Sweetening

/compression)


Sulphur Recovery


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Oil and gas processing

Oil and gas wells produce a mixture of hydrocarbon gas, condensate or oil waterwith 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.The purpose of oil and gas processing is to separate, remove, or transform thesevarious components to make the hydrocarbons ready for sale.

For the hydrocarbons(gas or liquid) to be sold, they must be:

separated from the water and solids

measured sold

transported by pipeline, truck, rail, or ocean tanker to the user


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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKT

Stabilized OilSTABILIZATION


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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKET


SULPHUR

RECOVERYSULPHUR


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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKE

T


SULPHURRECOVERY

SULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4


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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKT


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+


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Oil treatment train ( Oil stabilization / Dehydration / Storge

ang export ) Gas treatment train (Gas Dehydration/Sweetening

/compression)


Sulphur Recovery


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Hydrocarbon preparation

The goal is to produce oil that meets the purchasers specifications that define themaximum allowable amounts of the following:

water

salt

other impurities

Similarly, the gas must be processed to meet purchasers water vapor andhydrocarbon dew point specifications to limit condensation during transportation.

The produced water must meet the following requirements:

1. regulatory requirements for disposal in the ocean if the wells are offshore2. reservoir requirements for injection into an underground reservoir to avoid

plugging the reservoir


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3. technical requirements for other uses, such as feed to steam boilers in thermal-

flood operations, or in special cases, for irrigation

Field facilities :

The equipment between the wells and the pipeline, or other transportation system, iscalled an oilfield facility. An oilfield facility is different from a refinery or chemicalplant in a number of ways.The process is simpler in a facility, consisting not of chemical reactions to make newmolecules, but of:

phase separation

temperature changes

pressure changes


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Oil facility

An oil facility encompasses the equipment between the oil wells and the pipeline or

other transportation system.

The purpose of an oil facility is to make the oil ready for sale to

the purchaser's standards (maximum allowable water, salt, and other impurities).

We will describes the key equipment and functions found in an oil facility.


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Typical oil facility


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Function of a facility

The main function of an oil facility is to :

1. separate the oil, gas, water, and solids

2. treat the oil to meet sales specifications (e.g., BS&W*, salt content, vapor pressure3. measure and sample the oil to determine its value

4. Deliver it to the transportation system (i.e., the pipeline, truck, ship, or railroad car)

*Basic sediment and water (BS&W)


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Oil Separation Process Flow Diagram


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Requirements of separators

Separators are required to provide oil/gas streams that meet saleable pipelinespecifioation as well as disposal.

Oil must have less than 1% (by volume) water and sales Gasless than 7bbm water/MMscf.

Water stream must have less than 20 ppm oil


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Gas facility

A gas facility includes all the equipment necessary for Gas treatment & conditioningbetween the gas wells and the transportationpipeline or other transportation method.

The purpose of the gas facility is to remove impurities andcontaminants from the gas, remove liquids and solids, and prepare the gas to meetthe sales requirements of the purchaser.


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CPF Scope :

Gas Plant Feedstock normally includes heavier hydrocarbons that shall be separatedfrom the main gas flow (lighter ends). Heavier ends shall be conditioned in order tomake them suitable for storage or transportation.

CPF Design :

Heavier ends separation is typically performed by a Slug Catcher that collects theliquid phase. These liquids are routed to the stabilization unit

Slug Catcher

Slug catcher is a static equipment used in the upstream oil production facilities tominimize the slug from oil and gas pipeline


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Typical gas facility


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Function of a facility

The main function of a facility is to :

1. separate the oil, gas, water, and solids

2. deliver it to the transportation system (i.e., the pipeline, truck,

ship, or railroad car)

The gas must be treated for sales or disposal. In the past, disposal sometimes meantflaring or venting, but now gas that cant be transported is usually compressed for

reinjection into the reservoir

Gas treating may involve only separation from the liquids, or it may includeadditional processes such as:


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Gas treating may involve only separation from the liquids, or it may includeadditional processes such as:

compression

dehydration

removing H2S and CO2 gas processing to condense heavier components that can be transported as a liquid


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Condensate Stabilization Process Flow Daigram


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Central processing facilities (CPF) / Inlet Facilitiesoverview

Oil treatment train ( Oil stabilization / Dehydration /Storage and export )

Gas treatment train (Gas Dehydration/Sweetening/compression)

NGL Recovery & Fractionation Sulphur Recovery


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Oil Treatment Train

( Oil stabilization / Dehydration / Storge ang export )

Oil treating

No separation is perfect, there is always some water left in the oil. Water content canrange from less than 1% water to more than 20% water in the oil by volume.The lower the American Petroleum Institute (API) gravity

(i.e., the higher the molecular weight and the oil viscosity), the less efficient theseparation.

Dehydration and Desalting Unit :

Crude oil often contains water, inorganic salts, suspended solids, and water-solubletrace metals. As a first step in the refining process, to reduce corrosion, plugging, andfouling of equipment and to prevent poisoning the catalysts in processing units, these

contaminants must be removed by desalting (dehydration).


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Oil Treatment Train


The two most typical methods of crude-oil desalting chemical and electrostaticseparation, use hot water as the extraction agent.

In chemical desalting, water and chemical

surfactant (demulsifiers) are added to the

crude, heated so that salts and other

impurities dissolve into the water or attach

to the water, and then held in a tank where

they settle out.

Electrical desalting is the application of high-voltage electrostatic charges toconcentrate suspended water globules in the bottom of the settling tank.


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Oil Treatment Train


Surfactants are added only when the crude has a large amount of suspended solids.


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Oil Treatment Train


Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+


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Oil Treatment Train


Oil stabilizationStabilization removes light gases, along with hydrogen sulfide, befor the oil is stored.

Hydrogen sulfide is commonly found in crude oil, and when exposed to water alsocommom in crude , it forms H2SO4sulfuric acid.

This acid can eat its way through a steel pipline or storage tank.

If released into the air, it is poisonous to all who inhale itThe Stabilization process dose two jobs: it sweetens the sure crude (remove thehydrogen sulfide) and it reduces vapor pressure, making the crude safe for shipmentin tankers.

The vapor pressure is caused by light hydrocarbonssuch as Methane, Ethane,

Propane, and Butane changing from liquid to gas as the crudes pressure is lowered.


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Oil Treatment Train


Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+


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Oil Treatment Train


STABILIZER

COLUMN

FEED

TC

Steam

Condensate

SP

Balance line

FC

Static head for

natural convention

circulation (BY

APRES)

As per pumpNPSH

requirements

(BY PROTEC)

Mixed Phase

PC

LC

Static head for

condensate return(by PROTEC)


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Oil Treatment Train


Typical Control Parameters

Section Controlled Parameters

Inlet separator

Dehydrator / Desalter

Stabilizer

Compression

Oil/water levels

Vessel pressure

Levels

Differential pressure across mixingvalve

Level

Pressure

Bottom temperature

Suction Pressure

Aircooler outlet temperature

l


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Oil Treatment Train


Typical Design Parameters/Guarantees

Item Design Parameters

Water content in oil

Salt content in oil

Oil RVP

Oil content in water

0.1 0.3 % volume10 20 ptb (pounds per thousand

barrel)

13 psia

50 100 ppm weight


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Central processing facilities (CPF) / Inlet Facilitiesoverview

Oil treatment train ( Oil stabilization / Dehydration /Storge ang export )

Gas treatment train (Gas Sweetening /GasDehydration/compression)




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Gas treatment train (Gas Sweetening /Gas Dehydration/compression)

Gas Sweetening

Acid/sour gas removal (CO2 and H2S) Most natural gas contains acid gas

CO2 (acid)

H2S and other sulfur compounds (sour)

Why remove acid gas:

Corrosion induced by acid gas (+ free water)

Freezing of acid gas in process equipment

Sales specifications

Toxicity and reactivity (H2S)

Typical specification for sweetened gas: CO2 in pipeline gas:


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Sour gas sweetening

Sour natural gas compositions can vary over a wide concentration of H2S andCO2 and a wide concentration of hydrocarbon components.

If the H2S content exceeds the sales gas specification limit, the excess H2S mustbe separated from the sour gas.

The removal of H2S from sour gas is called sweetening.

Overview of sweetening process

The process selected for sweetening a sour gas depends on the general conditions:

H2S and mercaptan concentration in the sour gas, and sales gas H2S and totalsulfur limits

maximum design flow rate

raw gas inlet pressure

requirement for sulfur

acceptable method of waste products disposal


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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+


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Process summary:

Unit ScopeGases coming from Inlet Facilities contain acid gases (H2S e CO2) have to beremoved in order to assure the product spec and to avoid corrosion phenomena indownstream units

Unit design

Feed is contacted by a solvent where, at high pressure and low temperature, acidscomponents are chemically absorbed.Solvents are fully regenerable at higher temperature and lower pressure in order to

assure a continuous process.

Unit Spec

Sweetened gas specification depends by market or by the downstream units.

NGL/LPGCO2 < 1-2% vol

H2S < 2 ppmCO2 < 50 ppm vol

H2S < Traces

LNG


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Amine Selection

In Gas plants taken in account here, the CO2 and H2S removal take place withchemical absorption processes employing as absorbent a ETHANOLAMINE aqueoussolution

The amine commonly used is the MDEA (Methil-Diethanol-Amine)

Complete Removal

Primary and Secondary AminesMEA

DEA

Activated Solvents

Tertiary AminesMDEA

TEA

Activated Solvents

Selective H2S Removal

CHNCHCHOH 222 )(


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CO2 Adsorption step is slow;

If amine flow is underdesigned, CO2

replaces H2S in the upper part of the

absorption colum.

Fast Step

H2S Absorption step is istantaneous;

Few trays are enough to assure a

complete absorption.

Slow Step

MDEA H2S

CO2

Chemical Absorption with MDEA


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Amine ReactionsAcid gases (H2S e CO2) reactions with Amine are reversible:

Acid gases Absorption reactions are promoted by high pressure and lowtemperature

Amine Regeneration reactions are promoted by low pressure and high temperature

H2S Reactions CO2 Reactions

RRNH+2

H2S H+ + HS -

HS- H+ + S - -

H2O H+ + OH -

H+ + RRNH RRNH+2 H+ + RRNH

RRNH+2+H2O RRNH+ + HCO3

-

H2O+CO2 H+ + HCO3=

H2O H+ + OH -

HCO3- H+ + CO3

=


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Typical Process Scheme

FEED

SWEET GASACID GAS

OFF GAS

Absorber

Regenerator

Flash Drum

Rich Amine

Lean Amine


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Main Paramenters

Sweet Gas Specification

Amine Circulating Capacity

Amine Concentration

Absorption Column Pressure

Regenerator Bottom Temperature

Regeneration Quality

Acid Gas Loading


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Gas Dehydration

All raw natural gas is fully saturated with water vapor when produced from anunderground reservoir, Because most of the water vapor has to be removed fromnatural gas before it can be commercially marketed, all natural gas is subjected toa dehydration process.

One of the most common methods forremoving the water from produced gas

are Glycol and Molecular sieve .


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Water dew point

Water occurs naturally in the reservoir Free water phase is removed in 3-phase separators

Water (vapour) is naturally dissolved in the natural gas

Water must be removed from the gas to avoid: Free water in gas pipelines (corrosion) Ice/hydrate formation (plugging of equipment and pipes)

Water removal processes:

Condensation (cooling and separation)

Absorption by glycol processes (moderate dew-pointing)

Adsorption on solids (severe dew-pointing)


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Water dew point

Offshore processes Onshore processes

Transport specification:

-18C at 69 barg

(20-30 ppm)

Process needed:

Glycol absorption process

Process specification:

0.1 to 1 ppmv

Process needed:

Adsorption on solids


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Water removal onshore - Adsorption on solids

Adsorption in to a solid material Used in deep gas processing at low temperatures Removal of smaller amounts of water Extreme dryness, down to 0.1 ppm water

Porous structures with high internalsurface area (200800 m2/g) Strong affinity for water, 525 % by weight Solids like

Molecular sieve (3A or 4A type) (Zeolite)

Activated alumina (Al2O3) Silica gel (SiO2) Activated carbon


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Dehydration process summuary

Unit ScopeThe sweetened gas coming from the Acid Gas Removal Unit is water saturated.Sweet Gas water content shall be reduced to prevent ice and hydrate formation in thedownstream units, which would cause blockage of lines and equipment.

Unit design

In gas plants, water removal is based on adsorption on Alumina/Silica Gel Beds,called Molecular Sieve working in swing operation.Molecular Sieves can adsorb selectively polar substances like water within theirpores.Water molecules leave the pores if the bed is crossed by a current dry and hot gas(regeneration).

Unit Spec

Residual water content shall be less than 0.5 ppm (mol) in the dryer effluent.


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Typical Process Scheme dehydration System Molecular sieve

Regeneration gas (63.0)

(pressure, bara)

Hot Oil

Regenerationgas

(63.7)

(63.2)

molecular sieve

(64.9)

Wet gas

Dry gas

)64.0(

>27.6230 99.99% (w/w) has been

A;

B;

G t t t t i (G S t i /G D h d ti / i )


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Glycol regeneration Component

Reboiler:

Temperature should not exceed 204 C (TEG) due to

degradation.

Some degradation of glycol in contact with heat

transfer surface maximum heat flux rates.

Heat provided with direct fired fire tubes immersed in

the bath, hot oil, steam or electric resistance heating.

Stripping Colum:

Can be trayed or structural packed. Stripping gas

lowers the partial pressure of H2O in the gas phase,

and more water can be absorbed by the gas (Raoults

law).

Surge drum:

Flash tank:

Used to remove light hydrocarbons,

CO2, H2S. Operation pressure 15% ofthe contactor operating pressure.

Filters:

Captures chemical impurities and solid

particles. Pressure drop is measured

and used as a replacing criteria.

Retention time >20 min

Be able to hold all the re-boiler glycol, to allow repair

or inspection of the re-boiler heating coil.



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Main Paramenters of Dehydration

Inlet water content Hydrates temperature formation Outlet water specification Number of beds Max allowable pressure drop

Regeneration available time Regeneration available flowrate Regeneration temperature

P t ti t t


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Oil treatment train ( Oil stabilization / Dehydration /

Storge ang export )

Gas treatment train (Gas Sweetening /Gas

Dehydration/compression)




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Natural gas liquid NGL

NGLs are hydrocarbon liquids that can be separated from a natural gas stream after theheavier hydrocarbon components have already been removed by separation at ambientTemperatures NGLs include:

ethane

propane

Butane natural gasoline.

Main reasons: HC dew point control (Sales Gas spec)

Economics: high value HC recovery



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Refrigeration cyclePrincipal thermodynamic path

Liquid recovery by refrigerationThermodynamic path

A-B,E cooled by heat exchange with the process gas.

B-C Natural gas is cooled by heat exchange with the refrigeration cycle. The gas temperature is lowered atconstant pressure.

E-F Natural gas is cooled by isentropic (constant entropy S) expansion through a turbine (turbo expander), EF

actual path.

B-D Natural gas is cooled by isenthalpic (constant enthalpy) expansion through a valve (Joule Thompson).



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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKE

T


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+



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Refrigeration cycle by Hysys



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Unit Scope

Avoid liquid HC condensation in the downstream unit/pipeline.

Recover and separate heavier components mixed in the dry gas.

Unit design

Design is different case by case.A lot of licensed unit are available depending by the scope of the unit.

As a general rule, gas is cooled by an external cooling medium; liquid are separatedand sent to the separation columns to obtain C2, C3 and C4.

A Propane cycle could be foreseen in order to increase the heavier recovery (DeepCut).

Unit Spec

Depending by the process and by the downstream unit/market requests.Ethane and propane recovery could vary from 70% to 98%.



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Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKE

T


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+



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NGL Fractionation



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Main Paramenters

Critical conditions Products requested recovery

Products requested purity

Demethanizer upper temperature

Expander efficiency

Available cooling medium

Available heating medium



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export )

Gas treatment train (Gas Sweetening /Gas

Dehydration/compression)


Sulphur Recovery

Sulphur Recovery


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Sulphur Recovery

Sulphur Recovery

Feed from

manifold

Gas & Oil

Separation

ACID GAS

REMOVALDEHYDRATION

DEW POINT

CONTROL

GAS

COMPRESSION

De-hydration /

Desalting

GAS TO

MARMARKE

T


SULPHUR

RECOVERYSULPHUR

NGL RECOVERY

&

FRACTIONATION

C2

C3

C4

C5+

Sulphur Recovery


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Sulphur Recovery

Unit ScopeConvert H2S into liquid sulphur (S2, S4, S6, S8) in order to contain the plant toxicemission,

Unit designDesign depends by the requested conversion and by Licensors.Normally design are improvement of the original Claus process.

As a general rule, acid gas preheated and burned in the Thermal Reactor where a part of

the H2S conversion is performed. Subsequent catalitic stages complete the sulphurconversion. Generally the requested conversion is higher than the maximumachievable by this process. It is then requested an additional unit (e.g. Tail Gas CleanUp) capable to achieve the target.

Unit Spec

Max H2S emissions are regulated by each Country laws.Claus process can achieve about the 95-96% of the sulphur conversion.Modified Claus processes can improve the conversion up to 99.8%.

Sulphur Recovery


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p y

Main Reactions

Thermal Stage Catalytic Stage

H2S + 3/2 O2 SO2 + 2 H2S 3S + 2H2O

H2S + O2 S + H2O

SO2 + H2O

Overall : Claus Reaction

Sulphur Recovery


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p y

Claus typical scheme

Sulphur Recovery


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p y

Sulphur Recovery Plant

Sulphur Recovery


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Sulphur Recovery

Main Paramenters

H2S concentration in Acid Gas Requested sulphur conversion H2S/SO2 ratio @ last condenser outlet Content of contaminants Thermal reactor temperature Catalytic converters temperature


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