PRG.pr.GAS.0001 Gas Dehydraion

Form code: MDT.GG.QUA.0516 Sht. 01/Rev. 1.94 Cod.file: CRIDESBI.DOT Data File: PRG_PR_GAS_0001_E.doc CONFIDENTIAL document. Sole property of Saipem. Not to be shown to Thid parties or used for purposes other than those for which it has been sent.

B. U. ONSHORE

DESIGN CRITERIA

GAS DEHYDRATION

PRG.PR.GAS.0001

Rev. 0

January 2010

PRG.PR.GAS.0001

Rev. 0 Date Jan 2010

Sheet 2 (90)


I N D E X

1. SCOPE AND PURPOSE 5

2. REFERENCE DOCUMENTS 5

3. DEFINITIONS 5 3.1 Specific Definitions 5 3.2 Symbols and Abbreviations 8

4. ACTIVITIES DESCRIPTION 12 4.1 Glycol Gas Dehydration 13

4.1.1 General 13 4.1.2 System Description and Process Flow Diagram 16 4.1.2.1 Gas Stream 17 4.1.2.2 Glycol Stream 17 4.1.2.3 Enhanced Regeneration Systems 19 4.1.3 Design Variables 22 4.1.3.1 Inlet Gas Flow rate 22 4.1.3.2 Inlet Gas Temperature 22 4.1.3.3 Inlet Gas Pressure 25 4.1.3.4 Lean TEG temperature 25 4.1.3.5 Lean TEG Concentration 25 4.1.3.6 Glycol Circulation Rate 26 4.1.3.7 Number of Stage in the Contactor 27 4.1.4 Equipment Design 27 4.1.4.1 Inlet Gas Cooler 27 4.1.4.2 Inlet gas Separator or Scrubber 27 4.1.4.3 Contactor 28 4.1.4.4 Glycol Flash Vessel 35 4.1.4.5 Regenerator and Reboiler 36 4.1.4.6 Surge Drum 44 4.1.4.7 Heat Exchangers 45 4.1.4.8 Condensed Overheads Separator 46 4.1.4.9 Filters 47

PRG.PR.GAS.0001


Sheet 3 (90)


4.1.4.10 Glycol Circulation Pumps 49 4.1.4.11 Glycol StorageTank 49 4.1.4.12 Glycol Sump Vessel 50 4.1.4.13 Enhanced Regeneration Equipment Design 51 4.1.5 Materials 55 4.1.6 Operation and Maintenance 56 4.1.6.1 Oxidation 56 4.1.6.2 Ph Control 56 4.1.6.3 Salt Contamination 57 4.1.6.4 Hydrocarbon Contamination 57 4.1.6.5 Sludge Accumulation 57 4.1.6.6 Foaming 57 4.1.6.7 Acid gas solubilities and stripping 58 4.1.6.8 Mercury in Feed gas 58

4.2 Molecular Sieves Dehydration 59 4.2.1 General 59 4.2.2 System Description and Process Flow Diagram 65 4.2.2.1 Adsorption Mechanism 67 4.2.3 Design Variables 68 4.2.3.1 Gas Composition 68 4.2.3.2 Flow Rate 68 4.2.3.3 Pressure 68 4.2.3.4 Temperature 69 4.2.3.5 Further variables affecting the efficiency of

regeneration 69 4.2.3.6 Utilities Availability and Local Conditions 69 4.2.4 Equipment Design 70 4.2.4.1 Scrubber 70 4.2.4.2 Gas Dehydrator 71 4.2.4.3 Regeneration Calculations 76 4.2.4.4 Special Bed Configurations 79 4.2.5 Operation and Maintenance 80 4.2.5.1 Operation Records 80 4.2.5.2 Good Operational Techniques 80 4.2.5.3 Depressurization / Repressurization 80

PRG.PR.GAS.0001


Sheet 4 (90)


4.2.5.4 Analyzers 81 4.2.5.5 Insulation 81 4.2.5.6 Effects of contaminants on molecular sieves 81 4.2.6 Process Control and Safeguarding 82

5. FLOW CHART 83

6. APPENDIX 84 6.1 Appendix I – Water removal at different TEG

concentration and TEG circulation rates 84 6.2 Appendix II – Reboiler Heat Duty 87 6.3 Appendix III – Molecular Sieve Equipment Sizing –

Example 88

PRG.PR.GAS.0001


Sheet 5 (90)


1. SCOPE AND PURPOSE

The purpose of this document is to provide the design guidelines for natural gas dehydration processes.

For equipment mechanical details the relevant SAIPEM or Project criteria shall be considered.

The application of this Design Criteria shall be subjected to accurate review of the results by a qualified and

competent designer to avoid unnecessary over sizing or design not adequate to the scope.

Moreover, margins indicated in the following paragraphs shall be considered as the minimum to be applied

in case no indications are present in the Project documents or in other SAIPEM standards.

2. REFERENCE DOCUMENTS

- PRG.PR.VES.0001 Guide to selecting and process sizing vessels

- PRG.PR.VES.0011 Guide to process sizing fractionating columns

- PRG.PR.GEN.0003 Guide to selecting standards for process equipment internals

- PRG.PR.HEB.0001 Guide to process selection and sizing of heat exchangers

- PRG.PR.MAC.0001 Guide to selecting and process sizing pumps

- PRG.PR.TUB.0001 Process piping sizing guide

- PRG.PR.HEB.0002 Guide to process sizing furnaces

- PRG.PR.MAC.0002 Guide to the process design of compressors

- GPSA Engineering Data Book

- Natural Gas Conditioning Though Adsorption Technology (J. M. Campbell, W. P. Cummings)

3. DEFINITIONS

3.1 Specific Definitions

Absorber See contactor Absorption Process The attraction and retention of vapours (water) by liquids

(glycol) / solids from a gas stream. Actual Trays The number of trays installed in a column or the equivalent

number of actual trays for a packed column. Bubble Cap Tray Horizontal plate holding bubble caps and downcomers in the

contactor. Bubble Caps Slotted metal caps attached over elevated nozzles (risers) on

the bubble cap trays. The slots cause the gas to break upinto small bubbles for intimate contact with the glycol.

PRG.PR.GAS.0001


Sheet 6 (90)


Condensate Light hydrocarbon liquids. Contactor (or Absorber) A vertical pressure column where gas and glycol are

intermingled counter-currently to remove water vapour fromthe gas. The contactor usually contains bubble cap trays,valve trays or structured packing.

Dehydration Removal of water vapour from a gas or a liquid. Design Pressure The pressure used in the design of a vessel for the purpose

of determining the minimum permissible wall thickness orphysical characteristics of the different parts of the vessel.

Dewpoint The temperature at which vapour begins to condense into a

liquid at a particular system pressure. A natural gas streamexhibits both hydrocarbon and water dewpoints.

Dewpoint Depression The difference in water dewpoint temperature between the

gas entering and leaving the contactor. Downcomer The vertical conduit between trays which allows liquid to pass

from tray to tray. Flood The condition wherein excess liquid hold-up occurs and

normal counterflow action is prevented in the glycolcontactor, regeneration still or stripping column. It is a designlimit which when reached in operation causes an excessiveloss of liquid from the top of the column.

Free Water Liquid water which is not dissolved in any other substance. Gas/Glycol Heat Exchanger A heat exchanger employed to cool the lean glycol by the gas

leaving the contactor before the glycol enters the contactor. Glycol A hygroscopic liquid. Mono-ethylene Glycol (MEG) and Di-

ethylene Glycol (DEG) are commonly used in hydrateinhibition service and Tri-ethylene Glycol (TEG) is mostcommon in gas dehydration service.

Lean Glycol (or Dry Glycol) Glycol which has been regenerated and has a low water

content. Rich Glycol (or Wet Glycol) Glycol which has absorbed water and thus has a high water

content. Glycol Flash Separator A three phase separator which is used in the rich glycol

stream to remove entrained gas and hydrocarbon liquids. Glycol/Glycol Exchanger A heat exchanger employed to recover heat from the

outgoing hot lean glycol from the reboiler and for pre-heatingthe incoming cool rich glycol from the contactor.

PRG.PR.GAS.0001


Sheet 7 (90)


Heat Duty The rate of heat absorption by the process. Heat Flux The average heat transfer rate to the fluid. Inlet Gas Separator (Scrubber)

A separator which removes free liquids from the inlet gasstream. The separator may be included or not in thecontactor.

Packing Material installed in the contactor, still column or stripping

column that provides a large surface area for merging liquidand vapour to facilitate mass transfer during absorption,distillation or stripping. Random packing consists of shaped pieces (e.g. rings,saddles) that have been dumped, not stacked, in the column.Structured packing is essentially a series of parallel formedmetal sheets.

pH Measure of the acidity of a liquid on a scale of 0 to 14 with 7

being neutral. 0 to 7 is acidic and 7 to 14 is alkaline. Reboiler A heat exchanger for boiling water out of the glycol. Regeneration System A unit including reboiler, still column and other related

facilities to regenerate (or re-concentrate) rich glycol to leanglycol.

Reflux Condensed liquid which flows back a column to maximise

separation efficiency. Saturated Gas (with respect to water)

A gas stream which contains the maximum amount of watervapour at a given temperature and pressure withoutcondensing the water.

Sparging Tube Internal pipe in the reboiler used to distribute stripping gas. Standard (pressure and temperature)

Unit of gas volume at reference conditions of 1 bar and 15°C.Abbreviated: m3(st).

Still Reflux Column Vertically mounted distillation (fractionation) column on top of

the reboiler. Stripping Column A packed column where glycol from the reboiler flows

downward to the surge drum while gas flows upwardstripping the water from glycol.

Stripping Gas Gas that is contacted with glycol to help remove water from

the glycol. Surge Drum Reservoir for regenerated glycol which is included or not in

the reboiler.

PRG.PR.GAS.0001


Sheet 8 (90)


Theoretical Tray One in which the vapour and liquid leaving the stage are in

equilibrium. The number of actual trays is equal to thenumber of theoretical trays divided by the overall trayefficiency.

Transfer Unit The dimensionless distance within which the solute

molecules transfer to the gas phase. A transfer unit can becalculated for a theoretical stage.

Tray Efficiency The ratio between the number of theoretical and actual trays. Valve Tray Horizontal plate holding valves and downcomers in the

contactor. A valve consists of a liftable metal plate whichcovers a hole in the tray, providing a variable area for gasflow.

3.2 Symbols and Abbreviations

A Area [m2] BTEX Aromatic components: benzene, toluene, ethylbenzene and xylene - Cp Heat Capacity [kJ/(kg K)] Css Saturation correction factor for sieve CT Temperature correction factor D Inside diameter of column or vessel [m] DEG Diethylene glicol - D Nozzle inside diameter, or diameter (with subscript) [m] EG Ethylene glicol - F Packing factor [m-1] FF Fraction of flood - G Acceleration due to gravity [9.81 m/s2] G Gas mass flowrate/unit area [kg/(s.m2)] H Height [m] H Henthalpy [kJ/kg] HC Height of channel or riser height of distributor [m]

PRG.PR.GAS.0001


Sheet 9 (90)


HETP Height equivalent to a theoretical plate [m] ILL Interface level of condensate and glycol [m] L Length of vessel between tangent lines [m] Ls Length of racket bed saturation zone [m] HLL High level pre-alarm [m] LLL Low level pre-alarm [m] LCV Level control valve - HHLL High level trip [m] LLLL Low level trip [m]

•

m Mass flowrate [kg/s]

MEA Methylethanol amine - MMSCF Milion of standard cubic feet - MTD Mean temperature difference [°C] MTZ Mass Transfer Zone - N Number of bubble cap - NLL Normal level of liquid [m] NPSH Net positive suction head [m] OVHD Overhead - P Pressure [Pa] PG Propilene glicol - PSV Safety relief valve - PVT Pressare-Volume-Temperature - Q Volumetric flow rate or Heat [m3/s] or [kJ] Re Reynold's number - T Temperature [°C] or [K]

PRG.PR.GAS.0001


Sheet 10 (90)


t Thickness [mm] TCV Temperature control valve - TEG Triethylene glicol - TREG Tetraethylene glicol - TS Tray spacing in contactor [m] TTL Top tangent line on vessel - U Overall heat transfer coefficient [W/(m2K)] UCR Unit circulation rate, volumetric flowrate of lean glycol per mass

flowrate of water removed [l/kg]

V Velocità [m/s] W Width [mm] Wr Water removed per cycle [kg]

Greek Symbols

Δ Separation between plates in separator, difference in parameter values (as in Δρ)

[m]

ρ Density [kg/m3] λ Gas load factor:

[m/s]

μ Dynamic viscosity [Pa.s] or [mPa.s] ψ Ratio of ρ of water to ρ of glycol - ϕ Flow parameter:

-

PRG.PR.GAS.0001


Sheet 11 (90)


Subscripts

B Bed G Gas (as in vg) Hl Heat loss I Initial In Inlet (as in vin, Yin) L Liquid M Mixture (as in vm) Min Minimum Max Maximum Out Outlet Rg Regeneration Si Sieve St Steel Tr Total regeneration W Water

Superscripts

* Density correction (e.g. in Q*max)

PRG.PR.GAS.0001


Sheet 12 (90)


4. ACTIVITIES DESCRIPTION

Gas Dehydration is the process of reducing the water content in the gas down to an acceptable level for the

downstream systems. At the wellhead, reservoir fluids almost invariably contain water and, except for a few

shallow wells, produced natural gas is saturated with water. The major reasons for dehydrating gas are:

• natural gas can combine with liquid or free water to form solid hydrates that can plug valves,

fittings, equipment or even pipelines;

• if not separated from the produced water, natural gas is corrosive, especially when CO2 and/or H2S

are also present;

• water can condense in the pipeline causing slug and possible erosion and corrosion;

• water vapour increases the volume and decreases the heating value of the gas;

• sales gas contracts and/or pipeline specifications have a maximum water content (usually 110 kg

H2O / million (st)m3 i.e. 7 lb H2O per MMSCF) or a specified dew point value;

• freezing in cryogenic and refrigerated absorption plants even in small quantities.

Natural gas is commercially dehydrated in one of the following methods:

1. Absorption Glycol Dehydration

2. Adsorption Molecular Sieve or Silica Gel

3. Condensation Refrigeration with Glycol Injection

Glycol dehydration (absorption) is the most common dehydration process used to meet pipeline sales

specification and field requirements (gas lift, fuel, etc.). Adsorption process are used to obtain very low

water contents (0.1 ppm vol or less) required in low temperature processing such as deep NGL extraction

and LNG plants. Condensation is commonly used as a dehydration process when the gas is employed in

moderate levels of refrigeration or in pipeline transportation. An inhibitor such as ethylene glycol (EG) or

methanol is used to prevent hydrate formation.

PRG.PR.GAS.0001


Sheet 13 (90)

4.1 Glycol Gas Dehydration

4.1.1 General

Glycol dehydration plants have many applications for natural gas dehydration. They are used to reach a

water dew point in the range of -30 ÷ -40°C. They are preferred for the following reasons:

• low installation costs ;

• operating costs similar to other dehydration systems;

• glycol dehydration is continuous process rather than batch;

• low pressure drop across the plant (0.35÷0.7 bar);

• easiness to treat gas at low pressure;

• possibility to receive gas at high feed temperature (till 66°C);

• low costs for obtaining small reductions in the gas dew point.

The principle of glycol dehydration is contacting a gas stream with a hygroscopic liquid which has a greater

affinity for the water vapour than does the gas.

After contacting the gas, the water-rich glycol is regenerated by heating at approximately atmospheric

pressure to a temperature high enough to drive off virtually all the absorbed water. The regenerated glycol

is then cooled and recirculated back.

All the following glycol types possess suitable properties to be used in a dehydration plant:

• Triethylene glycol (TEG) is the most commonly used dehydration liquid and it is the assumed glycol

type in this process description because it is the most cost-effective choice. TEG is the most easily

regenerated to a concentration of 98÷99.5% (using stripping gas) in an atmospheric stripper

because of its high boiling point. This permits higher dew-point depression of natural gas in the

range of 27÷66°C. Moreover, TEG has an initial theoretical decomposition temperature of 206.7°C,

higher than other glycol types and it is not too viscous above 21°C.

• Diethylene glycol (DEG) is sometimes used when hydrate inhibition is required upstream of

dehydration or due to the greater solubility of salt in DEG. Moreover, DEG is somewhat cheaper to

buy and sometimes is used for this reason. Compared to TEG, DEG has a larger carry-over loss,

offers lower dew point depression, and regeneration to high concentrations is more difficult due to

lower degradation temperature and consequent lower regeneration temperature.

• Tetraethylene glycol (TREG) is more viscous and more expensive than the other glycols. The only

real advantage is its lower vapour pressure which reduces absorber vapour loss. For this reason, it

should only be considered for rare cases where glycol dehydration will be employed on a gas

whose temperature exceeds about 50°C, such as when extreme ambient conditions prevent

cooling to a lower temperature.


PRG.PR.GAS.0001


Sheet 14 (90)

• Propylene glycol (PG) has been employed in some units and it is the least toxic glycol. It has a

lower affinity for aromatics, but PG has a much higher vapour pressure than TEG, and a much

lower flash point.

Physical properties of glycols are the following:

Glicol MEG DEG TEG TREG

Formula HOC2H4OH HO(C2H4O)2H HO(C2H4O)3H HO(C2H4O)4H

Molecular mass 62.07 106.12 150.17 194.32

Boiling point 101.3 kPa (°C) 197 245 287 327

Freezing point (°C) -13 -8 -7.2 -6.2

Density 20°C (kg/m3) 1113 1116 1123 1246

Viscosity 20°C (mPa.s) 20.9 35.7 47.9 60.0

Degradation temperature (°C) 165 164 206 238

Flash Point (°C) 111 124 165 202

Auto Ignition temperature (°C) 410 229 370 358

Toxicity YES YES YES YES

Table 1 – Physical Properties of MEG, DEG, TEG and TREG

Glycols as a class are of a low order of toxicity (with the exception of oral toxicity). They do not vaporise

readily at normal temperatures and, therefore, do not constitute a hazard from inhalation. They are also not

active skin irritants.

Glycols will burn and should be handled as if they were hydrocarbons. As they are highly miscible with

water, alcohol type foam concentrate shall be used for extinguishing of a glycol fire. For extinguishing of

small fires some dry powder types can be effective.

TEG has been applied downstream of production facilities that use MEG or DEG as a hydrate inhibitor

without apparently leading to contamination problems. Methanol used as a hydrate inhibitor in the feed gas

to a glycol dehydration unit will be absorbed by the glycol, and according to the GPSA Engineering Data

Book it can cause the following problems:


PRG.PR.GAS.0001


Sheet 15 (90)

1. methanol will add additional reboiler heat duty and still vapour load and therefore increase

glycol losses;

2. aqueous methanol causes corrosion of carbon steel. Corrosion can thus occur in the still

and reboiler vapour space;

3. high methanol injection rates and consequent slug carry-over can cause flooding.

Glycol entrainment may lead to the following downstream problems:

• coalescing and partial condensation in pipelines resulting in localised corrosion;

• in cryogenic plants, particularly at temperatures below -25°C, freezing of TEG and plugging of

equipment;

• reduced performance of downstream adsorption plant, e.g. molecular sieves or silica gel.

Any entrained glycol should be removed upstream of cryogenic plant in high efficiency gas/liquid separators

to prevent possible plugging.

A range of lean TEG concentrations can be achieved with the basic regeneration flow schemes and various

enhancements summarised in

Table 2 and further described in the following paragraphs. It should be noted that the corresponding

dewpoint depressions are approximate and achievable figures are affected by actual process conditions.

Regeneration Process Basic Cold Finger Vacuum Stripping Gas Azeotropic

Stripping Lean TEG

concentration (wt%) 98.75 99.5 99.9 99.96 99.99

Dewpoint Depression (°C)

45 60 65 70 100

Table 2 – Lean TEG Concentrations with Regeneration Systems


PRG.PR.GAS.0001


Sheet 16 (90)

4.1.2 System Description and Process Flow Diagram

The basic flow scheme without enhancements, such as stripping gas, is described below with reference to

Fig. 1, and follows the two main streams, gas and glycol. It is typical and many variations are possible.

Flash Gas

Fig. 1 – Simplified Process Flow Diagram for TEG Dehydration System


PRG.PR.GAS.0001


Sheet 17 (90)

4.1.2.1 Gas Stream

Where feed temperatures are high, especially relative to ambient conditions, an inlet cooler may be used.

Feed gas is scrubbed of free liquids (water and condensate) and solid particles before entering the glycol

contactor. The separator may stand alone or form an integral part of the glycol contactor column. The latter

solution is usually preferred for small gas flowrate.

The saturated feed gas is introduced in the bottom of the contactor and rises up through the column where

it contacts lean glycol which is injected in the top of the column. The contacting devices may be trays or

packing. Dry gas leaves the column via a de-entrainment device, e.g. a demister mat, to remove entrained

droplets.

Flash gas from glycol flash vessel and off gas from still column overhead could have a high content of H2S,

BTEX and volatile hydrocarbon and are usually routed to low pressure flare.

4.1.2.2 Glycol Stream

Lean glycol from surge drum flows through the rich/lean glycol heat exchanger to cool the lean glycol

stream before entering the glycol circulation pumps. In some arrangements there will be two rich/lean glycol

heat exchangers in series.

Although there will be some pressure drop through the heat exchanger, due to the temperature reduction

the glycol should not flash at this point. If there is insufficient NPSH for the glycol pumps in the location

shown, they may be located between the surge drum and the lean/rich glycol heat exchanger. In this

location the pumps will operate at a higher temperature. Sufficient NPSH can be created for the main glycol

pumps by installing glycol booster pumps, if necessary.

The lean glycol then flows to the final cooler, which is often an air-cooled heat exchanger but could also be

a glycol-gas heat exchanger. In some cases (generally for low glycol circulation rate) lean glycol cooling

coils are installed in the top section of contactor thus avoiding the installation of the gas/glycol heat

exchanger.

From the glycol final cooler, the lean glycol enters the top of the contactor. On its way down the column the

glycol absorbs water and the rich glycol collects at the bottom of the contactor.

The rich glycol passes from the contactor via a level control valve to a coil in the top of the regeneration still

column, thereby providing reflux cooling in the still column.

Rich glycol is heated to about 60°C or 70°C in the rich/lean glycol heat exchanger before it enters the glycol

flash vessel. In this 3-phase separator, dissolved and entrained gas is removed from the glycol and liquid

hydrocarbon condensate, if present, is separated from the glycol. These hydrocarbon components would

flash in the regenerator and lead to an increased still column vapour load, a higher reboiler duty

requirement, greater glycol losses and a loss of recoverable product. These components would also lead to

coking of the reboiler heating elements, fouling and foaming.


PRG.PR.GAS.0001


Sheet 18 (90) While this arrangement is typical (heating reduces glycol viscosity and makes gas and condensate

separation easier), in some units the glycol flash vessel is located immediately downstream of the

contactor, operating at a lower temperature.

From the flash vessel the rich glycol flows through a full flow particle filter and an activated carbon filter

often in slipstream service, to remove solids and dissolved hydrocarbons and degradation products,

respectively, in order to prevent foaming and sludge build-up in the regenerator.

The rich glycol is further heated in a second rich/lean glycol heat exchanger and then flows to the

regenerator still column between two sections of packing. This is a typical arrangement, in some systems

the glycol flows directly to the regenerator without passing through a second glycol/glycol heat exchanger.

Heat is provided at the bottom of the regenerator evaporating water from the glycol. The reboiler may be

directly fired or indirectly heated by electricity, hot oil or steam. Typical operating temperatures are up to

204°C, i.e. 2°C lower than degradation temperature (see Fig. 2). Water and volatile species present are

evaporated from the rich glycol, the reflux is provided to reduce glycol losses. Because of the wide

difference in volatility only a small reflux is needed to effect water/glycol separation. Off gas is normally

cooled and sent to a three phase separator where condensate and oily water are recovered and sent to

treatment/disposal. The regeneration units are designed to operate at prevailing atmospheric pressure and

at temperature lower than the initial thermal decomposition temperatures of the glycols shown below:

GLYCOL DECOMPOSITION

TEMPERATURE

LEAN GLYCOL

CONC., wt%

SUGGESTED

REGENERATION

TEMPERATURE

EG 165°C 96.0 164°C

DEG 164°C 97.1 163°C

TEG 206°C 98.7 204°C

TREG 238°C - 236°C

Table 3 – Glycol Decomposition Temperatures

These are the temperatures at which measurable decomposition begins to occur in the presence of air. In

the units containing no air (oxygen), it has been found that the reboiler can be operated very close to the

above temperatures without noticeable decomposition. The composition of the lean glycol is set by the

bubble point composition at the regenerator pressure. Maximum concentration achievable in an

atmospheric regenerator operating at decomposition temperature is also shown in the above Table 3.


PRG.PR.GAS.0001


Sheet 19 (90)

Fig. 2 – TEG concentration vs. reboiler temperature

If the lean glycol concentration required at the absorber (to meet the dew point specification) is higher than

the maximum concentrations above, then some enhanced methods (see par. 4.1.2.3) of increasing the

glycol concentration at the regenerator shall be incorporated in the unit. Generally all of these methods

involve lowering the partial pressure of the glycol solution either by pulling a vacuum on the regenerator, or

by introducing stripping gas into the regenerator.

4.1.2.3 Enhanced Regeneration Systems

A. COLDFINGER

The "Coldfinger" method is a patented process which has been used in a number of locations, mostly in the

USA, to give enhanced glycol regeneration. It consists of a heat exchanger tube bundle with a liquid

collection through which is inserted into the vapour space of the surge drum. The heat exchanger tubes are

fed with either rich glycol before flowing to the still column reflux, or with cooling water, which gives a lower

temperature. This "cold finger" leads to condensation of some vapour which is richer in water than the

regenerated TEG in the liquid space of the surge drum. The condensed vapours collected are continuously

recycled back to the still column feed. The H2O partial pressure in the vapour space is thus lowered and the

lean glycol concentration increased. Lean TEG concentration of 99.5÷99.9 wt% have been achieved in

Coldfinger units without the use of stripping gas, although a small amount of gas is introduced into the

surge tank for pressure balancing. A simplified scheme of this regeneration process is shown in Fig. 3.


PRG.PR.GAS.0001


Sheet 20 (90) B. AZEOTROPIC STRIPING (DRIZO)

The azeotropic striping "DRIZO", shown in Fig. 3, is a patented process to give enhanced regeneration of

glycol. It utilises a circulating solvent, such as heptane or octane, to remove water by azeotropic stripping.

The regenerator vapours are condensed in a 3-phase separator and condensed solvent is returned to the

regenerator via a pump and solvent heaters. Some solvent is lost in the remaining vapour stream to vent.

Depending on the composition of the gas being dried, sufficient heavy ends can be absorbed by the glycols

in the contactor to more than compensate for these losses. Thus, an initial charge may only be needed for

start-up and excess hydrocarbon liquid can be recovered as a product.

This unit has the advantage of providing very high stripping gas rates with little or no venting of

hydrocarbons. Glycol concentrations in excess of 99.99% have been achieved with the DRIZO process. It

has an added advantage of condensing and recovering aromatic hydrocarbons from the still column

overhead. In fact, these unit often operate with a stripping solvent which is not iso-octane but a mixture of

aromatic, naphthenic and paraffin hydrocarbons in the C5-C8 range.

C. STRIPPING GAS

Glycol concentration can be increased by injecting a small quantity of stripping gas via a sparge pipe in the

surge drum or via a packed stripping column with a counter-current glycol flow, as shown in Fig. 3. The

latter alternative is preferred since it allows either a glycol concentration of 99.96 % instead of 99.9 % to be

achieved or alternatively a reduction in the stripping gas rate. If introduced directly to the reboiler, it is

common to use a distributor pipe along the bottom of the reboiler. Any inert gas is suitable as stripping gas:

it may be drawn from the fuel gas system, from the gas being dehydrated or from exhaust gas from a gas-

powered glycol pump if used. The use of stripping gas, however, is not recommended due to the increase

of hydrocarbon emissions when vent gas from still column is routed to flare.


PRG.PR.GAS.0001


Sheet 21 (90)

Rich TEG

Vent gas to flare or recycle

Still Column

Direct Fired

Reboiler

Surge Tank

Lean TEG

Stripping Gas

A) Stripping Gas

Rich TEG

Vent gas to flare or recycle

Still Column

Direct Fired

Reboiler

Surge Tank

Lean TEG

Rich TEG

Still Column

Direct Fired

Reboiler

Surge Tank

Lean TEG

Cooling MediumWater/Rich

TEG mixture to Still Column

B) Coldfinger ®

C) Drizo ®

Solvent Condenser

Solvent Vaporizer

Excess Solvent

Water

Vent

Drizo® Separator

Stripping Solvent

Fig. 3 – TEG Regeneration Alternatives (Stripping Gas, Coldfinger® and Drizo®)

D. VACUUM

The vacuum process utilises a low partial pressure over the glycol solution to achieve a higher glycol

concentration. This is achieved by drawing a vacuum on the stripping column. These units are not common

due to their high operating costs, control complexity and problems with glycol degradation due to air

infiltration.


PRG.PR.GAS.0001


Sheet 22 (90)

4.1.3 Design Variables

A properly designed and operated TEG unit will dehydrate natural gas with only minor difficulties and

require modest maintenance.

High glycol losses, excessive TEG recirculation rates, improperly operating pumps, needless energy

consumption, frequent plant shutdowns and excessive equipment replacement can lead to very high

operating costs. The overall design of a glycol system requires optimisation of many variables that interact

with each other.

This paragraph explains the effect of process variables on TEG unit optimisation.

4.1.3.1 Inlet Gas Flow rate

The load (kg/hr H2O to be removed) varies directly with the feed gas flow rate. Normally the trays (bubble

cap usually and valve type sometimes) are operating in a severe spray regime, i.e. very little liquid glycol

compared to the gas flow rate. Increases in feed gas flow rate can exacerbate this delicate condition of

“blowing flood” and can be very detrimental to contactor performance. Random or structural packing is not

susceptible to this “blowing flood” because the liquid flows as wetted film on the packing surface. In

addition, an increase in gas flowrate can lead to excessive glycol losses and overload of regenerator; of

course the capability of the other units (i.e pumps and reboilers) must be considered. The lower flow limit is

determined by the “overdesign” and the turndown ratio (depending on the type of the internals used).

4.1.3.2 Inlet Gas Temperature

Inlet gas temperature is a significant variable. Higher gas temperature requires more glycol circulation,

since:

- there is an exponential increase in the water vapour content of the saturated gas (see Fig. 4);

- a higher inlet dew point requires a higher dew point depression for a given outlet dew point;

- a higher unit circulation rate (UCR) is required due to an increase in the equilibrium value of water

dew point for a given lean glycol concentration.

Higher temperature also reduces the gas density leading to a higher volumetric gas flow and load factor.

The operating inlet gas temperature shall be in the range 25÷50°C.

Hydrates may form if the temperature of the water saturated gas is less than about 20°C, therefore it is

desirable to have the inlet gas temperature at least 5°C above the hydrate formation temperature. It has to

be noted that at very low inlet gas temperature (i.e. < 15°C) the increase of glycol viscosity will reduce the

efficiency of absorption and will increase the foaming tendency.


PRG.PR.GAS.0001


Sheet 23 (90) Gas cooling upstream of the inlet scrubber is generally recommended, especially for temperatures above

50°C, since it is usually more economic than providing increased glycol circulation and regeneration

capacity. Reducing the glycol circulation rate is also preferred to reduce losses.

Above 50°C the inlet gas contains too much water, and the drying ability of the glycol is reduced. Moreover,

at higher temperature glycol vaporisation losses become appreciable. In addition, if the inlet gas

temperature is much higher than ambient temperature, heavier hydrocarbons could condensate on the wall

of the contactor.

Glycol into contactor needs to be slightly warmer (3 ÷ 6°C) than the inlet gas to avoid hydrocarbon

condensation.


PRG.PR.GAS.0001


Sheet 24 (90)

Fig. 4 – Equilibrium Water Dew Point Vs Temperature


PRG.PR.GAS.0001


Sheet 25 (90)

4.1.3.3 Inlet Gas Pressure

The pressure effect is quite small. Operation is theoretically possible up to pressures of 150 to 200 bar.

However, in practice operations at pressures above 135 bar, i.e. outside 900# ANSI pressure rating, are

not recommended. The HETP increases with pressure and glycol vapour loss may become excessive at

gas densities greater than about 100 kg/m3.

At pressure below about 35 bar, the gas contains significantly more water vapour and the effect of pressure

is quite appreciable.

4.1.3.4 Lean TEG temperature

While TEG can theoretically dehydrate natural gas at operating temperatures from 10°C to 55°C the

preferred temperature range is 30 ÷ 55°C. The equilibrium water dew point decreases with decreasing

temperature, but cooling below 20°C the glycol becomes too viscous. This reduces tray efficiency,

promotes foaming, and increases glycol losses. Below 10°C the drop in dehydration efficiency is very

pronounced. The inlet glycol temperature should be 3÷6°C higher than the inlet gas temperature. If the

glycol enters cooler than the gas, the resulting chilling condenses hydrocarbons, which, in turn, promote

foaming. If the glycol enters more than 8°C above the effluent gas temperature, TEG vaporization losses

are increased unnecessarily.

4.1.3.5 Lean TEG Concentration

The lean glycol concentration has the greatest effect on the dew point depression highly affecting

equilibrium water dew point of dry gas. For standard dehydration systems, the factors affecting

concentration are the reboiler operating temperature and the quantity of stripping gas used, as discussed in

par. 4.1.2.3. The drying ability of TEG increases rapidly with concentration as illustrated in Fig. 5.


PRG.PR.GAS.0001


Sheet 26 (90)

Fig. 5 – Equilibrium Water Dew Point Vs TEG Concentration

4.1.3.6 Glycol Circulation Rate

Total glycol circulation rate is a function of the total amount of water to be removed from the gas and the

Unit Circulation Rate (UCR). As indicated in 4.1.3.2, a higher inlet gas temperature increases the water

vapour content of the saturated gas, the dew point depression required, and the UCR, all of which

compound total circulation requirement.

Increasing the circulation rate, the dew point depression will increase by providing a higher mean difference

between the operating and equilibrium lines. However, for UCR above 40 litres/kg, the improvement is

usually small and the reboiler duty becomes excessive. Increasing the number of trays (or packing height)

or the glycol concentration are generally more effective means to increase the dew point depression,

especially when the percentage of the inlet water to be removed is high. A lower circulation rate will also

reduce the sensible heat requirement of the system. A minimum design UCR of 18 litres/kg is

recommended. Typically UCR varies between 25 and 40 litres of glycol per kg of water removed.

Figures in Appendix I illustrate the effect of different TEG circulation rates on water removal, at different

TEG concentration. Curves have been determined at fixed temperature and number of equilibrium stages.


PRG.PR.GAS.0001


Sheet 27 (90)

4.1.3.7 Number of Stage in the Contactor

At a fixed value of lean TEG concentration, it can be selected a contactor with several stages and a low

circulation rate, or one with few stages and a high circulation rate.

At fixed values of lean TEG concentration and circulation rate the water concentration in the treated gas

has an asymptotic trend when the number of theoretical trays is 5 or higher.

In conclusion, the number of trays in the Contactor is economically less important than other design

variables (i.e. lean TEG concentration and circulation rate) in fact, due to the large difference between

boiling point of glycol and water, few stages are required for dehydration; hence more efforts shall be made

to optimise other process variables above mentioned.

4.1.4 Equipment Design

This section recommends the minimum requirements for the design, material selection and fabrication of

glycol-type gas dehydration systems. The components of a basic system are described in a detailed

manner. Supplementary design details for enhanced regeneration methods (see 4.1.2.3) are present.

The equipments described in this section shall be equipped with piping, instruments, valve actuators, level

shutdown devices and other accessories to make a complete and functional system. It shall be understood

that sample connections, vents, low point drains and minor material items required to make the system

functional are part of the assembly.

4.1.4.1 Inlet Gas Cooler

Whenever possible, the feed gas should be cooled by air or water ahead of the inlet separator, since this is

generally a cheaper form of dehydration. The inlet cooler shall operate above the hydrate formation

temperature, taking into account minimum ambient temperature scenario with all fans switch off.

4.1.4.2 Inlet gas Separator or Scrubber

An inlet gas separator with a minimum liquid removal efficiency of 99% of liquid droplets > 10 µm shall be

provided upstream of the dehydration unit, even if it is downstream of a production separator. The need of

removing entrainment from the gas stream before the contactor is emphasized by the fact that most of all

gas dehydration problems are caused by inadequate scrubbing of the inlet gas. Five of the more common

contaminants that impair the performance of the glycol systems are:

1. Entrained or Free Water. This water increases the glycol recirculation, reboiler duty, and

fuel costs. If the unit becomes overloaded, glycol can be carried over from the contactor

and/or the still column.


PRG.PR.GAS.0001


Sheet 28 (90)

2. Oils or Hydrocarbons. Dissolved oils (aromatic or asphaltic) reduce the drying capacity of

the glycol and, with water, cause foaming. Undissolved oils coke on the heat transfer

surfaces in the reboiler and increase the viscosity of the glycol.

3. Entrained Brine. These salts dissolve in the glycol, are corrosive to steels (especially

stainless) and can deposit on the fire tubes in the reboiler, causing hot spots and fire-tube

burnout.

4. Down-Hole Additives. They are for example corrosion inhibitors, acidizing and fracturing

fluids. These materials cause foaming, corrosion, and hot spots if they deposit on the fire

tubes.

5. Solids. They are for instance sand and corrosion products. They promote foaming, erode

valves and pumps and eventually plug trays and packing.

Heat tracing may be used to eliminate condensing liquids between the separator and the contactor.

The separator can also be arranged inside the contactor column below the contacting section. The

combination of the contactor and separator in one column offers savings in total weight, space and costs.

Liquids that might otherwise condense in the piping between the separator and contactor are also avoided.

The separator internals may either be of the demister type or a high efficiency type (High efficiency inlet

device-mist mat-multicyclone separator). In the latter case the required diameter for separation will be

considerably smaller than that required for contacting.

4.1.4.3 Contactor

As shown in Fig. 6, the absorber consists of an optional integral scrubber at the bottom, a mass transfer or

drying section in the middle, and a mist extractor at the top. In smaller units, the lean glycol is cooled in a

coil located in the contactor just below the mist extractor, while in larger units, a separate, external heat

exchanger is used (see 4.1.4.7). Wet natural gas enters the integral scrubber tangentially, and then passes

through a wire-mesh mist extractor that removes most of the remaining entrained liquid droplets.

In the drying section, the gas flows upward and is contacted intimately by the descending glycol solution.

This counter-current contact usually employs 4 to 12 bubble cap or valve trays or packed bed.

Liquid glycol carryover should not exceed 16 kg/MMSm3 (1 lb/MMscf), therefore a mist extractor should be

provided at the top of the absorber.

Various configurations for the contactor are possible; the main variables are the choice of contacting

internals, and whether or not the inlet gas separator is arranged in the column.

The following Fig. 7 and Fig. 8 show the possible different configurations.


PRG.PR.GAS.0001


Sheet 29 (90)

Fig. 6 – TEG Contactor


PRG.PR.GAS.0001


Sheet 30 (90)

Dry gas outlet

Glycol outlet

Demister mat

Manhole

Glycol inlet

Bubble cap trays (5 to 8 typical)

Wet gas inlet

Manhole

Vortex breaker

LAHH

HC skimmer

0.15 D (min 0.15 m)0.10 m

2 TS

TS (0.6 m typical)

TS

TS

TS

0.5 d (min 0.3 m)

d + 0.02 m0.05 D (min 0.15 m)

Inlet gas distributor

Glycol inlet

Bubble cap trays (5 to 8 typical)

TS (0.6 m typical)

TS

TS

TS

0.10 m

2 TS

0.15 D (min 0.15 m)

Glycol outlet

0.05 D (min 0.15 m)

d + 0.02 m

d (min 0.3 m)0.1 m0.2 D (min 0.3 m)

hc (0.8 m typical)

min 0.4 m

HC skimmer

Glycol outlet

Gas riserRiser cap

Chimney tray

Demister mat

Wet gas inlet

Manhole

Vortex breaker

LAHH


Demister mat

Dry gas outlet

Manhole

Fig. 7 – Glicol Contacor with Bubble Cap Trays (left side) and with Bubble Cap Trays and inelt Separator (right side)

0.05 D (min 0.15 m)

d + 0.02 mWet gas inlet

LAHH


Demister matManhole (0.6 m typical)

Glycol inlet

Liquid distributor

Structured packing

Gas riserRiser cap

Chimney trayDrain pipe

HC skimmer

Manhole

Vortex breaker

0.4 m typically

0.10 m0.6 m (or 0.3 m for a full dia. top flange)

0.15 D (min 0.15 m)

Packed height 2.5 – 4.0 m

typically

0.2 D (min 0.3 m)

hc (0.25 m typical)

min 0.4 m

Glycol outlet

Dry gas outlet

Demister matManhole (0.6 m typical)

Glycol inlet

Liquid distributor 0.4 m typically

0.10 m0.6 m (or 0.3 m for a full dia. top flange)

0.15 D (min 0.15 m)

Dry gas outlet

Structured packing

0.05 D (min 0.15 m)d + 0.02 mWet gas inlet

LAHH


HC skimmer

Manhole

0.2 D (min 0.3 m)

Drain pipe

Vortex breaker

Liquid outlet

Packed height 2.5 – 4.0 m

typically

min 0.4 m

hc (0.25 m typical)

0.3 m

0.51 m

0.10 md (min 0.3m)

Glycol outlet

Demister mat

Multicycle trays

Chimney trayGas riser

Riser cap

Fig. 8 – Glicol Contacor with Structured Packing (left side) and with Structured Packing and Inlet Separator (right side)


PRG.PR.GAS.0001


Sheet 31 (90)

Manufacturers shall be required to provide fully dimensioned and detailed drawings of the internals,

including layout and location of gas risers, liquid inlet and, where applicable, drip pipes. A skim line is

required from the bottom section of the contactor to prevent accumulation of condensate. This should be

located such that condensate can be skimmed with glycol at the normal operating level.

A check valve should be installed as close as possible to the injection point of the contactor to prevent a

reversed flow and gas entering the glycol injection line in the event of a pump failure or line rupture.

For design details of the internals refer to PRG.PR.VES.0011 and to PRG.PR.GEN.0003.

• Chimney Tray A chimney tray is required immediately below the contacting section for all configurations except for trays

with an external separator. The chimney collects the wet glycol and, for columns with an integral separator,

it provides a liquid volume for level control. For columns with structured packing this tray also acts as a gas

distributor.

• Contacting Internals The options for the contacting internals include bubble cap trays, valve trays, random packing, structured

packing and multicyclone trays. Since glycols tend to foam, the trays should be spaced at least 450 mm

and preferably 600÷760 mm apart. The use of structured packing is recommended in view of its high

specific gas capacity and low glycol entrainment characteristic, further reduction in column diameter can be

achieved by using multicyclone trays.

A. Bubble Cap Trays Prior to the late eighties, most glycol contactors used bubble cap trays. They have proved effective and

reliable and have good gas and liquid turndown ratios; the latter being limited primarily by the bypassing of

gas. There is industry experience with columns up to 4.2 m in diameter with bubble cap trays.

The gas turndown for bubble caps is superior to that for valve trays; turndown requirements should be

stated in the specification.

They are suitable for viscous liquid also. For gas flow rates below about 40 % of design, the tray efficiency

may decrease. Blinding off several of the bubble caps has been proven as a cheap and effective way of

overcoming problems at high turndown ratios.

For design purposes most manufacturers use tray efficiencies in the range of 25 to 33 %, although actual

efficiency may differ.


PRG.PR.GAS.0001


Sheet 32 (90) Valve Trays Valve trays have about 10 to 15 % greater capacity than bubble cap trays for a given contactor diameter

and, at design gas flow rates, possibly a little higher efficiency. However, due to their design, valve trays

are more prone to weeping, i.e. liquid seepage through the valves. This is not significant at relatively high

liquid rates, but with the low liquid rates normally encountered in glycol contactors, weeping causes the

column to be inefficient unless the glycol rate is maintained at a high level.

B. Random Packing Random (or dumped) packings, consisting of ceramic saddles or pall rings, are not as well suited to glycol

contactors as structured packings or trays due to the high gas-liquid ratios. They were previously used in

preference to bubble cap trays, in small diameter columns less than 450 mm diameter due to easier

installation and lower cost. For further information about turndown, please refer to Supplier data.

C. Structured Packing At low liquid loads such as encountered in glycol contactors, structured packings are superior to random

packing because of their higher specific area and better mass transfer efficiency.

The gas handling capacity of structured packings is about 150 % to 190 % greater than that of bubble cap

trays, which allows smaller diameters and thus cheaper contactors.

A gas turndown ratio of 10 to 1 can be achieved with structured packing, and the glycol losses due to carry-

over of liquid from the contactor are extremely low. The latter can be explained by the liquid film formed on

packing, which is not as easily entrained as the liquid from a droplet bed on a tray.

Structured packings can also be attractive for revamping existing columns in order to increase the gas

handling capacity, to reduce the glycol carry-over from the contactor, or to improve the dew point

suppression capability.

The recommended minimum liquid superficial velocity based on contactor cross-sectional area for

structured packing is 0.5 mm/s to ensure complete wetting of the packing surface area.

Structured packings and their liquid distributors are more sensitive to liquid turndown (please refer to

Supplier data).

Packing, packing supports, hold-down grids and liquid distributor should be designed / verified by a single

entity.

D. Multicyclone Trays Contacting multicyclone trays are a recent development that have been successfully field tested. Vanes are

used to impart a rotation to the gas which forces the liquid droplets to the wall of the tube where they are

collected.


PRG.PR.GAS.0001


Sheet 33 (90) The gas handling capacity of multicyclone trays is of the order of four times that of bubble cap trays. At gas

flows as low as about 30 % of design, contacting occurs with co-current upward flow of glycol and gas in

the multicyclones. A gas turndown to 20 % is achievable in combination with a higher unit circulation rate.

At the lowest gas flows contacting occurs with counter-current (downward) glycol flow. At maximum

capacity glycol losses are extremely low, similar to structured packing.

Multicyclone trays are more expensive than structured packing for the same capacity. However, for typical

operating conditions and capacities of about 5 million m3(st)/day or more, the advantage consists of a

substantial cost savings for the column shell.

• Column Diameter The column diameter is governed by the gas load in the contacting section and is not affected by the glycol

circulation rate.

The design should be based on the operation mode under the severest conditions with the highest value of

the volumetric load factor Q*, defined by:

gl

ggQQ

ρρρ−

=* ; [m3/s] Eq. 1

where ρ

l is the density of the rich glycol leaving the contactor [kg/m3]

ρg is the density of the gas entering into contactor [kg/m3]

Qg is the inlet gas volumetric flow rate [m3/s]

Having identified the most severe loading from the highest value of Q*, it is then necessary to add a margin

to give the value on which the design shall be based. This value, Q*max, should include margins for

inaccuracies in basic data, for operational flexibility.

The column inside diameter may be calculated from:

max

*max4

πλQD = ; [m] Eq. 2

in which λmax is the maximum allowable gas load factor.

A λmax of 0.055 m/s should be used for bubble cap trays at 0.6 m spacing. For smaller tray spacings (TS)

the capacity decreases as: 33.0

max 60.0055.0 ⎟

⎠⎞

⎜⎝⎛=

TSλ ; [m/s] Eq. 3


PRG.PR.GAS.0001


Sheet 34 (90) With greater tray spacings only a marginal improvement is achieved.

λmax is higher for structured packings and, depending on the type selected, the column diameter required is

a factor of 1.4 to 1.25 smaller than that required for bubble cap trays.

This is a simplified calculation method and final diameter shall be confirmed by trays / structured packing

Manufacturer.

A- TRAYS NUMBER

The number of actual trays required is determined by the number of theoretical trays divided by the tray

efficiency. The height of the contacting section follows from the actual number of trays and the tray spacing.

An adequate space shall be taken into account for demister, distributor, chimney tray,…

B- PACKING HEIGHT

For structured packing the packing height is determined by the number of theoretical trays required for the

process duty and the height of transfer unit given by Vendor, Supplier or Literature. Structured packing

consists of prefabricated elements. The calculated packing height should be rounded up to a multiple of this

height and the total packing height should not exceed 6100 mm or 10 times the column diameter whichever

is smaller without redistribution of glycol in the tower.

• Liquid Distributor A liquid distributor is required when packing or multicyclone are used. It consists of a number of liquid drip

pipes and vapour risers evenly distributed over the column cross-sectional area.

• Pressure Drop The pressure drop over a glycol contactor is the sum of pressure drops over the internals:

- inlet and outlet nozzles;

- demister;

- separation cyclones (if any);

- chimney tray;

- contacting section;

- liquid distributor.

Contactor pressure drop shall take into account the overall system and should not exceed 0.5 bar. The

following equations can be used for the calculation:

Pressure drop over chimney tray (accurate figures should be obtained from tray Manufacturers):

32 10*2 −=Δ ggvP ρ ; [kPa] Eq. 4


PRG.PR.GAS.0001


Sheet 35 (90)

Pressure drop over bubble cap trays:

ΔP=0.01 bar/tray is typical. Accurate figures should be obtained from tray manufacturers.

For pressure drop over structured packing refer to Manufacturers data.

Pressure drop over the liquid distributor: 32 10*2 −=Δ ggvP ρ ; [kPa] Eq. 5

Actual gas velocity should be calculated through chimney tray and liquid distributor.

4.1.4.4 Glycol Flash Vessel

The glycol flash vessel is used to remove gaseous hydrocarbons that have been absorbed or entrained

with the glycol. It also provides to separate any liquid hydrocarbons from the glycol to prevent them from

entering the reboiler and causing fouling, foaming and flooding.

Both sulphur compounds and carbon dioxide are very soluble in water/glycol mixtures and react to some

degree with glycols. Degassing in the flash vessel before the still column reduces their concentration and

reduces high temperature corrosion. Degassing is more efficient if the rich glycol is first pre-heated in the

top of the still column and in the glycol/glycol exchanger. Pre-heating, to about 60 ÷ 70°C, also reduces

glycol viscosity. However, increased temperatures increase the solubility of liquid hydrocarbons in the

glycol. The pressure in the flash separator shall be sufficient to permit the exist glycol stream to flow

through all downstream equipment, i.e. the heat exchangers and the filters.

The general requirement for glycol vessel pressure is a maximum pressure of 15 % of the contactor

operating pressure. Thus, for 70 bar contactor pressure the flash vessel should operate at a pressure lower

than 10 bar. Flash gas may be routed to flare or to other Plant destination. In addition a blanket gas

connection should be provided to ensure sufficient operating pressure in the glycol flash vessel

It may be appropriate to design the piping and equipment upstream of the flash vessel for the design

pressure of the contactor.

The glycol flash vessel rich glycol LCV should be installed as close as possible to the still feed nozzle to

minimise vaporisation.

The vessel should normally be horizontal and sized for a residence time of 20 minutes. Since liquid

capacity is limiting and gas rates are low, it should usually be designed to operate between about 60% to

80 % full.

In order to separate liquid hydrocarbons from glycol, a bucket or trough and weir design is recommended

due to the simplicity of the controls for the small density difference between the collected hydrocarbons and

the glycol (for details refer to PRG.PR.VES.0001.


PRG.PR.GAS.0001


Sheet 36 (90)

4.1.4.5 Regenerator and Reboiler

The glycol regenerator includes a reboiler to supply heat for the glycol regeneration system and it is sized

for the total heat demand. This is governed primarily by the total glycol circulation rate and the quantity of

water removed, and secondly by the efficiency of heat exchange and system losses. Heat is required for

vaporising the water to regenerate the glycol, for sensible heat lost to the treated gas stream and for

system heat losses.

Data on typical onshore TEG regenerators are given in the following table.

Rating [kW]

23 51 110 150 220 290 370 440 590

Glyol rate [m3/hr]

0.15 0.32 0.68 0.95 1.4 1.9 2.4 2.8 3.8

Reboiler dia & length

[m]

0.4x3.0 0.5x2.7 0.6x3.0 0.76x3.0 0.86x4.0 0.86x4.9 0.92x5.8 1.07x6.1 1.14x6.6

Storage dia & length

[m]

Integral Integral 0.5x3.0 0.6x3.0 0.6x4.0 0.6x4.9 0.76x5.8 0.76x6.1 0.91x6.6

Firebox dia & length

[m]

0.1x1.2 0.15x1.5 0.2x2.7 0.25x2.6 0.3x3.4 0.3x4.3 0.3x5.2 0.4x5.4 0.5x5.8

Still dia & length

[m]

0.15x2.0 0.2x2.1 0.25x2.4 0.3x2.4 0.4x3.0 0.45x3.0 0.45x3.7 0.5x3.7 0.6x3.7

Skid size [m]

1.2x3.7 1.5x3.6 1.7x3.7 1.7x3.7 1.7x4.6 1.7x5.8 2.0x6.7 2.1x7.0 2.3x7.6

Shipping weight [tonnes]

64 107 164 220 310 410 540 640 850

Operating weight [tonnes]

83 144 251 350 490 640 880 1020 1370

Glycol volume [m3]

0.17 0.33 0.80 1.2 1.7 2.1 3.1 3.9 4.7

Table 4 – Data on Typical Onshore TEG Regenerators

• Reboiler The reboiler should have a spill-over column or a weir to prevent the heating coils from becoming exposed.

The spill-over column may be packed to serve as a stripping gas contact column. A separate stripping

column is, however, recommended if stripping gas is required. The reboiler bundle should be easily

removable.


PRG.PR.GAS.0001


Sheet 37 (90) HEAT SOURCES

Alternative heat sources for the glycol regenerator are:

- direct gas fired;

- hot oil/steam;

- electricity;

- turbine or engine exhaust;

- furnace flue gas.

Waste heat recovery, e.g. from engine or turbine exhaust with a heating fluid system, is most common in

offshore oil applications and should in all cases be considered as the preferred option for environmental

reasons. Where this is not possible or reasonably practicable, electrical heating is preferred to direct fired

heating for safety.

a) Direct gas fired

Direct fired heaters are most common in onshore applications due to the lower cost. The source of

permanent ignition shall always be installed in a non-hazardous area and fired heaters should be located

as far as practicable away from a hazardous area.

The minimum distance between a fired heater and a process equipment should be 30 m. They are not as

inherently safe as waste heat recovery (except when hot oil is used) or electric heating units and need

additional detection/protection measures. In common with all detection/protection systems, they require

maintenance and adherence to procedures to ensure they work satisfactorily.

b) Hot oil/steam

In some location, such as offshore platform, indirect heating with oil or steam is required by fire code and

prudent practice. A steam condensate trap and strainer with block valves and a bypass should be provided

to drain the steam condensate. The reboiler should be sized as a heat exchanger using the U values.

c) Electricity

A minimum of three heating coils should be used. Over-temperature protection of the heater elements

should be provided by means of at least two thermocouple elements clamped or welded to the heater

sheath, located in an area of highest anticipated sheath temperature. Solid state proportional current

control on part of the load is preferred to on-off control.

d) Turbine or engine exhaust

The use of exhaust gases form gas turbines and engines as the heating medium achieves substantial

energy savings.

e) Furnace flue gas

For onshore locations, all flash gas and condensate may be incinerated in a furnace and the flue gas used

as a reboiler heat source. This may be the most favourable alternative when it is necessary to dispose of all

waste hydrocarbon streams.


PRG.PR.GAS.0001


Sheet 38 (90)

It is generally environmentally favourable to maximise the lean glycol concentration by using high reboiler

temperatures since this will minimise the circulation rate or the volume of stripping gas required.

HEAT DUTY

The following maximum flux rates should not be exceeded at normal operating conditions:

Electric 12.5 kW/m2

Direct fired 19 kW/m2

Steam 24 kW/m2

Hot oil 24 kW/m2

For an example refer to Appendix II.

The reboiler should typically be sized in compliance with PRG.PR.HEB.0001.

• Still Column The column shall be located on top of the reboiler with a flanged connection.

A direct acting PSV set at the design pressure of the regenerator should be installed on the vapour line

between the still column and overhead condenser. The vapour line should be able to withstand full vacuum.

Trays, structured packing and random packing may be used in still columns. Random packing is

recommended in case of the small column size.

With the larger surface areas recommended on the lean/rich glycol heat exchangers, some still feed

vaporisation will occur. Feed piping to the still column should be designed for this two-phase flow to prevent

surging which could upset the still operation, possibly causing flooding and glycol carry-over.


PRG.PR.GAS.0001


Sheet 39 (90) DESIGN METHODS

Column design for random packings, such as pall rings, is typically based on curves in Fig. 9.

Fig. 9 – Pressure Drop and Flooding Correlation

These curves give the generalised pressure drop correlation for packed column design.

Packed columns are usually designed for 60 to 85 % of the flood point. However, for glycol units, care

should be exercised in determining the appropriate mass flow rates, ml and mg. Due to the unsteady flows

encountered in glycol units together with potential for overloads at start-up, still columns are usually

designed at the lower end of the range, or about 60 % of the flood point. Columns designed in this manner

are consistent with the sizes recommended by Manufacturers for onshore applications, see

Table 5.


PRG.PR.GAS.0001


Sheet 40 (90) Since regenerators usually operate below the design rate, this conservative design will result in a low

velocity and a reduction of column efficiency. The wide difference between the boiling points of glycol and

water makes separation easy even with a relatively short column, with a minimum of reflux and with

reduced packing efficiencies.

PACKING TYPES

Table 5 gives recommended pall ring sizes and associated data for a range of still column diameters.

Column Diameter

[mm]

Recommended pall ring size

[mm]

Packing Factor

[m-1]

Density

[kg/m3]

HETP

[m]

<250 16 230 593 0.30 to 0.45

<300 25 157 480 0.38 to 0.53

<750 38 92 415 0.45 to 0.75

>750 51 66 385 0.6 to 0.9

Table 5 – Pall Ring Data for Still Column

COLUMN DIAMETER

Fig. 9 can be used to determine the allowable mass flowrate per unit area, G.

The following equation can be used to determine the required diameter of packing: 5.04

⎥⎦

⎤⎢⎣

⎡=

GFFm

D g

π; [m] Eq. 6

where: mg = gas mass flow rate [kg/s]

G = allowable flow rate per unit area [kg/(s.m2)]

D = internal diameter of packed column [m]

FF = fraction of flood. Take as 0.6.

The size of the still column is pre-determined by most manufacturers of packaged systems to match the

glycol reconcentration capacity of the reboiler. A still column cross-sectional area of typically 0.55 x 10-3 m2

should be supplied for every kW of reboiler heat duty.


PRG.PR.GAS.0001


Sheet 41 (90) COLUMN HEIGHT

The large difference between the boiling points of water (100°C) and TEG (288°C) allows a sharp

separation to be accomplished in the still with a relatively short column and with a minimum reflux.

Fig. 10 shows a typical McCabe-Thiele diagram for the reboiler and still column. Due to the wide difference

between the equilibrium line and the operating line, three theoretical trays are sufficient to effect the

separation.

Fig. 10 - McCabe - Thiele diagram for glycol reboiler and still column

Since the reboiler and condenser are each one theoretical stage, only one stage of packing is required.

The height of packing for a theoretical tray (HETP) ranges from 0.3 to 0.9 m for operation in normal loading

ranges, although it can be much higher with low loading or poor liquid distribution. A total of 1.8 m of

packing is recommended, 0.6 m below the feed point and 1.2 m above. Although this is effectively two

stages, the cost of the additional packing is small and provides a safety margin. A stage can be needed

above or below the feed point, depending on extremes of rich glycol water content and feed temperature.


PRG.PR.GAS.0001


Sheet 42 (90) Poor packing performance is also expected above the feed point because of low liquid loading and the

extra packing height helps to minimise glycol losses.

Random packing requires a simple liquid distributor which should be supplied by the same Manufacturer as

that of the packing.

• Reflux Reflux is provided at the top of the still column to effect rectification of the vapours and to minimise glycol

losses. This reflux is normally supplied by using the rich glycol stream circulating through a condensing coil

inserted in the top of the column. Cooling water, an air-cooled finned section at the top of the column, or an

external water source (such as de-mineralised water or steam condensate) could alternatively be used.

The rich glycol stream is the preferred method for cost and simplicity of operation and energy efficiency. By

not using the rich glycol stream as the condenser coolant the sensible heat duty of the reboiler is increased.

The advantage of increased reflux ratios is to reduce the number of theoretical trays required for a given

level of separation. Fig. 10 also shows the effect of reflux on the still column height. The slope L/V of the

operating line is termed the "internal reflux ratio", where "L" and "V" are the liquid and vapour phase rates,

respectively. The fraction or percentage of the vapour which is reflux, "R", is termed the "external reflux

ratio". L/V and R are related by the equation:

RR

VL

+=

1 Eq. 7

The figure shows that increasing the external reflux ratio from 15 to 50 %, the number of theoretical stages

required decreases only slightly. Only minimal amounts of reflux are therefore required for glycol still

columns.

Fig. 11 shows the minimum reflux rate required to control glycol losses as a function of feed temperature.

The slope increases with the feed temperature due to the increasing amount of glycol in the overhead

vapours. For a still column with a large number of theoretical trays, the reflux rate shown would be

adequate.


PRG.PR.GAS.0001


Sheet 43 (90)

Fig. 11 – Minimum Reflux Required to Control TEG Losses

When the maximum still feed temperature is 165°C and lower, the recommended design external reflux

ratio is 15 %. As a example, for a 35°C inlet gas temperature and a UCR of 25 litres/kg, the temperature of

the combined stream after the reflux condenser will be about 40°C for 15 % reflux and 50°C for 50 % reflux.

The temperature of the vapours leaving the reflux condenser will be between 93 and 100°C depending on

the amount of stripping gas and vaporised hydrocarbons in the vapours. The presence of gas lowers the

partial pressure of the water vapour to less than atmospheric pressure thereby lowering the boiling point of

the water. Vapour temperatures above 100°C indicate that the vapours contain glycol and that additional

reflux should be provided to reduce the glycol losses.

Since the difference between the condensing and feed temperatures is large, reflux may be effectively

controlled by controlling the temperature at a point halfway between the feed and the top of the packing

above the feed point (see Fig. 1). By adjusting the bypass to the reflux coil, the amount of reflux can be

easily and accurately controlled; 10 % of the total glycol flow to the coils is nominally sufficient, with 20 %

recommended for design. If the temperature at the control point is between 110 and 125°C, then the

minimum amount of reflux is assured.


PRG.PR.GAS.0001


Sheet 44 (90)

• Reboiler The following method may be used to size indirectly heated reboiler heat exchange bundles.

1) Calculate the MTD assuming a constant reboiler temperature, normally between

190°C and 204°C for calculating both lower and higher temperature differences between the

heating medium and the glycol.

2) Use a U-value of 340 W/m2.K for hot oil or 425 W/m2.K for steam to calculate the required

surface area. The outside film coefficient is controlling.

3) Table 6 indicates the surface area per length of bundle with 19 mm tubes.

Diameter

[mm]

Surface Area per

length of bundle

[m2/m]

300 4.8

350 6.0

400 7.7

450 10.3

500 13.2

600 19.1

Table 6 – Surface Areas – Steam or Hot Oil Heated Bundles

For hot oil tubes, the tube side velocity shall be a minimum of 1.2 m/s.

4) The shell diameter should be approximately 350 to 450 mm larger than the tube bundle to

provide adequate vapour disengagement area.

5) The reboiler should be designed for a minimum internal pressure of 0.1 barg of or full of water,

whichever is greater.

For details refer also to PRG.PR.HEB.0001

4.1.4.6 Surge Drum

The surge drum should be sized to provide the following:

- handle start up, normal operation and shut down fluctuations due to drain-down of TEG from the

contactor.

- a retention time not less than 20 minutes between low and high levels, based on the design circulation

rate;

- a reasonable length of time between glycol additions;


PRG.PR.GAS.0001


Sheet 45 (90) - sufficient volume to accept the glycol drained from the reboiler to allow repair or inspection of the heating

coil.

In case no stripping gas is provided, the surge drum could be conveniently vented to the reboiler but a

small amount (typically 0.4 m3/h) of nitrogen or dry fuel gas purge is needed to prevent water vapour from

the reboiler flowing through the vent line and being absorbed by the glycol in the surge drum. If it is not

located directly below the reboiler, it should be provided with a separate purge gas supply.

Provisions should be made for:

- make-up of the glycol inventory;

- batch addition of chemicals to the glycol surge drums, e.g. for pH control, corrosion inhibition, etc.

In addition, the glycol surge drum elevation shall always supply adequate liquid head to the glycol

circulation pump.

4.1.4.7 Heat Exchangers

For general design details refer to PRG.PR.HEB.0001.

Heat exchangers in glycol dehydration systems have low overall heat transfer coefficient (U) values

because glycol is a poor heat transfer fluid. Fouling from glycol contaminants and degradation products

may also be severe. Table 7 gives the range of values for the exchangers discussed herein.

Recommended

Fouling Factors [m2K/W] Type of

Exchanger

Range of Uvalues

[W/m2K] Shell Tube Overall U [W/m2K]

Glycol-Glycol (double pipe type)

Finned Bare

45 to 57 110 to 140

0.0004 0.0004

0.0004 0.0004

50 125

Reflux Coil

110 to 230

0.0002

0.0004

170

Reboiler

Steam Hot Oil

400 to 510340 to 400

0.0004 0.0004

0.0002 0.0002

425 340

(double pipe type) Gas-Glycol

Finned Bare

51 to 57 170 to 200

0.0004 0.0004

0.0002 0.0002

50 180

Table 7 – Typical Values for Heat Exchangers TEG Service


PRG.PR.GAS.0001


Sheet 46 (90)

• Glycol-Glycol Exchangers The recommended design criterion for lean-rich glycol heat exchangers is to cool the lean glycol to a

maximum temperature of 90°C. As shown in Fig. 1, two heat exchangers may be used, with the rich glycol

being heated to about 70°C before the glycol flash vessel, then heated to between 150°C and 165°C before

feeding the still column. The choice of temperatures then becomes an economic decision based on the

availability and cost of process heat and the cost of larger glycol/glycol exchangers. The duty of the

glycol/glycol exchanger upstream of the glycol flash vessel will be affected by solution gas, but this will be

typically less than 4 % assuming 50 m3(st)/m3 solution gas and a UCR of 25 litres/kg. The lean glycol

should flow through the shell side of the heat exchangers where the pressure drop is small.

Double pipe or hair pin type, with bare or finned tubes, or plate-type heat exchangers may be used. The

latter are increasingly used, especially for offshore or large systems, because they are more compact,

lighter, cheaper, less susceptible to fouling and easier to clean. A new type of exchanger named

Compablock® are now available in the market and its application needs to be deeply analyzed with

Supplier due to sensitivity to fouling. Some incidents of gasket leakage in plate-type units have been traced

to carry-over of hydrocarbon condensate (due to poor system design) and flashing in the heat exchanger. It

should be recognised that gasket leakage also occurs due to high pressure shock loads seen during gas

blow-by.

• Lean Glycol Cooler A lean glycol cooler is required so that the lean glycol entering the top of the contactor is cooled to 3 ÷ 6°C

higher than gas temperature entering the contactor. The lean glycol may be cooled by either an air-cooled

heat exchanger, a water-cooled heat exchanger or a lean glycol-gas heat exchanger. Although air-cooled

glycol coolers risk under-cooling the lean glycol they are recommended since control of the glycol

temperature is then independent of the gas flow. This provides greater operational flexibility, e.g. during

start-up or gas turndown, and avoids the risk of excessive contactor temperatures.

Failure to cool the glycol makes the top tray act as a heat exchanger. The temperature of the glycol on this

tray is higher, which increases the partial pressure of the water vapour and thus reduces drying efficiency.

4.1.4.8 Condensed Overheads Separator

As shown in Fig. 1, a condenser and three-phase separator should be installed in the vapour line from the

regenerator still column. The vapour and contaminated water are waste streams, hydrocarbon emissions or

flaring/incineration are reduced by the amount of produced condensate. The 3-phase separator can be


PRG.PR.GAS.0001


Sheet 47 (90) similar in design to the glycol flash vessel. Similarly to the overhead condenser, pressure losses should be

minimised. Further processing of the outlet streams should also be considered with regard to

environmental issues.

4.1.4.9 Filters

The solid content in the glycol should be kept below an acceptable value to prevent pump wear, plugging of

heat exchangers, foaming, fouling of contactor trays and still packing, cell corrosion (where the solids settle

on metal surfaces), and hot spots on fire tubes.

Filters should be located in a common area in order to limit areas subject to spillage/pollution. They should

be designed for rapid, simple and safe filter element replacement. Space around the filters should ensure

accessibility for easy maintenance and the handling of fouled filter elements. Filter elements shorter than

0.5 m are suggested to avoid crack formation by expansion. The high viscosity of glycol at low

temperatures should be taken into account in the design of the glycol filters. The design should be such

that no gas can be trapped in the filter cover.

A quick-closure lid with pressure safety device should be used. The lid should be easily removable by

means of a rotating davit or a hinge with counterweight.

Block, vent and drain valves should be provided for each filter. Vent and drain connections should be large

enough to allow water flushing before opening for cleaning and maintenance.

The following steps should be taken if the feed gas contains mercury:

- replaceable filter elements should be non-metallic to reduce the problem of disposal in case they become

contaminated;

- special provisions should be made for storage and disposal of used filter elements;

- the possibility of mercury accumulation should be borne in mind for all connections to the filter. Drainage

points are preferred to be vertical. In addition, since mercury migrates through gaskets, suitable drip pans

or pits should be constructed under the filters with a low point in which the mercury can be collected and

sucked up with a vacuum truck.

A) PARTICLE FILTERS

Sock or pleated paper cartridge type glycol filters should be used to remove 95 % of solid impurities > 5 μm

in size before they cause fouling, foaming or plugging. Two full flow filters with change-over valves and no

by-pass lines should be installed in parallel to permit continuous operation during change-out. The filters

are installed in the rich glycol line downstream of the glycol-flash vessel. In addition a single full flow filter

may be installed downstream of the glycol pump to intercept particles that may originate in the reboiler and

eliminate the need for a specific filter upstream of any liquid distributor in the contactor.

Frequent filter changes may be needed during start-up or when neutralisers are added to the system to

control the glycol pH. 25 μm cartridges can be used for initial start-up, then changed to 5 μm cartridges.


PRG.PR.GAS.0001


Sheet 48 (90) The filters should be depth type filter elements, since these have a longer service life and greater efficiency

than barrier filters. If the glycol is contaminated with condensate, this will dissolve the impregnating agent,

which reduces the life of the surface filters. The filters should have a holding capacity of at least 20 kg, but

preferably 50 kg. Alternatively, two filters in series may be specified, the first a cleanable filter down to 50

μm followed by a 5 μm filter. The coarse filter will prolong the life of the fine filter, possibly improving

lifecycle cost.

The maximum pressure drop across the filter should be limited to 170 kPa. The filter elements should be

designed for a pressure difference of at least 2 bar. The flow through the filter should not exceed 44

litre/min/m2 based on the external area of the filter elements. Each filter shall be sized for 110% of the

design flow, in compliance with the Glycol Circulation Pumps overdesign margin.

B) ACTIVATED CARBON FILTERS

An activated carbon filter can effectively remove most foam promoting compounds such as well-treating

chemicals, compressor oils and other troublesome organic impurities in the glycol. It should be installed

downstream of the particle filters in the rich glycol line. Sidestream filtration with not less than 10 % - 20%

flow can be used for higher glycol flow rates. For low glycol flowrate it could be also foreseen a full flow

carbon filter. This flowrate should be verifiable during normal system operation. Sidestream filtration may

be achieved with a three-way control valve equipped with a mechanical stop for the design flow rate.

Only one carbon filter with block valves and a bypass should be installed, since it will not harm the glycol

system to take the filter out of service to change the elements. Carbon filters are usually sized to give a

flowrate of 2.5 to 5.0 m3/h per m2 of filter cross sectional area.

The method for determining the need to change the activated carbon filters differs from that of particle

filters. Due to the method of adsorption in the carbon elements, the differential pressure will remain

constant even though the filters are no longer active. The elements should thus be changed when the

clarity of the glycol deteriorates or when the glycol analysis indicates a high hydrocarbon content.

If the feed gas contains mercury, it may also be necessary to install a sulphur-impregnated activated

carbon filter in the vapour outlet line downstream of the condensed overheads separator.


PRG.PR.GAS.0001


Sheet 49 (90)

4.1.4.10 Glycol Circulation Pumps

The glycol recirculation pumps, which represent the only moving part in the entire unit, return the low

pressure lean glycol to the high pressure contactor.

Depending on Plant operating philosophy, Glycol pumps could be classified as essential duty and

continuous operation.

Glycol circulation pumps are usually reciprocating type. The pumps shall be sized to provide a minimum of

10% excess capacity because the circulation rate is a key parameter to ensure the unit performances. Two

glycol pumps should be provided in parallel: one running and one standby.

A start-up strainer should be installed in the glycol line upstream from each pump. The strainer should be

easily removable for cleaning.

For other details of pump design refer to PRG.PR.MAC.0001.

4.1.4.11 Glycol StorageTank

Glycol storage tank is provided for the make-up of glycol losses in the circuit. It consists of an atmospheric

tank whose pressure is maintained by means of a inert gas (e.g. nitrogen) blanketing system that prevents

glycol from oxidation due to possible air infiltration. Off gas is routed to safe location or flare.

Make-up glycol is filtered and then pumped into glycol surge drum by using reciprocating or rotative pumps.

Such operation is discontinuous and locally controlled by operator. A typical design of glycol storage

system is shown in Fig. 12.

N PC

At safe location

Truck unloading connection

to TEG surge drum

Fig. 12 – TEG storage process flow diagram


PRG.PR.GAS.0001


Sheet 50 (90)

4.1.4.12 Glycol Sump Vessel

A vessel is provided in order to collect the drains of glycol unit for reprocessing or disposal. Drainages are

usually gravity flow lines taking from the bottom of the equipment, so glycol sump is located underground.

Operating pressure of glycol sump is maintained at about atmospheric value by means of a pressure

control valve and a inert gas blanketing system, e.g. nitrogen, that prevents glycol from oxidation. Off gas is

routed to flare or safe location. Such system could be used also to pressurize and therefore empty the

vessel. Alternatively, sump can be emptied by using self-priming or submerged pumps. When glycol is

recovered from sump and then reprocessed, it shall be filtered before recycling into the circuit; otherwise,

contaminated glycol is loaded into a truck and sent for disposal.

Pressure relief valve installed on glycol sump, shall be sized in order to protect itself against, as minimum,

the following overpressure scenarios: pressure control valve to flare or safe location blocked outlet,

pressure control valve inlet blow-by and inlet blow-by from high pressure upstream equipment, due to

failure during drainage operation. A typical design of glycol sump is shown in Fig. 13.

N PC

grade grade

TEG sewer underground

header

Vacuum tanker connection

TEG make-up

flare

M

Fig. 13 - TEG sump process flow diagram


PRG.PR.GAS.0001


Sheet 51 (90)

4.1.4.13 Enhanced Regeneration Equipment Design

As introduced in par. 4.1.2.3, a more detailed description of enhanced regeneration equipment design will

be given in this paragraph.

• COLDFINGER Equipment Application of the Coldfinger process requires an additional pump, with a spare, to recycle glycol from the

Coldfinger collection in the surge drum to the still column feed (Fig. 3). Changes to the following equipment

are also required:

- still column;

- reboiler;

- surge drum.

The loading of the still column and the duty of the reboiler are increased by the recycle stream from the

surge drum. The surge drum needs to be well insulated to maintain a temperature close to that of the

reboiler. It must also accommodate the Coldfinger heat-exchanger bundle and liquid collection trough,

which occupies space that is not available for liquid surge.

• Gas Stripping Equipment Stripping gas cannot be condensed from the still overheads and it also reduces the amount of

hydrocarbons recovered in the condensed overheads separator. "End-of-pipe" facilities, e.g. incinerators,

shall have sufficient capacity for the stripping gas in addition to vapours from the reboiler and glycol flash

vessel.

Normally fuel gas is used as stripping gas. To prevent accumulation and freezing of liquid, there should be

no low points in the stripping gas line to the surge drum. There should be adequate facilities incorporated in

the stripping gas line upstream of the surge drum to prevent liquid from the reboiler entering the stripping

gas line.

A heater may be required upstream of the stripping column to ensure that the stripping gas is dry. The need

and duty of this heater depend on the gas composition and the ambient temperature.

A) GAS RATE

Using counter-current stripping in a packed column, the quantity of stripping gas required to achieve a

given concentration can be reduced by a factor of five or more compared with injecting gas into the reboiler.

Fig. 14 shows the effect of counter-current stripping on glycol concentration.

A 10% overdesign margin should be kept on the minimum amount of stripping gas because the gas flow

rate is a key parameter for the unit performances. A maximum design rate of 40 m3(st)/m3 should not be

exceeded, to prevent the possibility of column flooding.


PRG.PR.GAS.0001


Sheet 52 (90) A measure device should be used for measuring the flow of stripping gas.

Fig. 14 – Glycol Concentration vs. Stripping Gas Rate

B) STRIPPING COLUMN

The stripping column allows the stripping gas to make intimate contact with the lean glycol and it is installed

between the reboiler and the surge drum. The stripping gas thus strips the water remaining in the lean

glycol and is not diluted by the water previously removed in the reboiler.

The size of the column can be calculated as for other packed columns and in compliance with

PRG.PR.VES.0011. However, since the design conditions are always the same, the cross-sectional area of

the stripping column can be found from Fig. 15.


PRG.PR.GAS.0001


Sheet 53 (90)

Fig. 15 – Stripping Column Size

The height of the stripping column is governed by the same variables as the height of other columns; i.e.

the taller the packing, the more theoretical trays available.

Due to the low gas rates involved and the nature of stripping/absorbing, a greater packing height per

theoretical tray is required than in the still column: the values in stripping columns are typically 0.6 to 0.9 m

per theoretical tray.

• Azeotropic Stripping (DRIZO) Equipment The DRIZO process (Fig. 3) requires additional equipment and modifications to the standard ones, as listed

below:

- still column;

- stripping column;

- still overheads condenser and separator;

- glycol flash vessel overheads condenser and separator (optional extra);

- solvent pumps (extra);


PRG.PR.GAS.0001


Sheet 54 (90) - solvent heater (extra).

One simplification is the elimination of activated carbon filters in case BTEX components are present in the

feed gas due to the high affinity between the solvent and the BTEX. BTEX components would flood the

carbon bed making them ineffective in removing degradation products.

The DRIZO process may lead to an approximate doubling of the gas stream in the reboiler and a higher

concentration of BTEXs in the waste water stream.

The still column is similar to the traditional one but allowance is required for the solvent loading. A demister

mat may be installed above the reflux condenser to reduce entrainment losses. This causes an increase in

backpressure, but can probably be accepted in view of the higher glycol concentration.

The stripping column is similar the traditional one but takes account of the different properties and flow

rates.

The Still Overheads Condenser and Separator should be similar in design to those already described. The

quantity of condensed hydrocarbon will, however, be greater due to the recovery of condensate from the

glycol flash vessel and condensation of additional BTEX components due to absorption by the solvent.

Glycol Flash Overheads Condenser and Solvent Recovery Drum may be placed downstream of the glycol

flash vessel vapour outlet to recover C5+ components which reduces solvent losses. The condensed liquid

stream flows to the still column and is added to the solvent extraction process.

Two full-flow solvent pumps are required to overcome the backpressure of the solvent heaters and

stripping column.

A heat exchanger using lean glycol leaving the surge drum heats the solvent downstream of the solvent

pump. This is followed by an electric heater upstream of the stripping column to superheat the solvent to

above 150°C.


PRG.PR.GAS.0001


Sheet 55 (90)

4.1.5 Materials

All materials indicated below are the minimum requirement and are to be evaluated / confirmed during

detailed design considering project peculiarity involving also material specialists.

The contactor shell should be made of carbon steel with a minimum corrosion allowance of 3 mm. A 3 mm

thick AISI 316L stainless steel cladding should be applied below the bottom tray when bubble caps are

used or below the chimney tray when structured packing or multicyclones are used. All internals should be

AISI 316L stainless steel.

Material for the regeneration system where rich glycol is present should be carbon steel with AISI 316L

cladding or solid stainless steel AISI 316L depending on economical evaluation.

Material for regeneration system where lean glycol is present is normally carbon steel with 3 mm corrosion

allowance.


PRG.PR.GAS.0001


Sheet 56 (90)

4.1.6 Operation and Maintenance

This section describes some of the most important operating and maintenance aspects of glycol

dehydration process including generalised start-up and shutdown procedures.

4.1.6.1 Oxidation

Degradation is a natural occurrence and it is accelerated in the presence of sulphur compounds. Oxygen

may enter a system with the inlet gas, through storage tanks and sumps without inert-gas blankets, through

the pump packing glands or via spilled or leaked glycol recovered from the drain base plates. Glycols will

oxidise readily in the presence of oxygen and form corrosive organic acids. Recovered glycol, which is old

or dirty or has been exposed to oxygen, should not be returned to the glycol systems. Oxidation inhibitors

may be used to prevent corrosion if oxygen contamination cannot be avoided. Degradation products

contribute to foaming but they also are major sources of corrosion problems; the answer is effective

filtration of circulating glycol.

4.1.6.2 Ph Control

Solutions in a glycol unit that is not downstream of an amine unit become acidic and corrosive, especially

when the inlet gas contains H2S or CO2. Glycols are very reactive with sulphur compounds. The resultant

materials tend to polymerize and form a product which is very corrosive. Also the pH becomes lower.

The metallic corrosion rate increases rapidly with a decrease in the glycol pH. Organic acids resulting from

the oxidation of glycol and thermal decomposition products or acid gases absorbed from the gas stream

are the most troublesome corrosive compounds. The glycol pH should be regularly checked and kept

between 6.5 and 8.0 by neutralising the acidic compounds with ethanolamines, soda ash or other alkaline

chemicals.

About 100 g of methylethanolamine (MEA) per m3 of solution is usually sufficient to raise the pH from 6.5 to

a safe level of 7.3. Maintaining the pH around 7.3 may, however, require excessive addition of neutraliser.

It is generally better to allow the pH to swing between the control limits. When the glycol pH is extremely

low, the amount of neutraliser required can be determined by laboratory analysis. The pH should not raised

above 8 to 8.5 because the glycol solution will tend to foam and emulsify more easily. An overdose of

neutraliser will also precipitate a blank sludge that will be suspended in the glycol solution. There is a risk of

over-dosing when using MEA, leading to a pH of greater than 10 causing cracking due to stress corrosion.

Frequent filter changes are also required when pH buffers are being added.

If CO2 is present in the gas stream, sodium acetate or another base should be used instead of MEA to

avoid reaction of CO2 with MEA.


PRG.PR.GAS.0001


Sheet 57 (90)

4.1.6.3 Salt Contamination

Salt over carry-over, either as slugs or fine mist, should be prevented by the use of an efficient separator

upstream of the glycol contactor.

Salt deposits on the reboiler fire tube cause hot spots, fire-tube plugging and hence failures.

Salt deposits accelerate equipment corrosion, reduce heat transfer in the reboiler tubes and affect specific

gravity reading when a hydrometer is used to determine glycol-water concentrations. Troublesome salts

are not removed with normal regeneration and accumulate in the glycol circuit.

When it is not possible to remove all the salt water from the gas stream from the feed gas to the Contactor,

the removal of salt from the glycol is necessary. Several methods are available for salt removal from glycol

such as vacuum distillation, electrodialysis or ion-exchange resin bed.

4.1.6.4 Hydrocarbon Contamination

Liquid hydrocarbons, resulting from carry-over with the inlet gas or from condensation in the contactor,

increase glycol foaming, degradation and losses. Carry-over can be prevented by maintaining proper levels

in the inlet separator and by keeping mist mats clean. If hydrocarbons enter into the contactor, they should

be removed in the glycol flash vessel or in the activated carbon filter.

4.1.6.5 Sludge Accumulation

Dust, sand, pipeline scale, reservoir fines, and corrosion products such as iron sulphide and rust are picked

up by the glycol if not removed by the inlet separator. These solids, together with tarry hydrocarbons,

eventually settle out and form an abrasive, sticky, black gum which can erode the glycol pump and other

equipment, plug the contactor trays and the packing in the stripper, and deposit on the fire tubes.

4.1.6.6 Foaming

Foaming may be mechanical or chemical. Mechanical foaming is caused by excessively-high gas flow rates

in the Contactor, while contaminants such as solid particles, salts, corrosion inhibitors, and liquid

hydrocarbon cause chemical foaming. Foaming increases glycol losses and reduces the capacity of the

system. Entrained glycol will carry over the top of the contactor with the dry gas if a stable foam builds up

on the trays. Foaming also causes poor contact between the gas and the glycol solution, which in turn

leads to a poorer dew point depression.

Foaming is best detected by monitoring the pressure drop across the contactor. Erratic readings followed

by a rapid increase in pressure are symptoms of foaming. Chemical foaming can be detected by bubbling

air through a sample of glycol for five minutes and observing the resulting foam height and stability.


PRG.PR.GAS.0001


Sheet 58 (90) The most satisfactory cure for foaming problems is proper care of the glycol solution. The most important

measures to achieve this are effective gas cleaning ahead of the glycol system, a proper filtration of the

circulating solution and by raising the temperature of the gas and the glycol above the dew point of the

condensed hydrocarbon. The use of anti-foaming agents (AF) will not solve the underlying problem. The

use of AF should be regarded as a temporary control until the foam promoters can be determined and

eliminated.

The success of the AF is usually dependent upon when and how it is added. Some AFs, when added after

the foam is generated, act as good inhibitors, but when added before foam generation act as good foam

stabilisers, which makes the problem worse. Most AFs are deactivated within a few hours under high

temperature and pressure conditions and their effectiveness can be dissipated by the heat of the glycol

solution. AFs should generally be added continuously, a drop a time, for best results. The use of a chemical

feed pump will help meter the AF accurately and give better dispersion into the glycol solution. Water-

soluble AFs are sometimes made more effective by diluting them before addition into the system. AFs with

limited solubility should be added via the pump suction to ensure good dispersion in the glycol solution. If

foaming is not a serious problem, the AF may be added in slugs of about 100g when needed. The addition

of too much AF is usually worse than no AF at all. Excessive amounts sharply increase the foaming

problem.

4.1.6.7 Acid gas solubilities and stripping

CO2 and/or H2S, when present in significant quantities, have the following effects:

- they increase the saturation water content of natural gas.

- they readily dissolve in glycol, reducing its pH and promoting corrosion.

- CO2 and H2S react with MEA, an acid neutraliser.

For high CO2 and/or H2S contents, it may be advantageous to employ a stripper upstream of the glycol

flash vessel. This approach can reduce corrosion, the flare SO2 level and the size of the glycol reboiler and

still column.

4.1.6.8 Mercury in Feed gas

The presence of mercury in the feed gas will lead to contamination of the entire glycol system.

Used glycol and filters should be stored in a safe, confined area and disposed of in an environmentally

acceptable manner. There are also consequences for the design of the filters themselves.

The overhead condenser and separator reduces the mercury content of the residual vapour but may not

eliminate the need for an activated carbon filter impregnated with sulphur for this stream.

There is also the possibility of mercury induced stress cracking in small bore pipelines, hence precautions

should be taken in the material selection, especially for instrument connections.


PRG.PR.GAS.0001


Sheet 59 (90)

4.2 Molecular Sieves Dehydration

4.2.1 General

The use of solid desiccant is tipically limited to applications such as high H2S content gases, very low water

dewpoint requirements, simultaneous control of water and hydrocarbon dewpoints, and special cases such

as oxygen containing gases. In processes where cryogenic temperatures are encountered, solid dessicant

dehydration is usually preferred over conventional methanol injection to prevent hydrate and ice formation.

Solid desiccant units are generally more expensive to buy and to operate than glycol units.

Commercial desiccants are summarized in three categories:

• Gels – Alumina or silica gels manufactured and conditioned to have an affinity for water.

• Alumina – A manufactured or natural occurring form of aluminium oxide that is activated by

heating.

• Molecular Sieves – Manufactured or naturally occurring alumino-silicates exhibiting a degree of

selectivity, based on crystalline structure, in the adsorption of natural gas constituents.

In particular Silica Gel is a generic name for a gel manufactured from sulphuric acid and sodium silicate. It

is essentially pure silicon dioxide, SiO2. It is used for gas and liquid dehydration and hydrocarbon recovery

from natural gas. When used for dehydration, silica gel will give outlet dewpoints of approximately -50°C .

Alumina is a hydrated form of alumina oxide (Al2O3). It is used for gas and liquid dehydration and will give

outlet dewpoints of about -68°C. Less heat is required to regenerate alumina and silica gel than for

molecular sieve and the regeneration temperature is lower. Particular attention should be taken when

drying sour gas because Al2O3 will catalyze the H2S + CO2 reaction and form so much COS + H2O that the

process would be unable to dry the gas. Alumina can be a prolific producer of COS.

Molecular Sieves are a class of aluminosilicates. They produce the lowest water dewpoints, and can be

used to simultaneously sweet and dry gases and liquids. Their equilibrium water capacity is much less

dependent on adsorption temperature and relative humidity. They are usually more expensive and the

common crystalline forms used in commercial adsorption are synthetically manufactured materials.

For comparison Fig. 16 presents the important properties of commercial solid dessicants. Fig. 17 shows

static equilibrium capacity vs. relative humidity for various new dessicants.


PRG.PR.GAS.0001


Sheet 60 (90)

Dessicant Shape Bulk density [kg/m3] Particle size Heat capacity

[kJ/kg°k]

Approx, minimum moisture Content of

Effluent Gas [mm/kg]

Activated Alumina Alcoa F200 Beads 770 7x14 Tyler mesh or 3.2 mm / 4.8mm /

6.4mm

1.00 -68°C dew point

Activated Alumina UOP A-201 Beads 735 3-6 mesh or 5-8 mesh

0.92 5-10 ppmv

Mole Sieve Grace – Davison 4A Beads 675-720 4-8 mesh or 8-12 mesh

0.96 0.1 ppmv (-101°C)

Molecular Sieve UOP 4A-DG Extrudate 640-705 3.2 / 1.6 mm pellets 1.00 0.1 ppmv Molecular Sieve Zeochem 4A Beads 720-735 4-8 mesh or 8-12

mesh 1.00 0.1 ppmv

Silica Gel Sorbead® -R Beads 785 5x8 mesh 1.05 -51°C dew point Silica Gel Sorbead® -H Beads 720 5x8 mesh 1.05 -51°C dew point Silica Gel Sorbead® -WS Beads 720 5x8 mesh 1.00 -51°C dew point

Fig. 16 – Typical Dessicant Properties

Fig. 17 – Static Equilibrium Capacity vs. Relative Humidity for Selected Solid Desiccants

The Molecular Sieves activated crystalline material is porous. The pore openings in a given structure are all

exactly the same size and are determined by the molecular structure of the crystal and the size of

molecules present in the crystal. The pores are formed by driving off water of crystallization that is present


PRG.PR.GAS.0001


Sheet 61 (90) during the synthesis process. The exactness of the pore size and distribution has given rise to the name

molecular sieves, which is used almost universally to describe these materials.

Molecular Sieves have the large surface area typical of any solid adsorbent. In addition, however, they

have highly localized polar charges and high adsorptive selectivity for polar and un-saturated compounds.

These localized charges are the reason for the very strong adsorption of polar or polarisable compounds

on molecular sieves. This also results in much higher adsorptive capacities for these materials by

molecular sieves than by other adsorbents, particularly in the lower concentration ranges.

Molecular Sieves in the gas industry vary in pore size from 3-10 Å, and are generally found as the following

types:

• 3A – Potassium variation of sodium aluminosilicate, used for water removal.

• 4A – Sodium aluminosilicate, used for removal of water, CO2, incidental H2S removal.

• 5A – Calcium variation of sodium aluminosilicate, used for water, H2S and light mercaptans

removal

• 13X – Sodium aluminosilicate with X crystal structure, used for water and mercaptan removal.

Table 8 shows that in most industrial applications molecular sieves are used for the removal of water,

hydrogen sulphide, organic sulphides, and carbon dioxide (either singly or in combination) from fluids.

Data included in the table shall be considered as a preliminary indication and Molecular Sieves type and life

time shall be confirmed by a specialized Vendor.

Application Molecular sieves

Industry Type Phase Type Estimated life [years]

Petroleum Super Drying Kerosene/Jet fuel Liquid 4A 4 Alkylation feed Liquid 4A 3 Reformer recycle gas Gas 4A 4 Hydrocracker gas Gas 4A 4 Purifying Sweetening LPG Liquid 13X 2-3 Sweetening recycle gas Gas 4A/5A 2-3 Separation n-Paraffin Gas/Liquid 5A 4 Petrochemical Chemical Super Drying Olefin Cracked gas Gas 3A 2 Finished product Liquid 3A 2 Propylene Liquid 3A 2 Alcohols Liquid 3A 4 Feed to low temperature plants Liquid/Gas 4A 4 Purifying CO2 from Xylenes Liquid 5A 3


PRG.PR.GAS.0001


Sheet 62 (90)

Cyclohexane purification Liquid 13X 3 CO2 from Ethylene Gas 5A 2 Natural Gas Super Drying Pipeline Gas Gas 4A 4 Feed to LNG plants Gas 4A 4 Feed to helium plants Gas 4A 4 Purifying Sweetening natural gas Gas 4A 2-3 Sweetening plus CO2 Gas 4A 2-3 Air Separation Purifying Water and CO2 from air Gas 13X 4 CO2 removal Gas 13X 4 Refrigeration Super Drying Liquid/Gas 4A Not

regenerable General Super Drying Instrument air Gas 4A 4 Waveguide driers Gas 4A 4 Inert gases and rare gases Gas 4A 4 Purifying Ammonia and water

from furnace atmosphere gas Gas 5A 3-4

CO2 from inert gas Gas 5A/13X 3-4

Table 8 – Typical Application of Molecular Sieves

The static equilibrium adsorption capacity for type 4A, type 5A, and type 13X molecular sieves for H2O are

shown in Fig. 18, Fig. 19 and Fig. 20 and Make no allowances for co-adsorption.

Fig. 18 – Adsorption Equilibrium Loading of H2O on 4A Pellets


PRG.PR.GAS.0001


Sheet 63 (90)

Fig. 19 – Equilibrium Adsorption Loading of H2O on 5A

Fig. 20 – Equilibrium Adsorption Loading of H2O on 13X


PRG.PR.GAS.0001


Sheet 64 (90)

As long as the component molecule is small enough to fit through the pore opening, the adsorption of

components on sieve is:

• directly proportional to MW;

• inversely proportional to vapour pressure;

• directly proportional to dipole moment (i.e. polarity).

Adsorption in order of retention is:

1. water (strongest retention)

2. methanol (coadsorbes with water)

3. heavier mercaptans

4. light mercaptans

5. H2S

6. CO2

7. COS (weakest retention)

In general, published isotherms showing loading on sieve are only for that specific component in a carrier

gas and can be significantly different in presence of other contaminants.

In terms of heat of adsorption it can be helpful to refer to the following data: the heat of adsorption of water

on sieve of about 4180 kJ/kg or almost twice its atmospheric latent heat.

CS2 cannot be removed with sieve because its polarity is too low. COS can be removed by some sieves but

it is not strongly adsorbed and would be displaced with RSH’s. CO2 is strongly adsorbed and the presence

of CO2 will decrease COS loadings. Unless the CO2 content is low (< 0.1-0.5%) COS removal will require

large beds, infact COS is non-polar and very weakly adsorbed.

Some specific molecular sieves are used for sour gas drying. They can provide good dryness of natural

gas with minimum COS formation.

Methanol is very polar but not as polar as water. However the presence of methanol will decrease the water

loading. This is true for all sieves except 3A because the pore size is too small. Since methanol is not as

thermally stable as water, there may be methanol degradation during regeneration on certain sieves.

The typical parameter shown in this document should be confirmed with Molecular Sieve Vendor.


PRG.PR.GAS.0001


Sheet 65 (90)

4.2.2 System Description and Process Flow Diagram

A schematic flow diagram of one typical molecular sieve process is shown in the following Fig. 21.

Regeneration gas to flare

Sour gasinlet

Sweet gas out

Regeneration gasRegeneration

heater

Tower 1adsorpt.

Tower 2regener.

Fig. 21 – Schematic Flow Diagram for a Simple Molecular Sieve Adsorptive Process

The continuous process requires two (or more) towers with one (or more) on-line removing water while the

other is being regenerated. Generally a bed is designed to be on-line in adsorption for 8 to 24 hours. Gas

flow during adsorption is typically downflow: this allows higher gas velocities (thus smaller diameter towers)

since bed fluidization is avoided.

When the bed is taken off-line, the water is removed by heating to 230°C÷320°C, depending on the

desiccant used and the performance specification (i.e., 315°C for molecular sieve, with alumina gel and

activated alumina falling in between). The regeneration gas used to heat the bed is usually a slipstream of

dry process gas and it can be sent to flare or reprocessed after it has been cooled and the free water

removed. Any heat source can be used including waste heat from engines and turbines. This is an

important design consideration since heat is often a major operating cost.

Regeneration gas is upflow during the heating period since the flow rate is usually much less than during

dehydration, so velocity is not a problem. In this way, any residual water left on the desiccant will be at the

top of the bed and will not affect the effluent dewpoint when adsorption is resumed. In addition, upflow

heating helps to strip the contaminants from the top of the bed, where they are accumulated, extending

desiccant life. The regeneration cycle continues until H2O has been driven off. Before starting another

dehydration cycle, the hot regenerated bed shall be cooled to 15-20°C higher than the feed gas

temperature, in order to avoid liquids condensation on the bed itself. Regeneration gas flow during the

cooling period may be upflow if the gas is completely free of water, which saves two switching valves per


PRG.PR.GAS.0001


Sheet 66 (90) tower. If the cooling gas contains water, cooling flow should be downflow to avoid preloading of the

desiccant at the bottom of the bed with water.

A more sophisticated process has been developed in order to overcome the difficulties encountered in

flaring a portion of sweetened gas stream which has been used for regeneration. This Closed Cycle

process is shown in Fig. 22.

TC

1 2 3 4

Heater

Cycle Control

TC

Cooler

Separator

Sour Vent

Flashed SolventContactor

Recycle

Wet Gas Inlet

Separator

Filter

Flash Tank

Dry Gas Out

Water Hydrocarbon

Fig. 22 – Closed Cycle Process

Wet gas enters into the unit through a separator and a filter which will remove all liquids and entrained

solids. The wet gas then flows downward through two molecular sieve treating beds and leaves the plant as

dried gas. A portion of the dry gas stream is removed and flows downward through a third bed which has

been regenerated but is still hot. The dried gas removes heat from the bed and flows through a gas-to-gas

exchanger before going through the regeneration heater. After being heated, this gas flows upward through

the bed (bed 4) on regeneration cycle, heating it and removing the adsorbed water. The gas from the bed

then flows through heat exchanger with the dried gas to the tower and then through a cooler. Any

condensed liquids are removed in a separator before the regeneration stream flows into a contactor where

approximately 90% of the H2S, if present, is removed by circulating solvent (i.e. amine). This process

rejects from the gas stream only the acid gas constituents and burns only the amount of gas required to

provide regeneration heat.


PRG.PR.GAS.0001


Sheet 67 (90)

In some cases a portion of the wet gas, spilled upstream the adsorption bed, is heated and sent to the bed

in regeneration mode.

4.2.2.1 Adsorption Mechanism

The mechanisms of adsorption in a molecular sieve bed are relatively complex. In most processes there is

a combination of “sieving” action and physical adsorption. In simplest terms, a molecule must pass through

the pore opening in the sieve before it can be adsorbed on the active centres inside the crystal structure.

In most gas-purification cases water vapour is also present in the impure gas and is removed by the

molecular-sieve adsorbent along with the other impurities. Since water is adsorbed more strongly than any

of the other components, it concentrates initially at the inlet portion of the bed where it displaces the other

impurities which had previously been adsorbed. These desorbed impurities are then re-adsorbed further

down the column, and this impurity adsorption zone moves through the bed in advance of the water

adsorption zone. Fig. 23 shows the four major adsorption zones in a sieve bed designed to remove both

water and sulphur compounds. In zone 1, equilibrium has been established between the water and the

sieve bed. Zone 2 is the water-sulphur exchange zone in which the water is displacing sulphur compounds

on the sieve surface. Zone 3 is the sulphur equilibrium section where the sulphur compounds are desorbed

to the equilibrium capacity of the bed. Zone 4 is the mass transfer section where the sulphur compounds

are transferred from the gas phase to the adsorbed phase. In a bed in which the sulphur zones are allowed

to develop fully, the sweet gas leaving will be at a very, very low water content.

As indicated in Fig. 23, a much smaller bed would be required, for the same adsorption period, if

dehydration alone were desired. In that case a small amount of mercaptan sulphur would be removed with

the water, but, at the water breakthrough point, the sulphur content of the product gas would be the same

as that of the feed. In a similar manner, the presence of any more strongly adsorbed component will affect

capacity and breakthrough point for a given impurity.

Zone 1Water

Equilibrium Section

Zone 2Water- Sulfur

Exchange

Zone 3Sulfur Equilibrium

Section

Zone 4Sulfur

Mass-Transfer Section

Sour, Wet Gas Inlet

Sweet, Dry Gas Outlet

Lenght of Adsorption Bed

ConcentrationH2O

H2S

Fig. 23 – Schematic Representation of the Adsorption Process


PRG.PR.GAS.0001


Sheet 68 (90) Normally before dehydration system a sweetening facility is foreseen. Therefore usually only Zone 1 and

Zone 2 (Water Mass Transfer Zone) are to be taken into account.

4.2.3 Design Variables

A review of the performance of adsorption plants, particularly those encountering some operational

difficulty, has shown that many are processing gas stream of different composition or under different

conditions then were used as a basis for the original design. The greatest problem seems to arise from

inadequate specification, although over-specification also occurs. Here below are outlined those factors

that should be specified in adsorption plants to obtain optimum performance. Obviously many of these

factors are specific for hydrocarbon recovery units, while others apply to straight dehydrators as well.

As a matter of practicability, the adsorber should be designed to operate under the most common

conditions expected, with allowance for the normal variations.

4.2.3.1 Gas Composition

The designer needs a complete gas analysis that includes at least the percentages of methane through

heptanes plus fraction, as well as the molecular weight and specific gravity of that heavy fraction. Also the

composition of the gas “contaminants” such as hydrogen sulphide, carbon dioxide, nitrogen, and other non-

hydrocarbon components is needed. If the feed gas is a high pressure gas condensate it is also desirable

to outline the PVT (pressure-volume-temperature) properties of the gas, particularly the dew point.

The probable water dew point of the gas as it enters the unit should be specified. It is not to be assumed

that the gas is saturated. This, of course, will lead to the highest bed loading, but relative saturation affects

the dynamic performance of a unit.

4.2.3.2 Flow Rate

An adsorption plant can accommodate relatively large velocity changes so long as the frequency is not too

pronounced. Situations are sometimes encountered, particularly with longer cycle dehydration units,

wherein the flow rate falls to a point that efficient regeneration and cooling becomes a problem.

As for composition, it is desirable to specify the nominal flow rate, with estimates of the normal variations

(max and min) and their frequency.

4.2.3.3 Pressure

In most cases a hydrocarbon recovery unit operates most effectively in the pressure range 35-55 barg.

Operating pressure depends on the circuit in which the unit is operating.


PRG.PR.GAS.0001


Sheet 69 (90) When applying specified pressure loss parameters to equipment design it is good practice to allocate up to

70% of the available loss to the column design and the reminder to the interconnecting pipework manifolds,

valves, and ancillary equipment items.

4.2.3.4 Temperature

The proper specification of temperature requires a careful appraisal of the operating conditions if the gas

being processed comes more or less directly from producing wells. Both adsorbent capacity and water

content are fairly sensitive to increases in temperature above 38°C. Gas should never enter a unit above

the temperature to which it could be reduced by means of available cooling media. Cooling is the cheapest

way to dehydrate where gas temperatures are above these ranges. Positive cooling ahead of the tower

also allows positive control of inlet temperatures.

4.2.3.5 Further variables affecting the efficiency of regeneration

The regeneration heating sequence can be broken down into the following component heat requirements:

• applying heat to the molecular sieve its supports, and any protective media employed;

• Heating the ironware, for example, the vessel, pipework and valves;

• Allowing for heat losses;

• Heating and vapourising the adsorbate;

• In the case of liquid-phase treaters it may be necessary to provide heat to remove liquid remaining

in the adsorbers after draining.

The heating step can be sub-divided into two distinct steps, each with particular temperature range.

An initial low temperature range during which desorption of hydrocarbons and bulk of the impurities takes

place and the second stage during which the final design regeneration temperature is attained.

4.2.3.6 Utilities Availability and Local Conditions

The utilities available and their reliability are significant parameters in optimum design. The following should

be outlined for the designer:

• availability of electricity with specification of voltage, amperage, phase, KWH and reliability;

• availability of water with specification of quality and quantity;

• design wet and dry bulb of air;

• amount of supervision and maintenance normally available and / or preferred;

• altitude;

• availability of “sweet” natural gas suitable for use as fuel.


PRG.PR.GAS.0001


Sheet 70 (90)

4.2.4 Equipment Design

This section recommends the minimum requirements for the design, material selection and fabrication of

molecular sieves gas dehydration systems.

The equipment described in this section should be equipped with piping, instruments, valve actuators, level

shutdown devices and other accessories to make a complete and functional system in line with the rest of

the Plant. It should be understood that sample connections, vents, low point drains and minor material

items required to make the system functional are part of the assembly.

4.2.4.1 Scrubber

The presence of contaminants in the feed gas strongly reduces the adsorption capability of solid desiccant.

Therefore, an adequate scrubber at the inlet of the dehydration bed is an important element to ensure as

long life as possible of the bed.

Some Vendors provide special adsorbent materials at the inlet of the bed, which prevent contamination of

liquids (e.g. H2O and gasoline). These adsorbents can represent up to 15% of the bed, however they

should be considered as a complement and not as a substitute of the inlet scrubber.


PRG.PR.GAS.0001


Sheet 71 (90)

4.2.4.2 Gas Dehydrator

A detailed representation of adsorber tower is shown in Fig. 24.

2:1 SEMI ELLIPSOIDAL HEAD

M1

N1

J3

M2

INLET COLLECTOR

FLOATING MESH SCREEN

150 DEEP HOLD DOWN LAYER, 12 DIA. CERAMIC BALLS

MOLECULAR SIEVE BED.

J2

3 DIA. CERAMIC BALLS, 75 DEEP



MESH RETAINER SCREEN AND BED SUPPORT GRATING / BEAMS2:1 SEMI ELLIPSOIDAL HEAD

OUTLET DISTRIBUTOR -STRAINER

N3

J1

N4

N2

J4

N5

Fig. 24 – Adsorber tower

The inlet and outlet distributors should be designed so that the process and regeneration gases do not

impinge directly on the bed, in order to ensure as uniform as possible flow through the bed and to avoid

channelling. The top and bottom of the bed should contain two or three layers of inert support balls in

graduated sizes. The support should be designed to carry the weight of the desiccant and the inert balls,

plus 1 ÷ 2 bar pressure differential. The anular space between the bed support and the vessel wall should

be filled with high temperature packing to avoid bypassing.

The first step is to determine the bed diameter, which depends on the superficial velocity. Too large

diameter will require a high regeneration gas rate to prevent channelling. Too small diameter will cause too

high pressure drop and will damage the sieve.


PRG.PR.GAS.0001


Sheet 72 (90) As a general rule, the diameter of the tower should be such that the adsorption gas velocities are within the

following ranges:

Adsorption Pressure Superficial Gas Velocity 69 bar 7.6 to 12.2 m/min

34.5 bar 10.7 to 16.8 m/min

The pressure drop is determined by a modified Ergun equation, which relates pressure drop to superficial

velocity as follows:

2VCVBLP ρμ +=

Δ Eq. 8

Constants for the previous equation are detailed in the following table:

Particle Type B C

3.2 mm bead (4x8 mesh) 0.0693 3.75 x 10-7

3.2 mm extrudate 0.0893 5.23 x 10-7

1.6 mm bead (8x12 mesh) 0.1881 5.74 x 10-7

1.6 mm extrudate 0.2945 8.86 x 10-7

Table 9 – Constants for Pressure Drop Equation

Fig. 25 was derived from the previous equation by assuming a gas composition and temperature setting the

maximum allowable pressure drop through the bed should be about 35 kPa. A design pressure drop higher

than 55 kPa is not recommended as the desiccant is fragile and can be crushed by the total bed weight and

pressure drop forces. Remember to check the pressure drop after the bed height has been determined.


PRG.PR.GAS.0001


Sheet 73 (90)

Fig. 25 – Allowable Velocity for Mole Sieve Dehydrator

Once the allowable superficial velocity is estimated, calculate the bed minimum diameter (i.e. D minimum), and

select the diameter (i.e. D selected): 5.0

maxmin

4⎟⎟⎠

⎞⎜⎜⎝

⎛=

VqD imum π

; [m] Eq. 9

ρ

•

=mq [m3/s] Eq. 10

Where should be 110% of the maximum operating case since the bed diameter is a key parameter for

the unit performances.

•

m

Obtain the corresponding superficial velocity, Vadjusted as follows: 2

minmax ⎟⎟

⎠

⎞⎜⎜⎝

⎛=

selected

imumadjusted D

DVV [m/s] Eq. 11

An alternative and more exact method is to calculate the maximum superficial velocity by solving Eq. 8

algebraically, which gives Eq. 12 below. The second term inside the square root of Eq. 12 may be deleted

since its value is insignificant compared to the first term, which gives Eq. 13.


PRG.PR.GAS.0001


Sheet 74 (90)

⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢

⎣

⎡⎟⎟⎠

⎞⎜⎜⎝

⎛⎟⎠⎞

⎜⎝⎛

−

⎪⎪

⎭

⎪⎪

⎬

⎫

⎪⎪

⎩

⎪⎪

⎨

⎧

⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢

⎣

⎡⎟⎟⎠

⎞⎜⎜⎝

⎛⎟⎠⎞

⎜⎝⎛

+⎟⎠⎞

⎜⎝⎛ Δ

=22

21

2

maxmax

ρμ

ρμ

ρCB

CB

CLP

V [m/s] Eq. 12

⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢

⎣

⎡⎟⎟⎠

⎞⎜⎜⎝

⎛⎟⎠⎞

⎜⎝⎛

−

⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢

⎣

⎡⎟⎠⎞

⎜⎝⎛ Δ

=2

21

maxmax

ρμ

ρCB

CLP

V [m/s] Eq. 13

The value of (ΔP/L)max in this equation depends on the sieve type, size and shape, but a typical value for

design is 7.5 kPa/m.

Next step is to choose an adsorption period and calculate the mass of desiccant required. Eight to twelve

hour adsorption periods are common. Periods of greater than 12 hours may be justified especially if the

feed gas is not water saturated. Long adsorption periods mean less regenerations and longer sieve life, but

larger beds and additional capital investment.

Both water capacity and the rate at which solid desiccant adsorb water decline as the material ages. The

object of the design is to install enough desiccant such that after three to five years, the water mass

transfer zone (Zone 2, Fig. 25) will be at the bottom of the bed at the end of the adsorption period.

In the saturation zone, molecular sieve is expected to hold approximately 13 kg of water per 100 kg of

sieve. New sieve will have an equilibrium capacity near 20% (20 kg of water per 100 kg of sieve); 13%

represents the approximate capacity of a 3-5 year old sieve. This capacity needs to be adjusted when the

gas is not water saturated or the temperature is above 24°C. See Fig. 26 and Fig. 27 to find the correction

factors for molecular sieve.


PRG.PR.GAS.0001


Sheet 75 (90)

Fig. 26 – Mole Sieve Capacity Correction for Unsaturated Inlet Gas

Fig. 27 – Mole Sieve Capacity Correction for Temperature

To determine the mass of desiccant required in the saturation zone (SS), calculate the amount of water to

be removed during the cycle and divide by the effective capacity.

TSS

rs CC

WS13.0

= Eq. 14

( )densitybulkDSL S

S ⋅= 2

4π

Eq. 15

where

SS: amount molecular sieves required in saturation zone, [kg];

LS: length of packed bed saturation zone, [m];

Wr: water removed per cycle, [kg];


PRG.PR.GAS.0001


Sheet 76 (90) Css: saturation correction factor for sieve;

CT: temperature correction factor.

Molecular sieve bulk density is 675-735 kg/m3 for spherical particles and 640-705 kg/m3 for extruded

cylinders.

Even though the mass transfer zone (MTZ) will contain some water (approximately 50% of the equilibrium

capacity), the saturation zone is estimated assuming it will contain all the water to be removed.

The length of the mass transfer zone can be estimated as follows:

( )ZV

L adjustedMTZ ⋅⎟⎟

⎠

⎞⎜⎜⎝

⎛=

3.0

640 Eq. 16

Where: Z = 0.52 m for 3 mm sieve

0.26 m for 1.5 mm sieve

The total bed height is the summation of the saturation zone and the mass transfer zone heights. It should

be not less than the vessel inside diameter, or 1.8 m, whichever is greater.

Now the total bed pressure drop is checked. The ΔP/L for the selected diameter, Dselected, is adjusted using

the following equation and approximation:

( )2

max

/46.7 ⎟⎟⎠

⎞⎜⎜⎝

⎛≅⎟

⎠⎞

⎜⎝⎛ Δ

VV

mkPaLP adjusted

adjusted

Eq. 17

The result is multiplied times the total bed height (Ls + LMTZ) to get the total design pressure drop, which

should be 45-55 kPa max. This is important, because the operating pressure drop can increase to as much

as double the design value over three years. If the pressure drop exceeds 55 kPa, the bed diameter should

be increased and the sieve amount and vessel dimensions recalculated.

To estimate the total cylindrical length of a tower, add an adequate spacing to the bed height, which

provides the space for an inlet distributor and for bed support and hold-down balls under and on top of the

sieve bed.

4.2.4.3 Regeneration Calculations

The first step is to calculate the total heat required to desorb the water, to heat the desiccant and vessel. A

10% heat loss is assumed.

( bedonwaterofkgkgkJQw ⋅⋅⋅⋅⎟⎟

⎠

⎞⎜⎜⎝

⎛= 4200 ) Eq. 18

where Qw: desorption of water heat duty, [kJ];


PRG.PR.GAS.0001


Sheet 77 (90)

( ) ( irgsi TTKkg

kJsieveofkgQ −⎟⎟⎠

⎞⎜⎜⎝

⎛⋅

⋅⋅=0.1 ) Eq. 19

where Qsi: duty required to heat molecular sieve to regeneration temperature, [kJ];

( ) ( irgst TTKkg

kJsteelofkgQ −⎟⎟⎠

⎞⎜⎜⎝

⎛⋅

⋅⋅=5.0 )

)

Eq. 20

where Qst: duty required to heat vessel and piping to regeneration temperature, [kJ];

( ) ( )( 10.0stsiwhl QQQlossheatQ ++=⋅= Eq. 21

where Qhl: regeneration heat loss, [kJ];

The temperature, Trg, is the temperature at which the bed and vessel must be heated, based on the vessel

being externally insulated (i.e. no internal insulation which is usually the case). This is about 28°C below

the temperature of the hot regeneration gas entering the tower.

It is recommended to evaluate the thickness of the vessel according to design requirement. As short-cut

formula, the weight of the vessel steel can estimated from the equations below. Eq. 22 is the ASME Section

VIII equation in terms of the vessel inside diameter. It is based on a maximum tensile stress of 130 MPa.

The design pressure is usually set at 110% of the maximum operating pressure. The value of 3.2 mm in

Eq. 23 is the corrosion allowance in inches. The term 0.75 Dbed is to account for the weight of the tower

heads. The value of 0.91 mm provides the space for the inlet distributor and support and hold down balls.

design

designbed

PkPaxPD

t2.1)2600001300002(

1000−=

= ; [mm] Eq. 22

bedbedMTZS DDLLtkgsteelofMass )91.075.0)(2.3(8.29)( ++++=⋅⋅ Eq. 23

For determining the regeneration gas rate, the total regeneration heat load should be calculated from the

following equation:

( )( )hlstsiwtr QQQQQ +++= 2 Eq. 24

The 2 factor is based on operating plants feedback and corrects for the change in temperature difference

(in – out) across the bed with time during the regeneration period. It assumes that 50% of the heat in the

gas transfers to the bed, vessel steel and heat loss to atmosphere; and the balance leaves with the hot

gas.

The regeneration gas flow rate [mrg] and the heat capacity [Cp] are calculated from the Eq. 25 and Eq. 26,

with the enthalpies obtained from the enthalpy vs temperature plots for various pressures.

Moreover the regeneration furnace should be designed for the 110% of the calculated regeneration flow

rate.


PRG.PR.GAS.0001


Sheet 78 (90)

⋅

⋅−=

))(( timeheatingTTCQm

bhotp

trrg ; [kg/time] Eq. 25

( )( )bhot

ihotp TT

HHC−−

= ; [kJ/kg°C] Eq. 26

The temperature Thot is 28°C above the temperature Trg at which the bed must be heated. The temperature

Tb is the bed temperature at the beginning of the regeneration, which is the same as the dehydration-plant

feed temperature.

The heating time is usually 50% to 60% of the total regeneration time which must include a cooling period.

Fig. 28 shows a typical temperature profile for a regeneration period (heating and cooling). For 8 hour

adsorption periods, the regeneration normally consists of 4 ½ hours of heating, 3 hours of cooling and ½

hour for stand-by and switching. For longer periods the heating time can be extended as long as a

minimum pressure drop of 0.23 kPa/m is maintained to ensure even flow distribution across the bed.

Fig. 28 – Inlet and Outlet Temperatures During Typical Solid Desiccant Bed Regeneration Period

The superficial velocity of the regeneration gas is calculated with the following equation:

24DqV

π= [m/s] Eq. 27


PRG.PR.GAS.0001


Sheet 79 (90) The calculated superficial velocity can not be less than the value that corresponds with a minimum bed

pressure drop of 0.23 kPa/m. If the calculated velocity is less than this, the regeneration gas rate should be

ecreased by

ultiplying it times V/Vmin.

tion of the above formulas for equipment sizing.

d only one of the group is

eens to provide the

lower side. This two foot space and the

e dryer. This saves

on vessel size and reactivation costs. Also in a very large system where multiple beds must be used in

parallel it may be possible to save a complete unit, and bypass that amount of gas.

increased by multiplying it by the ratio Vmin/V, and the period of regeneration should be d

m

Appendix III shows an example of the applica

4.2.4.4 Special Bed Configurations

1. Multiple Beds – Dividing the total bed area between two or more towers can result in fabrication saving

because smaller heads and lighter shell plate may be used, even though piping will be somewhat more

expensive. In addition, it is sometimes possible to reduce total desiccant and regeneration

requirements, thus affecting further savings. When the low L/D results from relatively small amounts of

water in the inlet gas, normal cycle times of 8 to 12 hours frequently result in very shallow beds of large

diameter. Multiple beds of a height higher than the minimum calculated allow each tower to operate

several times as long as a normal cycle. Thus, instead of two large towers, one on dehydration and one

on regeneration, several small dryers share the load during dehydration an

removed periodically for regeneration. Under some circumstances the total desiccant requirements for

a system of multiple beds is less than for more conventional double towers.

2. Radial Flow Dehydrators – Occasionally dehydrators are designed for radial gas flow. The gas enters a

distribution tube which runs full length through the central axis of a vertical cylindrical shell. It exits

through an annular space between the desiccant and the shell itself. This configuration provides a large

facial area in a shell of reasonable cost. There is an added cost of support scr

annular space outside the desiccant. The system also provides very short contact time, so dew points

as low as those obtained with more conventional designs are not usually possible.

3. Horizontal Beds – Supporting a bed with large area and relatively shallow depth in a cylindrical vessel

resting on its side is another alternative. In such an arrangement the desiccant depth can be about

60% of the diameter of the vessel. Thus a ten foot diameter shell would hold a six foot deep bed

supported parallel with its axis and about two feet above its

equal space above the desiccant, act as space for gas distribution. Various mechanical headers and

baffles may also be incorporated to improve gas distribution.

4. Partial Bypass – Another system may be used where the requirements are exactly opposite – only

normal drying is required. Because solid desiccants, by their nature, tend to produce very dry gas, a

portion of a wet stream may sometimes be bypassed and blended downstream of th


PRG.PR.GAS.0001


Sheet 80 (90)

4.2.5 Operation and Maintenance

Although the adsorption plant is basically simple and easy to operate, there are certain details that should

be appreciated if both satisfactory performance and adsorbent life are to be assured. This involves

measurement of temperature and flow, as well as sampling connections, at key points. Ideally, the location

and type of such facilities should be indicated. The Vendor will not normally furnish complete testing

facilities unless they are specified.

4.2.5.1 Operation Records

Adequate record maintenance and periodic tests are key to good operation. Such records should include a

diary of plant problems as well as the usual information. Routine records should show daily gas volume

processed, inlet pressure and temperature, pressure drop across the unit, daily liquid recovery,

regeneration temperatures and regeneration gas flow rate. Recording of such data on a routine basis is

advisable.

4.2.5.2 Good Operational Techniques

In addition to keeping good records there are several operating practises that lead to optimum plant

performance.

1. Protect the towers from the entrance of all liquids. This implies a good scrubber with a good mist

extractor element. A filter coalescer can also be foreseen.

2. Minimize the regeneration and cooling gas necessary to perform their functions within the prefixed

time.

3. Never allow a rapid pressure release or increase on the towers. Severe breakage can result,

particularly in the second case.

4. Make an effort to maintain as constant an inlet gas flow as possible. Minimizing rapid fluctuation in inlet

analysis is also desirable if feasible.

5. Always design and operate for maximum cycle length, consistent with the purpose of the unit in order to

increase the life of the bed.

4.2.5.3 Depressurization / Repressurization

The regeneration cycle frequently includes depressurizing / repressuring to match the regeneration gas

pressure and / or to maximize the regeneration gas volume to meet the velocity criterion. In these

applications, the rate of depressuring or repressuring should not exceed 350 kPa per minute.


PRG.PR.GAS.0001


Sheet 81 (90)

4.2.5.4 Analyzers

Moisture analyzers for very low water contents require care to prevent damage to the probes. When

inserted into the beds, sample probes and temperature probes should be installed to reach the centre of

the gas phase.

A water monitor, to indicate bed switching time is necessary part of this system. It may be an automatic

system with probe 75-100 cm up in the bed at the exit end, or it may be only an indicating system in the

feed stream which will display the water content for an operator, so that he can compensate by manually

changing the cycle time.

4.2.5.5 Insulation

Solid desiccant towers are insulated externally or internally. Internal refractory requires careful installation

and curing, usually before the desiccant is installed. It saves energy but the greatest benefit is it can

dramatically reduce the required heating and cooling times. This is often an important benefit for systems

where regeneration times are limited. The primary disadvantage is the potential for wet gas bypassing the

desiccant through cracks and defects in the insulation during the adsorption cycle.

4.2.5.6 Effects of contaminants on molecular sieves

Molecular sieves performance is strongly affected by the presence of contaminants. The nature of silica gel

molecular sieve and physical structure, which contributes to its efficiency as an adsorbent, make it subject

to chemical attack by many compounds.

- Oil, glycols, diisopropynalomine, diglycolamine and associates: this includes all the high boiling

viscous that comes along, from compressor lube systems, from the wells, from upstream

absorption plants. It enters a bed in the form of droplets or aerosol and it will be adsorbed by the

binder, or in the macropores of the molecular sieves. Such contaminant is not completely removed

during regeneration, and it eventually cracks, polymerises or otherwise goes through any number

of reactions which result in coke formation. When this occurs on some types of thermally stable

sieve, the heavy hydrocarbons can be removed by an actual burn-off under a controlled oxygen

atmosphere. Some sieves, including most of the available 3A grades do not have sufficient thermal

stability to permit this type of treatment.


PRG.PR.GAS.0001


Sheet 82 (90)

- Ammonia: the ammonia formed from decomposition of amine derivates during regeneration, will

chemically attack the silica gel in the most commonly used molecular sieve binder systems and

weaken the physical structure of the particles.

- Potassium carbonate solutions: another upstream liquid process which involves the use of hot

liquid for CO2 removal. As in the previous cases for amine and glycols, the carbonate solution will

have a blockage and blinding effect on the sieve; if present in a secondary phase. Even mild

vaporized, entry will result in cation exchange on the standard natural gas dehydration molecular

sieve 4A. The soda will be replaced by potassium, altering the 4A into 3A material. This will impact

on overall water capacity as well as thermal stability of the altered 4A if regeneration exceeds

270°C.

- Oxygen: if there is any oxygen in the system, or in the regeneration gas, it will react with H2S and

some other sulphur compounds on the surface of the sieves and deposit elemental sulphur. Since

oxygen can enter a system by a number of routes, it is a good idea to request an oxygen

determination during any routine stream analysis.

- Salt: usually enters a desiccant bed dissolved in entrained water. Unfortunately it does not leave

when the water is vapourised and removed from bed during regeneration. Thus the solid

accumulates and blocks pores, macropores and in extreme cases, all the voids between the

molecular sieve beads.

- Heavy metals, arsenic and other dense elements: large molecular particles such as mercury, lead

and arsenic will not be adsorbed into classic synthetic A and X type crystal molecular sieve

because of the pore openings. These contaminants are not considered to be harmful to the

molecular sieves performance, but may alter its toxicity rating on disposal.

4.2.6 Process Control and Safeguarding

The switching valves may be controlled on a time basis, outlet regeneration gas temperature or outlet gas

analysis. The latter is best (and most expensive) but requires a time or temperature override to ensure that

a properly regenerated and cooled tower is ready when switching occurs.

A detailed logic sequence shall be developed containing as minimum a description for the Manual and

Automatic Mode selection and operation of the switching valve control, the system start-up procedure, the

Step Permissive and the Step description, the Process Abnormal Conditions, the Sequence Extension and

the Stop Procedure.

The following figure shows a typical control configuration.


PRG.PR.GAS.0001


Sheet 83 (90)

LC

AIH2O

AIH2O

AIH2O

Wet Gas

SourWater

Dry GasRegeneration

Dry Gas

FC

Regeneration Wet Gas

Filter

Adsorp. Adsorp. Regen.

TC

to regenerationgas heater

Fig. 29 – Typical configuration of switching valve control

5. FLOW CHART

NA


PRG.PR.GAS.0001


Sheet 84 (90) 6. APPENDIX

6.1 Appendix I – Water removal at different TEG concentration and TEG circulation rates

Fig. 30 – Water removal Vs TEG Circulation Rates (N = 1)

Win/out: water content in the inlet/outlet gas

Fig. 31 – Water removal Vs TEG Circulation Rates (N = 1.5)



PRG.PR.GAS.0001


Sheet 85 (90)



Fig. 33 – Water removal Vs TEG Circulation Rates (N = 2.5)



PRG.PR.GAS.0001


Sheet 86 (90)




PRG.PR.GAS.0001


Sheet 87 (90) 6.2 Appendix II – Reboiler Heat Duty

Table 10 gives typical reboiler heat duties. The heat duty may be calculated from:

Q = (122.6 + 2461/UCR) kJ/litre

UCR

[l/kg]

Reboiler heat duty

[kJ/l TEG circulated]

10 369

15 287

20 246

25 221

30 205

40 184

50 172

60 164

Table 10 – Approximate Reboiler Heat Duty per Litre of TEG

The above duties are only typical because the sensible heat demanded from the reboiler depends on the

temperature of the rich glycol entering the still column. This temperature is dependent on the design of the

glycol-glycol heat exchangers. For the reboiler heat duties stated, the following assumptions were used:

- sufficient glycol/glycol heat exchanger surface is provided to reduce the temperature of the dry

glycol entering the surge drum to 93°C;

- a gas temperature of 50°C;

- a stripping gas rate of 35 m3 (st) per m3 of glycol at 38°C;

- a power gas rate of 50 m3 (st) (heated to 100°C) per m3 of glycol for pumps.


PRG.PR.GAS.0001


Sheet 88 (90) 6.3 Appendix III – Molecular Sieve Equipment Sizing – Example

Data

Design Pressure = 2790 kPa

Adsorption Pressure = 2060 kPa

Adsorption Temperature = 17.5°C

Regeneration Temperature = 300°C

Cycle Period = 24 h (Heating Time = 6.45 h)

Water Removed per Cycle (kg) = 160 kg/h * 24 h = 3840 kg

No. of Beds in Adsorption per Cycle = 2

Gas Flowrate (m) = 132378 k/h

Gas Density (ρ) = 32.01 kg/m3

Gas Viscosity (μ) = 0.01 cP

Gas Heat Capacity (Cp) = 2.05 kJ/kg°C

mkPa

LP 5.7

max

=⎟⎠⎞

⎜⎝⎛ Δ

Particle Type = 3A Beads, 1.6 mm (B=0.1881, C=5.74 10-7, Z=0.26 m, ref. Table 9)

Molecular Sieve Capacity Correction Factors: CSS = 0.96, CT = 1

Bulk Density = 700 kg/m3

Sieve Supposed Weight = 20330 kg

Adsorber

hm

hmV 588

201.3201.0

1074.51881.0

01.321074.55.7 72

1

7max =

⎥⎥⎥⎥

⎦

⎤

⎢⎢⎢⎢

⎣

⎡⎟⎠⎞

⎜⎝⎛⋅⎟

⎠⎞

⎜⎝⎛

⋅−⎥⎦⎤

⎢⎣⎡

⋅⋅=⎟

⎠⎞

⎜⎝⎛ −

− (Eq. 13)

hm

hmq

33

5.413501.32

132378==⎟⎟

⎠

⎞⎜⎜⎝

⎛ (Eq. 10)


PRG.PR.GAS.0001


Sheet 89 (90)

( ) mmD 3588

5.41354 5.0

min =⎟⎠⎞

⎜⎝⎛

⋅⋅

=π

(Eq. 9)

( ) mmDsel 1.3=

hm

hmVadj 569

1.33588 =⎟

⎠⎞

⎜⎝⎛=⎟

⎠⎞

⎜⎝⎛

(Eq. 11)

( ) ( )m

kPam

kPaLP 01.756901.321074.556901.01881.0 27 =⋅⋅⋅+⋅⋅=⎟

⎠⎞

⎜⎝⎛Δ − (Eq. 8)

( ) kgkgSs 3080096.0113.0

3840=

⋅⋅= (Eq. 14)

( ) mmLs 9.27001.3

2308004

2 =⋅⋅

⋅=

π (Eq. 15)

( ) mmLMTZ 25.026.0640569 3.0

=⋅⎟⎠⎞

⎜⎝⎛= (Eq. 16)

( ) mmLTOT 15.325.09.2 =+=

( ) kPakPakPaPTOT 451.2215.301.7 <=⋅=Δ

Regeneration

( ) kJkJQW610*128.1638404200 =⋅= (Eq. 18)

( ) ( ) kJkJQsi610174.55.17272120330 ⋅=−⋅⋅= (Eq. 19)


PRG.PR.GAS.0001


Sheet 90 (90)

( ) mmmmt 7.3327902.1260000

27901.31000=

⋅−⋅⋅

= (Eq. 22)

( ) ( )( ) kgkgSteelofMass 217651.391.01.375.025.09.22.37.338.29 =+⋅+++=⋅⋅ (Eq. 23)

( ) ( ) kJkJQst61077.25.172725.021765 ⋅=−⋅⋅= (Eq. 20)

( ) ( ) kJkJQhl6666 10407.21077.210174.510128.161.0 ⋅=⋅+⋅+⋅⋅= (Eq. 21)

( ) ( ) kJkJQtr76666 10296.510407.21077.210174.510128.162 ⋅=⋅+⋅+⋅+⋅⋅= (Eq. 24)

( ) hkg

hkgmrg 12899

45.65.17328050.210296.5 7

=⋅−⋅

⋅=⎟

⎠⎞

⎜⎝⎛

(Eq. 25)


Documents

PRG.pr.GAS.0001 Gas Dehydraion