gas dehydration system chevron 46v

August 2003

Gas Dehydration System

Surya’s Year 2003 PMPDiversity Action Plan Agreement

ChevronTexaco Indonesian Business Unit PT. Caltex Pacific Indonesia

Bekasap Operation GO&RT Team

August 2003


1. John M. Cambell’s Gas Conditioning and Processing and Processing, Vol.2: The Equipment Modules

2. Maurice Steward’s and Ken Arnold’s Surface Production Operations – Design of Gas Handling Systems and Facilities, 2nd Edition.

3. E.Dendy Sloan, Jr’s Hydrate Engineering, Monograph Volume 21 SPE Hendry L.Doherty Series

References:

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PT. Caltex Pacific IndonesiaBekasap GO&RT Typical Gas Plants

August 2003

Gas Dehydration SystemTypical Gas Plant

METERINGSKID

HP-GASSEPARATOR

GLYCOLCONTACTOR

MP-GASSEPARATOR

MP-GASCOMPRESSOR

MP HEADER

GLYCOLREGENERATION

SYSTEMHP HEADER

COOLER

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Gas Dehydration SystemTypical Gas Plant

INLET GASCHILLER

REFRIGERANT

G/G HE

COMPRESSOR

3 PHASESEPARATOR

COND.

HC VAPOR

FLASHTANK

LEAN-RICHEXCHANGER

FILTER

PUMP

SURGETANK

REBOILER

STEAM

RICH GLYCOL

LEAN GLYCOL

TO BUYER

August 2003


What factors influence gas quality?

Gas quality closely relates to the following parameters:1. Saturated water content in lb/MMscfd2. Free liquid content3. Heat value in Btu/Scf4. CO2 content in mol5. Inert substance content in mol6. H2S content in ppm7. Oxygen content in %

August 2003


Hydrate and Dehydration

August 2003


Hydrate is solid water compound developed on a process flow

Hydrate forms in two fundamental ways:1. Slow cooling of a fluid as in a pipeline, or2. Rapid cooling caused by depressurization across valves or

through a turbo expander

Three conditions promote hydrate formation in process:1. Presence of free water from reservoir or pipeline condensation

and natural gas components.2. Presence of sufficiently low temperature on the process stream3. Presence of sufficiently high pressure on the process steam

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Hydrate formation prevention can be accomplished through:1. Water removal.

Separation will remove free water from gas stream.2. Maintaining of process high temperature

Pipe insulation and bundling, or steam or electrical heating process3. System Pressure Decreasing

High temperature system pressure drops design through line choking.4. Alcohol Inhibitors injection

Acting as antifreezes, alcohols will decrease hydrate formation temperature below operating temperature

5. Kinetic (Polymer dissolved in solvent) InhibitorsIt will bond on the hydrate surface to prevent crystal growth.

6. AntiagglomerantsThis dispersants will cause water phase be suspended as small droplets in oil or condensate.

August 2003


Hydrate formation can be found on the following section of gas system:

1. Gas wells. High reservoir temperature will prevent hydrate formation. However, abnormalities may arise during drilling, testing or shut-in/startup of a well.

2. Gas pipelinesPipeline maintained pressure above hydrate formation pressure and temperature below hydrate formation temperature will prevent hydration formation.

3. Gas Processing FacilitiesThere are three reasons why we need gas processing facilities:

3.1. Requirement for water, gas and oil separation 3.2. Dehydrate gas into acceptable water content 3.3. Compression of gas for transportation.

It is important to notice that water separation and gas dehydration are vital for hydrate prevention as they will help maintain insufficient water content on the gas for hydration formation.

August 2003


In gas processing facilities, Hydrate formation can be found on the following sections:

1. Low lying equipment pointssuch as pipeline lying under a roadway

2. Points of gas expansionDownstream of valves, expanders and other similar equipment

3. Points of flow obstructionsuch as screens preceding heat exchangers

4. Points of Change in flow directionsuch as pipe elbows

As a rule of thumb, Hydrate will form in a natural gas system in free water is available and system pressure is above 166 psig at 39 oF, which indicates:1. Gas drying or inhibitor is required for temperature approaching 39 oF2. A more accurate hydrate estimation procedure is required

August 2003


well

Dehydrator or Inhibitor

Injection

PC

GATHERING SYSTEM

PC

Fuel to heateror Engine

A

B

C D

E F

Dehydrator or Inhibitor

Injection

GAS

Condensate

Compressor ChillerValve

G H J

PROCESSING PLANT

Hydrate Formation Points

August 2003

Gas Dehydration SystemWhen we have a pipeline partial or complete blockage, questions arisen,

among others, are (1) where is the plug? (2) is the blockage composed of hydrates, paraffin, scale, sand or some combination of these?

Indication of blockage composition can be found through combination of separators contents and pigs returns, which can provide line solids information such as hydrates, wax, scale and sand.

How to detect pipeline blockage?1. Pigging returns – can indicate implicit hydrate as hydrate can flow with

oil/condensate.Lack of hydrate blockage does not mean lack of hydrate!Always examine pigging returns for the best hydrate indication!

2. Changes in fluid rates or composition at separator- Separator water arrival decline indicates separator’s upstream hydrate

3. Line Differential Pressure Increase indicates Line Hydration Formation

4. Thermo-camera5. Gamma-ray Densitometer with Temperature Sensor

August 2003

Gas Dehydration SystemHydrate Formation Conditions by Gas-Gravity MethodsGas Molecule weight ratio can be used to determine hydrate formation temperature and

pressure. (from page 11 of SPE book, figure 2.8)

Knowing gas gravity and the lowest temperature of the process/pipeline, we can read the hydrate formation pressure at the gas gravity and temperature.

To the left of every line, hydrates form with a gas of that gravity, while for pressure and temperature to the right of the line, system is hydrate-free.

August 2003

Gas Dehydration SystemHydrate Formation Conditions by Gas-Gravity Methods, an example

MoleculeMole

Fractionyi

Molecular Weight

M

FractionMolecularWeight inMixture

yiMMethane 0.9267 16.0430 14.8670Ethane 0.0529 30.0700 1.5907

Prophane 0.0138 44.0970 0.6085I-butane 0.0018 58.1240 0.1058n-butane 0.0034 58.1240 0.1965Pentane 0.0014 72.1510 0.1010

Gas Gravity Chart

Total 1.0000 Average Molecular Weight is 17.4700

Find the pressure are which a gas composed of 92.67 mol% metahen, 5.29% ethane, 1.38% propane, 0.182% I-butane, 0.338% n-butane, and 0.14% pentane froms hydrate with free water at 50oFSolusion:Gas gravity is 0.603 = Mg (gas mole weight) / M air = 17.47/28.96 = 0.603From the gas gravity table, gas gravity 0.603 in temperature of 50oF, hydrate pressure is around 450 psig.

A thing to remember is that the value is only approximation. However, it can be used to determine whether hydrate is potential to form or not in a system based on the data.

August 2003

Gas Dehydration SystemWill hydrate form in my pipeline?

Knowing composition of the stream, hydrate formation temperature can be predicted using hydrate equilibrium constants in which,

SUM(Yn/Kn) = 1Where Yn = mol fraction of hydrocarbon component nKn = vapor solid equilibrium of component n

Kn itself can be derived fromKn = (Yn/Xn)

Xn = mol fraction of hydrocarbon component in the solid

Kn value of various gas components can be taken from the charts of the following slides

Steps for determining hydrate temperature at a give pressure can be summarized;1. Assume a hydrate formation temperature2. Determine Kn for each component3. Calculate Yn/Kn for each component and sum them4. Repeat step 1-3 with other assumed temperature until getting total Yn/Kn value = 1

August 2003


August 2003


Condensation of Water VaporTemperature at which water condenses from natural gas is called its dew point.

If a gas is saturated with water vapor, it is, then, at its dew point.

Amount of water vapor saturated in a gas can be checked from the next page chart.

For example, at 150 oF and 3000 psi, saturated gas will contain approximately 105 lb of water vapor per MMscf of gas.

If there is less water vapor, the gas is not saturated and its temperature can be reduced without water condensing. If the gas is saturated at a higher temperature and ten cooled to 150 oF, water will condense until there are only 105 lb of water vapor left on the gas.

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pressure

Water content

Temp

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Dehydration is the of removing water from a gas and/or liquid to eliminate free water on the process system.Inhibition is the process of adding chemical to the condensed water to stimulate hydrate formation.

Why should water be removed from the system? Because free water can form hydrate and stimulate corrosion

Natural gas is dehydrated in one of the following methods: 1. Absorption Glycol dehydration usually used to meet pipeline specification and field requirement 2. Adsorption Mol Sieve, Silica Gel or Activated Alumina used to obtain very low water content in NGL extraction and LNG plant 3. Condensation Refrigeration with Glycol or Methanol injection usually used in transportation pipeline

August 2003


Four types of glycol are used for dehydration and/or inhibition1. Monoethilene glycol (MEG or EG)2. Diethylene glycol (DEG)3. Triethylene glycol (TEG)4. Tetraethylene glycol (TREG)

Glycol to be used in absorption must satisfy the following requirements:1. Hygroscopic, having an affinity to water2. Non corrosive3. Non-volatile,4. Easily regenerated to high concentrations, 5. Insoluble in liquid hydrocarbons6. Non-reactive with hydrocarbon, CO2 and sulfur compounds

August 2003


Distinguishable parameters among glycol types

Ethylene Glycol

Diethylene Glycol

Triethylene Glycol

Molecular Weight 62.07 106.12 150.17

Specific Gravity @ 77 F 1.110 1.111 1.120

Boiling point @ 1 atm, F 387.3 473.8 550.0

Freezing Point, F 7.9 16.4 19

Viscosity, cP, @ 77 F 16.9 25.3 39.4

Specific Heat @ 77 F 0.58 0.55 0.52

Vapor pressure, psia @77 F < 0.1 < 0.01 < 0.01

Decomposition temperature, F 329 328 404

August 2003


Glycol Dehydration System

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Typical Glycol Regeneration System

WET GASIN

INLETSEPARATOR

DRY GASOUT

WATER VAPOR &OFF-GAS TO ATM

OR INCINERATOR

LC

LC

LC

PC

TC

FLASHED VAPORTO FUEL OR

FLARE

TO HCDRAIN

TO HC DRAIN

CARBON FILTERSSOCK FILTERS

(RICH TEG)

LCFLASHDRUM

LEAN/RICH TEGEXCHANGER

LC

REBOILER

LEAN TEGSURGE TANK

(LEAN TEG)

TEG PUMP

TC

OUTLETSCRUBBER

GLYCOLCONTACTOR

LEAN TEGCOOLER

TO TEGSUMP

August 2003


Wet gas, free of liquid water, enters bottom of contactor and flows countercurrent to glycol. Glycol-gas contacts occurs on trays or packing where glycol absorbs water from gas, leaving the dried gas flow upward to the top of the contactor while the lean glycol enriched with absorbed water leaves the contactor through the bottom line of the contactor.

Rich glycol, leaving the contractor will flow to a reflux condenser at the top of the still column and, then, to a flash tank where the entrained and soluble (volatile) components are vaporized.

Leaving the flash drum, the rich glycol will flow through glycol carbon filters before being heated in lean-rich exchanger from which it flows to still column for water distillation.

The distillation process in still column and reboiler is the true glycol re-concentration media, i.e, the parts where rich glycol be turned to rich glycol.

August 2003

Gas Dehydration SystemTo properly absorbs gas water content in contactor (knowing how much

water to absorb from incoming gas), gas system personnel needs to know:1. Minimum concentration of lean glycol entering the contactor2. Lean glycol rate required to pick up water from the gas

The higher glycol concentration, the higher water removal rate beThe higher glycol circulation rate, the higher water removal rate be

As the concentration of lean glycol entering the contactor is a predefined value, then, things to calculate is only the lean glycol rate required to pick up water from gas.

Approximation of the glycol circulation rate can be obtained by knowing (1) lean glycol concentration,

(2) entering gas water content and (3) outgoing gas water content

Combined with the use of the following approximation chart to get the circulation rate in liters TEG/kg water or in gallon TEG/ lb water.

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August 2003


Example:Find circulation rate of 98.7 wt % lean TEG required to dry 106 std

m3/d (35.4 MMscfd) of gas at 7 Mpa (1000 psia) and 40 oC (104 oF) to achieve an exit gas water content of 117 kg/ 106 std m3(7 lbm/MMscf) if the incoming gas water content is 110 kg/ 106 std m3(68.5 lbm/MMscf)

Solution#1Water removal = (Win-Wout)/Win = (1100-117)/1100 = 0.894

From the chart, at 98.7 wt % TEG, the rate is around 35 liters TEG/kg water

Solution#2Water removal = (Win-Wout)/Win = (68.5-7)/68.5 = 0.898

From the chart, at 98.7 wt % TEG, the rate is around 4.4 gal TEG/lb water

August 2003


TEG Regeneration

August 2003


Typical Glycol Regeneration System

WET GASIN

INLETSEPARATOR

DRY GASOUT

WATER VAPOR &OFF-GAS TO ATM

OR INCINERATOR

LC

LC

LC

PC

TC

FLASHED VAPORTO FUEL OR

FLARE

TO HCDRAIN

TO HC DRAIN

CARBON FILTERSSOCK FILTERS

(RICH TEG)

LCFLASHDRUM

LEAN/RICH TEGEXCHANGER

LC

REBOILER

LEAN TEGSURGE TANK

(LEAN TEG)

TEG PUMP

TC

OUTLETSCRUBBER

GLYCOLCONTACTOR

LEAN TEGCOOLER

TO TEGSUMP

August 2003

Gas Dehydration SystemRegeneration system consists of a reboiler, still column and a gas

stripping column.Lean glycol concentration is controlled with adjustment of reboiler

temperature, pressure and possible use of a stripping gas, whileConcentration of rich glycol leaving a contactor can be calculated with :

%wt of rich TEG = (wt of lean TEG))/( + (1/CR))Where is equal to 1.12 kg/lt or 9.3 lb/galOne thing to notice is that, whatever rich glycol concentration flown to an atmospheric

pressure glycol regeneration system, in no stripping gas, the lean glycol concentration will be:

* 98.1 wt % if the reboiler temperature is maintained 128 oC or 360 oF* 98.4 wt % if the reboiler temperature is maintained 193 oC or 380 oF* 98.7 wt % if the reboiler temperature is maintained 204 oC or 400 oF.

One other thing to notice is than 20 oF reboiler increase of decrease will cause the lean glycol wt % increase or decrease by 0.3 wt %, however NEVER let temperature exceeds 400 oF.

For stripping gas usage, the lean glycol wt % can be approximated with the following chart (figure 18.12 JMC page 359)

August 2003


August 2003


Still column is the fractionator portion of the regenerator in which rich glycol is fractionated to some portions of water vapour, and lean glycol fractions.

Flash Drum is used to remove light hydrocarbons, CO2 and/or H2S absorbed or entrained with glycol, and to separate liquid hydrocarbons from glycol to prevent it from entering the reboiler and causing fouling and foaming.

Notwithstanding that flash drum should not contain liquid hydrocarbon, sometimes, we may find it there. Consequently, it is wise to have some kinds of skimmer to separate liquid condensate from rich glycol.

Filters in the regeneration system is used to reduce solids from rich glycol to about 100 ppm which will reduce corrosion, plugging and solid deposits in the reboiler and may reduce foaming losses.

Filters effectiveness can be checked through differential pressure inspection. As it reaches 25 psi, it needs replacement.

August 2003


Lean-Rich Glycol Heat Exchanger is designed to have lean glycol exchanger outgoing temperature of around 60 – 65 oC.

Reboiler is the actual location of regeneration ‘kitchen’ in which heat source, such as hot oil, steam or electrical resistance heater, is usually direct fired with fire tubes immersed in a glycol bath.

Surge tank is installed in regeneration system to give at least 20 minutes retention times between pumpings with sufficient volume to accept glycol drained from the reboiler to allow repair or inspection of fire tube or heating coil.

Glycol Circulating Pump is installed to provide flexibility to increase glycol circulation rate to meet dew-point requirements

Types of pumps to use in this function can be reciprocating multiplex type with conservative slow piston speed.

Lean Glycol Cooler is designed to have temperature of the lean glycol entering the top of contactor be within 5-10 oC.

August 2003


One thing that must be made sure in glycol dehydration system is that whatever gas fed to the contactor should have been free of liquid hydrocarbons, liquid water, solids, corrosion inhibitor, etc, i.e, gas must be sufficiently clean and free of liquid before dehydrated.

It is wise to make sure that gas planned to be glycol dehydrated be flown to a separator or to a slug catcher before being flown to contactor.

Other important thing to remember is that glycol must be free of non-volatile contaminant such as salt or hydrocarbon.

Salt can cause plugging which increases pressure drops and flow rate in regeneration parts such as reboiler, still column and exchangers.

In addition to causing things caused by salt, hydrocarbon can stimulate foaming in contactor and cause filters’ damage.

August 2003


How much glycol is required?

August 2003


Estimation of Hydrate Inhibitors Needed in Free-Water phase

Gas gravity chart described before may be combined with Hammerschmidth equation to estimate hydrate depression temperature for several inhibitors:

dT = CIWI /(MI (100-WI))

Where dT = hydrate depression, (Teq – Top), oF at the pressureCI = constant for particular inhibitor (2 for MEG)WI = weight % of inhibitor in the liquidMI = molecular weight of inhibitor (62 for MEG)

This equation is usable to determine amount of inhibitor to prevent hydrate formation with great accuracy

August 2003


Estimation of Hydrate Inhibitors Needed in PipelineThree considerations must be analyzed before injecting inhibitors to pipelines

1. Amount of inhibitors in free-water phase 2. Amount of inhibitor lost to gas phase3. Amount of inhibitor lost to condensate phase

Rule of thumb : For long pipelines approaching ocean, bottom temperature of 39 oF, the lowest water content can be tabulated

Rule of thumb : At 39 oF, and pressure greater than 1000 psia, the maximum amount of MEG lost to the gas is 0.02 lbm/MMscfd.

Pipe pressure, psia 500 1000 1500 2000water content, lbm/MMscfd 15 9 7 5.5

Gas Water Content at 39 oF

August 2003


Rules of Thumb

August 2003


1. At 39 oF, hydrates will form in anural gas system if free water is available and the pressure is greater than 166 psig.

2. It is always better to expand a dehydrated gas than a moist gas to prevent hydrate formation

3. Where drying is not a possibility, it is always better to take a large pressure drop at a process condition where the inlet temperature is high.

4. Hydrate blockages occur owing to abnormal operating conditions such as well tests with water, loss of inhibitor injection, dehydration malfunction, startup and shut-in.

5. In gas/water systems, hydrates tend to form on the pie wall. In gas.condensate or gas/oil systems, hydrates frequently form from free water as particles that agglomerate and bridge as larger masses in the bulk stream.

August 2003


6. A lack of hydrate blockages does not indicate a lack of hydrates. Frequently, hydrates form but flow with an oil/condensate (e.g., in an oil with a natural dispersant present) so they can be detected in pigging returns.

7. Attempts to blow the plug out of the line by increasing pressure differentials result in more hydrate formation because higher pressure place the system farther into the hydrate-formation region. When a hydrate blockage is experienced, for safety reason, the first step is to inject inhibitor from any access point.

8. As gas is cooled from reservoir temperature, the amount of water vapor contained in the gas will decrease. That is water will condense

August 2003

Thank you very muchYour support is very appreciated

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gas dehydration system chevron 46v

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