Hydrate and Dehydration

8/13/2019 Hydrate and Dehydration

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Gas Dehydration System

Suryas Year 2003 PMP

Diversity Action Plan Agreement

ChevronTexaco Indonesian Business Unit

PT. Caltex Pacific Indonesia

Bekasap Operation GO&RT Team


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1. John M. Cambells Gas Conditioning and

Processing and Processing, Vol.2: The Equipment

Modules

2. Maurice Stewardsand Ken ArnoldsSurface

Production Operations Design of Gas

Handling Systems and Facilities, 2ndEdition.

3. E.Dendy Sloan, Jrs Hydrate Engineering,

Monograph Volume 21 SPE Hendry L.Doherty Series

References:


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PT. Caltex Pacific Indonesia

Bekasap GO&RT

Typical Gas Plants


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Typical Gas PlantMETERINGSKID

HP-GASSEPARATOR

GLYCOLCONTACTOR

MP-GASSEPARATOR

MP-GASCOMPRESSOR

MP HEADER

GLYCOLREGENERATION

SYSTEM

HP HEADER

COOLER


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Typical Gas Plant

INLET GAS

CHILLER

REFRIGERANT

G/G HE

COMPRESSOR

3 PHASE

SEPARATOR

COND.

HC VAPOR

FLASH

TANK

LEAN-RICH

EXCHANGER

FILTER

PUMP

SURGE

TANK

REBOILER

STEAM

RICH GLYCOL

LEAN GLYCOL

TO BUYER


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What factors influence gas quality?

Gas quality closely relates to the following parameters:

1. Saturated water content in lb/MMscfd

2. Free liquid content

3. Heat value in Btu/Scf

4. CO2 content in mol

5. Inert substance content in mol6. H2S content in ppm

7. Oxygen content in %


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Hydrate and Dehydration


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Hydrateis solid water compound developed on a process flow

Hydrateforms in two fundamental ways:

1. Slow cooling of a fluid as in a pipeline, or

2. Rapid cooling caused by depressurization across valves orthrough a turbo expander

Three conditions promote hydrate formationin process:

1. Presence of free water from reservoir or pipeline condensationand natural gas components.

2. Presence of sufficiently low temperature on the process stream

3. Presence of sufficiently high pressure on the process steam


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Hydrateformation prevention can be accomplished through:1. Water removal.

Separation will remove free water from gas stream.

2. Maintaining of process high temperaturePipe insulation and bundling, or steam or electrical heating process

3. System Pressure DecreasingHigh temperature system pressure drops design through line choking.

4. Alcohol Inhibitors injectionActing 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. Antiagglomerants

This dispersants will cause water phase be suspended as small droplets inoil or condensate.


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Hydrate formation can be found on the following section of gassystem:

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 andtemperature below hydrate formation temperature will prevent hydrationformation.

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

3.1. Requirement for water, gas and oil separation3.2. Dehydrate gas into acceptable water content3.3. Compression of gas for transportation.

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


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

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

2. Points of gas expansion

Downstream of valves, expanders and other similar equipment3. Points of flow obstruction

such 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 wateris available and system pressure is above 166 psig at 39 oF, which indicates:

1. Gas drying or inhibitor is required for temperature approaching 39 oF

2. A more accurate hydrate estimation procedure is required


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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 Chiller

Valve

G H J

PROCESSING PLANT

Hydrate Formation Points


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When we have a pipeline partial or complete blockage, questions arisen,

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

Indication of blockage composition can be found through combination ofseparators contents and pigs returns, which can provide line solidsinformation 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 separatorsupstream hydrate

3. Line Differential Pressure Increase indicates Line HydrationFormation

4. Thermo-camera

5. Gamma-ray Densitometer with Temperature Sensor


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Hydrate Formation Conditions by Gas-Gravity Methods

Gas Molecule weight ratio can be used to determine hydrate formation temperature andpressure. (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.


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Hydrate Formation Conditions by Gas-Gravity Methods, an example

Molecule

Mole

Fraction

yi

Molecular

Weight

M

Fraction

Molecular

Weight in

Mixture

yiM

Methane 0.9267 16.0430 14.8670

Ethane 0.0529 30.0700 1.5907

Prophane 0.0138 44.0970 0.6085

I-butane 0.0018 58.1240 0.1058

n-butane 0.0034 58.1240 0.1965

Pentane 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

= 0.603

From the gas gravity table, gas gravity0.603 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.


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Will 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) = 1

WhereYn = mol fraction of hydrocarbon component n

Kn= vapor solid equilibrium of component n

Knitself can be derived from

Kn= (Yn/Xn)Xn= mol fraction of hydrocarbon component in the solid

Knvalue 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 temperature

2. Determine K nfor each component

3. Calculate Yn/Knfor each component and sum them

4. Repeat step 1-3 with other assumed temperature until getting total Yn/Knvalue = 1


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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 highertemperature 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

T

e

m

p


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Dehydration is the of removing water from a gas and/or liquid toeliminate free water on the process system.

Inhibition is the process of adding chemical to the condensed water tostimulate 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 dehydrationusually used to meet pipeline specification and field requirement

2. Adsorption Mol Sieve, Silica Gel or Activated Aluminaused to obtain very low water content in NGL extraction and LNG plant

3. Condensation Refrigeration with Glycol or Methanol injectionusually used in transportation pipeline


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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 water

2. Non corrosive

3. Non-volatile,4. Easily regenerated to high concentrations,

5. Insoluble in liquid hydrocarbons

6. Non-reactive with hydrocarbon, CO2and sulfur compounds


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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


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Glycol Dehydration System


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Typical Glycol Regeneration System

WET GAS

IN

INLETSEPARATOR

DRY GASOUT

WATER VAPOR &

OFF-GAS TO ATM

OR INCINERATOR

LC

LC

LC

PC

TC

FLASHED VAPORTO FUEL OR

FLARE

TO HCDRAIN

TO HCDRAIN

CARBONFILTERS

SOCK FILTERS

(RICH TEG)

LC

FLASHDRUM

LEAN/RICH TEG

EXCHANGER

LC

REBOILER

LEAN TEG

SURGE TANK

(LEAN TEG)

TEG PUMP

TC

OUTLET

SCRUBBER

GLYCOL

CONTACTOR

LEAN TEG

COOLER

TO TEGSUMP


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Wet gas, free of liquid water, enters bottom of contactor and flowscountercurrent to glycol. Glycol-gas contacts occurs on trays orpacking where glycol absorbs water from gas, leaving the driedgas flow upward to the top of the contactor while the lean glycolenriched with absorbed water leaves the contactor through the

bottom line of the contactor.

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

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

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


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To properly absorbs gas water content in contactor (knowing how much

water to absorb from incoming gas), gas system personnel needs toknow: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 be

The higher glycol circulation rate, the higher water removal rate beAs the concentration of lean glycol entering the contactor is a predefined

value, then, things to calculate is only the lean glycol rate required topick 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 circulationrate in liters TEG/kg water or in gallon TEG/ lb water.


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Example:

Find circulation rate of 98.7 wt % lean TEG required to dry 106stdm3/d (35.4 MMscfd) of gas at 7 Mpa (1000 psia) and 40 oC (104oF) to achieve an exit gas water content of 117 kg/ 106std m3(7lbm/MMscf) if the incoming gas water content is 110 kg/ 106stdm3(68.5 lbm/MMscf)

Solution#1

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

From the chart, at98.7 wt % TEG, the rate is around35 liters TEG/kgwater

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

From the chart, at98.7 wt % TEG, the rate is around4.4 gal TEG/lb water


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TEG Regeneration


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Typical Glycol Regeneration System

WET GAS

IN

INLETSEPARATOR

DRY GASOUT

WATER VAPOR &

OFF-GAS TO ATM

OR INCINERATOR

LC

LC

LC

PC

TC

FLASHED VAPORTO FUEL OR

FLARE

TO HCDRAIN

TO HCDRAIN

CARBONFILTERS

SOCK FILTERS

(RICH TEG)

LC

FLASH

DRUM

LEAN/RICH TEG

EXCHANGER

LC

REBOILER

LEAN TEG

SURGE TANK

(LEAN TEG)

TEG PUMP

TC

OUTLET

SCRUBBER

GLYCOL

CONTACTOR

LEAN TEG

COOLER

TO TEGSUMP


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Regeneration 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, while

Concentration of rich glycol leaving a contactor can be calculated with :

%wt of rich TEG = (j.(%wt of lean TEG))/(j+ (1/CR))Where is equal to 1.12 kg/lt or 9.3 lb/gal

One thing to notice is that, whatever rich glycol concentration flown to an atmosphericpressure glycol regeneration system, in no stripping gas, the lean glycolconcentration 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 temperatureexceeds 400 oF.

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


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

Flash Drum is used to remove light hydrocarbons, CO2 and/or H2Sabsorbed or entrained with glycol, and to separate liquidhydrocarbons 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 havesome kinds of skimmer to separate liquid condensate from richglycol.

Filtersin the regeneration system is used to reduce solids from rich glycolto about 100 ppm which will reduce corrosion, plugging and soliddeposits in the reboiler and may reduce foaming losses.

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


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Lean-Rich Glycol Heat Exchanger is designed to have lean glycol

exchanger outgoing temperature of around 60 65 oC.

Reboileris the actual location of regeneration kitchenin which heat source,such as hot oil, steam or electrical resistance heater, is usually directfired with fire tubes immersed in a glycol bath.

Surge tank is installed in regeneration system to give at least 20 minutesretention times between pumpings with sufficient volume to acceptglycol drained from the reboiler to allow repair or inspection of fire tubeor heating coil.

Glycol Circulating Pumpis installed to provide flexibility to increase glycol

circulation rate to meet dew-point requirementsTypes 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 glycolentering the top of contactor be within 5-10 oC.


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

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

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 inregeneration parts such as reboiler, still column and exchangers.

In addition to causing things caused by salt, hydrocarbon can stimulatefoaming in contactor and cause filtersdamage.


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How much glycol is required?


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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, (TeqTop),oF at the pressure

CI = constant for particular inhibitor (2 for MEG)

WI = weight % of inhibitor in the liquid

MI = molecular weight of inhibitor (62 for MEG)

This equation is usable to determine amount of inhibitor to prevent hydrate

formation with great accuracy


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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 phase

3. 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 2000

water content, lbm/MMscfd 15 9 7 5.5

Gas Water Content at 39o

F


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Rules of Thumb


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

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

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

4. Hydrate blockages occur owing to abnormal operating conditionssuch 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. Ingas.condensate or gas/oil systems, hydrates frequently form from freewater as particles that agglomerate and bridge as larger masses in the

bulk stream.


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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 anoil 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 pressureplace the system farther into the hydrate-formation region. When ahydrate blockage is experienced, for safety reason, the first step is toinject inhibitor from any access point.

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


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Hydrate and Dehydration