che 206.01 introduction to hydrate inhibition and dehydration

Note: The source of the technical material in this volume is the Professional Engineering Development Program (PEDP) of Engineering Services.

Warning: The material contained in this document was developed for Saudi Aramco and is intended for the exclusive use of Saudi Aramcos employees. Any material contained in this document which is not already in the public domain may not be copied, reproduced, sold, given, or disclosed to third parties, or otherwise used in whole, or in part, without the written permission of the Vice President, Engineering Services, Saudi Aramco.

Chapter : Chemical For additional information on this subject, contact File Reference: CHE-206.01 PEDD Coordinator on 874-6556

Engineering Encyclopedia Saudi Aramco DeskTop Standards

INTRODUCTION TO HYDRATE INHIBITION AND DEHYDRATION

Engineering Encyclopedia Dehydration and Hydrate Inhibition

Introduction to Hydrate Inhibition and Dehydration

Saudi Aramco DeskTop Standards i

CONTENT PAGE INTRODUCTION............................................................................................................6

APPROPRIATE METHODS OF DEHYDRATION OR HYDRATE INHIBITION..............7

Dehydration .........................................................................................................7

Liquid Desiccants (Glycols).......................................................................7

Solid Desiccants .....................................................................................10

Hydrate Inhibition...............................................................................................13

Temperature Control...............................................................................13

Methanol Injection...................................................................................13

Glycol Injection .......................................................................................15

Major Saudi Aramco Dehydration Units ..................................................17

Major Saudi Aramco Hydrate Inhibition Units .........................................17

PROBLEMS RELATED TO WATER IN PROCESS STREAMS ASSOCIATED WITH NATURAL GAS PROCESSING AND COMPRESSED AIR FACILITIES ...........18

Sources of Water...............................................................................................18

Water Trapped in the Reservoir Rock.....................................................18

Water Used for Extracting Oil and Gas From Wells................................20

Corrosion In Natural Gas Streams and Compressed Air Facilities ....................20

Blockages In Natural Gas Streams and Compressed Air Facilities ...................20

Examples of Problems Caused by Water in Saudi Aramco Process Streams...20

METHODS AND EQUIPMENT USED TO MEASURE THE WATER CONTENT OF NATURAL GAS STREAMS ...........................................22

Bureau of Mines Dew Point Tester ....................................................................22

Cobalt Bromide Method.....................................................................................25

Electronic Moisture Analyzers ...........................................................................26

Aluminum Oxide Humidity Sensor ..........................................................26

Conductivity Cell .....................................................................................27



Saudi Aramco DeskTop Standards ii

Electrolytic Moisture Analyzers ...............................................................27

Titration with Karl Fischer Reagents..................................................................29

Valve Freeze Method ........................................................................................30

CALCULATING THE SATURATED WATER CONTENT OF HYDROCARBON GASES AND LIQUIDS..............................................................31

Factors Affecting Water Content........................................................................31

Saturated Water Content of Natural Gas Streams.............................................31

Graphs Plotting the Temperature and Pressure of Natural Gases..........32

Graphs Plotting the Temperature, Pressure, and Acid-Gas Content of Natural Gases.................................................32

Equations-of-State Methods ...................................................................36

Saturated Water Content of Hydrocarbon Liquids .............................................37

WORK AID 1: PROCEDURES AND RESOURCES FOR CALCULATING THE SATURATED WATER CONTENT OF NATURAL GAS STREAMS AND HYDROCARBON LIQUID STREAMS......................38

Work Aid 1A: Procedures and Resources for Calculating the Saturated Water Content of Natural Gas Streams ..............38

Method 1.................................................................................................38

Method 2.................................................................................................43

Work Aid 1B: Procedures and Resources for Calculating the Saturated Water Content of Hydrocarbon Liquid Streams .........................46

WORK AID 2: PROCEDURES AND RESOURCES FOR DETERMINING THE HYDRATE-FORMATION TEMPERATURES OF SWEET AND SOUR GAS STREAMS ................................................47

Work Aid 2A: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (Gravity Graphic Method) ..........................................................47

Work Aid 2B: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (PRO/II) .....................................................................................49



Saudi Aramco DeskTop Standards iii

Work Aid 2C: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (HYSIM).....................................................................................50

GLOSSARY .................................................................................................................51

ADDENDUM ................................................................................................................56

Hydrate-Formation Temperature (Gravity Graphic Method) ..............................58

Hydrate-Formation Temperature (PRO/II) .........................................................58

Water Content (Inlet Temperature)....................................................................59

Water Content (Chiller Temperature) ................................................................59

Rate of Water Condensed in Chiller ..................................................................59

ADDENDUM A: MAJOR SAUDI ARAMCO DEHYDRATORS ....................................60

Aramco Dehydration Facilities ...........................................................................60

Khurais, Gas Lift for Crude Oil (Currently Mothballed)............................60

Udhailiyah, Gas Lift for Water Production (Currently Mothballed)...........60

Abqaiq Plants, 340 (Currently Mothballed) .............................................60

Abqaiq Plant 462 (Currently Mothballed) ................................................60

Safaniya Onshore Facilities ....................................................................61

Shedgum Gas Plant (Gas)......................................................................61

Shedgum Gas Plant (NGL) .....................................................................61

Uthmaniyah Gas Plant (Gas) ..................................................................61

Uthmaniyah Gas Plant (NGL) .................................................................62

Berri Gas Plant .......................................................................................62

Ju'aymah Fractionation Plant (Ethane) ...................................................62

Ju'aymah Fractionation Plant (Propane).................................................63

Ju'aymah Fractionation Plant (Butane) ...................................................63

Yanbu Fractionation Plant (Propane)......................................................63

Yanbu Fractionation Plant (Butane) ........................................................64

Ras Tanura Refinery, Plant 25................................................................64



Saudi Aramco DeskTop Standards iv

Ras Tanura Refinery, Plants 9, 10, 16, 40, 490 ......................................64

ADDENDUM B: EQUATIONS USED IN CHE 206.01................................................67

ADDENDUM C: WATER CONTENT CONVERSION TABLE.....................................69

ADDENDUM D: VAPOR-SOLID EQUILIBRIUM CONSTANTS .................................71

List of Figures Figure 1: Characteristics Of Glycols .............................................................................8

Figure 2: Typical Glycol Dehydration System...............................................................9

Figure 3: Characteristics Of Solid Desiccants ............................................................11

Figure 4: Solid Desiccant Dehydration System ..........................................................12

Figure 5: Methanol Injection System ..........................................................................14

Figure 6: Glycol Injection And Recovery System .......................................................15

Figure 7: Comparison Of Glycol And Methanol As Hydrate Inhibitors ........................16

Figure 8: Major Types Of Reservoir Traps .................................................................19

Figure 9: Bureau Of Mines Dew Point Tester.............................................................23

Figure 10: Mechanical Construction And Cross-Section Of Aluminum Oxide Sensor ...................................................................26

Figure 11: Operation Of Electrolytic Moisture Analyzer..............................................28

Figure 12: Moisture Titrator Using Karl Fischer Reagents..........................................29

Figure 13: Effects Of CO2 And H2S On Water Content At 1,000 Psia.......................31

Figure 14: Comparison Of Calculated And Experimental Water Contents .................33

Figure 30: Water Content Of Hydrocarbon Gas .........................................................40

Figure 31: Effective Water Content Of CO2 ...............................................................41

Figure 32: Effective Water Content Of H2S................................................................42



Saudi Aramco DeskTop Standards v

Figure 33: Water Content Of Acid Gases (Converted To Pseudo H2S Concentrations) .....................................................................................44

Figure 34: Solubility Of Water In Liquid Hydrocarbons...............................................46

Figure 35: Pressure-Temperature Curves For Predicting Hydrate Formation ............48

Figure 36: Table For Calculating The Molecular Weight Of The Gas Stream ............57

Figure 37: Process Printout Of Hydrate-Formation Temperatures .............................58

Figure 38: Major Activated Alumina Dehydration Units ..............................................65

Figure 39: Major Molecular Sieve Dehydration Units .................................................66

Figure 40: Water Content Conversion Table ..............................................................69

Figure 41: Vapor-Solid Equilibrium Constants For Methane ......................................72

Figure 42: Vapor-Solid Equilibrium Constants For Ethane .........................................73

Figure 43: Vapor-Solid Equilibrium Constants For Propane.......................................74

Figure 44: Vapor-Solid Equilibrium Constants For Isobutane.....................................75

Figure 45: Vapor-Solid Equilibrium Constants For N-Butane .....................................76

Figure 46: Vapor-Solid Equilibrium Constants For Carbon Dioxide............................77

Figure 47: Vapor-Solid Equilibrium Constants For Hydrogen Sulfide .........................78



Saudi Aramco DeskTop Standards 6

INTRODUCTION

ChE 206.01 reviews and further develops the information covered in ChE 104.05. This module first identifies the methods commonly used for dehydration and hydrate inhibition. It then identifies problems caused by water in process streams associated with natural gas facilities. ChE 206.01 then covers the methods and equipment used to measure the water content of natural gas streams.

Having covered the measurement of water in natural gas streams, ChE 206.01 describes the calculation or prediction of the water content of natural gas and liquid hydrocarbon streams. This module then covers the use of equations and graphical techniques to determine the hydrate-formation temperatures of sweet and sour gas streams. The information and methods covered in ChE 206.01 are used to determine the process load on hydrate inhibition and dehydration systems.




APPROPRIATE METHODS OF DEHYDRATION OR HYDRATE INHIBITION

Dehydration

Removing water from natural gas streams helps prevent the following:

Line blockages and freezeups Accelerated corrosion Hydrate formation

Natural gases are also dehydrated to meet sales gas specifications. Gases are normally dehydrated by:

Absorbing free water and water vapor with liquid desiccants.

Adsorbing water vapor with solid desiccants. Condensing out the water vapor using expansion or

refrigeration. Liquid Desiccants (Glycols)

Liquid desiccants dry gases by absorbing water in a natural gas stream. A typical cycle includes contacting the liquid desiccant with the gas stream and then stripping the water from the desiccant.

Liquid desiccant dehydration systems are the dehydration systems most commonly used for noncryogenic applications. Liquid dehydration systems have the following characteristics:

Automate easily. Dry gases to moderately low dew points. Easy to operate and maintain. Lower dew points as much as 120F. Susceptible to foaming.

Absorption - Liquid desiccants dehydrate fluids by absorbing the water out of the process stream.




Types - The following four types of glycols are the most common liquid desiccants used for dehydration:

Monoethylene glycol (MEG): generally used for hydrate inhibition.

Diethylene glycol (DEG). Triethylene glycol (TEG). Tetraethylene glycol (TREG).

Figure 1 summarizes the characteristics of the different glycols. Note that TEG is most commonly used for dehydration and that viscosity commonly limits the use of glycols.

GLYCOL TYPES

USES/ APPLICATIONS

ADVANTAGES DISADVANTAGES

MEG Used for hydrate inhibition only

-- --

DEG

First glycol used commercially

Provides reasonable dew point control

Can be regenerated to only 95% MAX

Low thermal degradation temperature

TEG

Glycol most commonly used for dehydration

Requires lower circulation rates than DEG

Can reach lower dew points than DEG (down to -20F in special applications)

Can be regenerated to about 99.95% purity

High viscosity (not used when gas temperature is less than 50F)

TREG

Used when a stripping gas or vacuum regeneration is required

--

High viscosity

Figure 1: Characteristics of glycols




Glycol Dehydration System - Figure 2 shows the process flow of a simple glycol dehydration system. Having passed through the inlet scrubber, the wet gas enters the bottom of the contactor and rises through the contactor trays. Lean glycol enters the top of the contactor and flows down through the contactor trays. As the glycol and wet gas flow against each other, the glycol absorbs water out of the gas stream.

The dry gas leaves the dehydrator through the top of the contactor. The rich glycol leaves the contactor and flows through the still column to the flash drum separator, which degasses the glycol. The flash drum prevents high glycol losses and foaming by removing residual hydrocarbons from the glycol. The rich glycol then flows to the reboiler.

The reboiler heats the rich glycol above the boiling point of water but below the boiling point of the glycol. The water boils off, leaving lean glycol. Finally, the lean glycol flows back to the top of the contactor to begin the cycle again.

Source: EPRCO

Figure 2: Typical glycol dehydration system




Solid Desiccants

Adsorption - Solid desiccants adsorb water molecules onto their surfaces. Adsorption is the physical phenomenon of molecules clinging to a molecular surface. The molecules do not react with the surface material. Instead, van der Waals forces hold them to the surface.

To be effective, solid desiccants need very large surface areas. Solid desiccants gain their large surface areas from their porosity. This porosity results in very large surface-area-to-weight ratios (up to 4 million ft2/lb).

Solid desiccant dehydration systems have the following characteristics:

Best method for processing very sour gases. Cost more than glycol systems to build and to

operate. Reach very low dew points.

Types - The following are the most commonly used types of solid desiccants:

Activated alumina Calcium chloride (consumable, cannot be

regenerated) Molecular sieves Silica gel

Figure 3 summarizes the characteristics of these solid desiccants. However, the following is a brief description of the important characteristics of each solid dessicant. Activated alumina can adsorb up to twice as much water as molecular sieves, but molecular sieves can reach lower dew points than activated alumina. Molecular sieves, however, are the most expensive desiccants. Silica gel adsorbs twice as much water as molecular sieves, but is destroyed by free water.




SOLID

DESICCANTS

ADVANTAGES DISADVANTAGES/

LIMITATIONS

Activated Alumina

Adsorbs twice as much water as molecular sieves for saturated gases

Costs about half as much as silica gel and molecular sieves

Resists physical damage best

Does not adsorb selectively

Silica Gel Adsorbs twice as much water as molecular sieves for saturated gases

Regenerates at much lower temperatures

Not used where free water present (free water destroys silica)

Does not adsorb selectively

Molecular Sieve Possesses high water capacity at low relative humidities.

Produces lowest dew points.

Simultaneously sweetens and dries. Does not coadsorb heavy hydrocarbons.

Most expensive solid desiccant.

More easily contaminated by carryover of amine, glycol, or methanol from upstream.

Average 3-year life in industry. Within Saudi Aramco, up to 10-year life is typical.

Require up to 16% more heat to regenerate.

Where lower dewpoints are necessary, molecular sieves, despite their lower bulk density and lower water capacity (for saturated gases), can require smaller towers due to a significantly smaller mass transfer zone when compared to that of silica gels or activated alumina.

Calcium Chloride

Cannot be regenerated, consumable desiccant

Does not require heat or fuel

Efficient for remote location

Low dehydration capacity

Figure 3: Characteristics of solid desiccants




Solid Desiccant Dehydration System - The dehydration cycle of a typical solid desiccant dehydrator involves the following steps:

Contacting the solid desiccant with the gas stream (typically for 12 to 36 hours).

Drying the solid desiccant with a hot regeneration gas (450F to 600F). The higher the temperature of the regeneration gas, the lower the dew point of the gas stream being dried.

Cooling the solid desiccant with cool regeneration gas.

Solid desiccant dehydration systems normally consist of two, three, or four drying towers. Multiple towers allow the solid desiccant to be cycled without disrupting the flow of the gas stream. For instance, in the two-tower system shown in Figure 4, one tower dries the process gas while the other regenerates the desiccant.

FRC

-Valve open

-Valve closed

Wet feed gas

Inlet separator

Adsorbing

Regeneration gasRegeneration gascompressor

Water knockout

Regeneration gascooler Water

Regenerating and cooling

600F

Regeneration gasheater

Regeneration gas

Drygas

ChE 206.01 009 vgp2/3/93CMP

Source: GPSA

Figure 4: Solid desiccant dehydration system




Hydrate Inhibition

Hydrates form ice-like solids when free water combines with the components of a gas stream. These ice-like solids form at temperatures higher than the freezing temperature of pure water. The ice-like solids can block gas pipelines and accelerate corrosion.

The following conditions promote hydrate formation:

Gas stream at or below its dew point (free water is present). High pressure. Low temperature.

Temperature Control

Hydrate formation conditions may be avoided by carefully choosing where to expand the gas stream or by directly heating the gas stream. When hydrate-forming conditions cannot be avoided, several methods can be used to inhibit hydrate formation. Since free water is necessary for hydrate formation, dehydration also inhibits hydrate formation.

Downhole Regulators - Gas temperatures can be controlled by heating the gas stream or by carefully choosing where to expand a gas stream while the temperature of the gas is still well above its hydrate formation temperature. Downhole regulators are used to monitor gas pressures and prevent pressure drop.

Indirect heaters can be used to control the temperature of a gas stream and inhibit hydrate formation. Indirect heaters are used to heat gas streams at the wellhead and in pipelines.

Methanol Injection

The injection of methanol into gas streams inhibits the formation of hydrates. Because methanol is relatively inexpensive, it generally does not need to be recovered. This simplifies the system and saves the capital expense of a methanol recovery system. Also, methanol's low viscosity makes it useful for cryogenic applications.




Figure 5 shows a simple methanol injection system. The system in Figure 5 inhibits hydrate formation in a choke. It uses a gas powered pump to inject methanol into the gas stream ahead of the choke. This system does not recover the methanol.

Choke

Temperaturecontroller

Power-gas

MeOH

MeOHinjection pointMethanol

Power-gasGas stream

CHE 206.02 005vga/pro fig a11/5/92

.

Source: Dehydration and Hydrate Inhibition; Exxon Production Research Co., Production Operations Division; July

1986; p. 15, Figure 11.

Figure 5: Methanol Injection System




Glycol Injection

Dissolving free water into a solvent lowers the temperature at which hydrates form. The injection of solvents into a gas stream also dehydrates the gas. The design goal of the system, however, is to inhibit hydrate formation. Figure 6 shows a glycol injection and recovery system.

The system shown in Figure 6 inhibits hydrate formation in a choke. The separator removes injected glycol from the gas stream. The reboiler removes the absorbed water from the glycol.

Water vaporvent

Glycoltank

Well

Temperaturecontroller

Glycolinjectionpoint

Choke orpressurereducingvalve

Concentrated glycolsolution to injection pump

Reboiler

Water andglycol

Condensateto tankage

Gas to sales

Three phaseseparator

che 206.01 030vgmm/pro2/3/93

Driver

Pump

Source: EPRCO

Figure 6: Glycol Injection and Recovery system




Glycols are also used to inhibit hydrates. Monoethylene glycol (MEG) is the form of glycol most commonly used to inhibit hydrate formation. Figure 7 compares the characteristics of methanol and glycol injection.

INHIBITORS ADVANTAGES DISADVANTAGES/ LIMITATIONS

Glycol

Usually lower operating cost than methanol when both systems recover injected chemical

Low vapor losses (low volatility)

High initial cost

Possibility of glycol contamination

Limited use (only noncryogenic applications)

Cannot attack (dissolve hydrates already formed)

Methanol

Relatively low initial cost

Simple system

Does not generally need to be recovered

Low viscosity

When injected, distributes well into gas streams

Can attack (dissolve) hydrates already formed

High operating cost

Generally, use glycol injection if methanol injection rate is over 30 gph

Large vapor losses (high volatility)

Figure 7: comparison of Glycol and Methanol as Hydrate Inhibitors




Major Saudi Aramco Dehydration Units

Saudi Aramco liquefies large volumes of natural gas for export. Liquefaction requires the dehydration of the gases to very low dew points and the removal of large volumes of water. Dehydrating with solid desiccants is the most efficient method for most of Saudi Aramco's applications. Saudi Aramco's inventory of solid desiccants is about 4 million pounds.

Saudi Aramco uses molecular sieves to dry NGL gas and activated alumina to dry NGL liquid. In the past, activated alumina suffered short desiccant lives and high coadsorption losses of the heavier hydrocarbons when Saudi Aramco used it to dry hydrocarbon gas. Now, Saudi Aramco tries to use activated alumina only for the drying of hydrocarbon liquids. Addendum A lists Saudi Aramcos major desiccant dehydrators, their desiccant types, and their process flow rates.

Major Saudi Aramco Liquid Desiccant Dehydrators - Saudi Aramco mostly uses solid desiccants to dehydrate gases. The onshore facility at Safaniya, however, uses TEG to dehydrate 860 MMSCFD of natural gas to a water content of 7 lb H20/MMSCF. Additionally, an offshore TEG dehydrator is under construction at Marjan.

Major Saudi Aramco Hydrate Inhibition Units

Generally, Saudi Aramco does not need to inhibit hydrates in its plants and its pipelines. During the winter months, however, hydrates do form in Saudi Aramco plants and pipelines. Because of these intermittent problems, the gas plants at Berri, Shedgum, and Uthmaniya have methanol injection systems installed in case they are needed.




PROBLEMS RELATED TO WATER IN PROCESS STREAMS ASSOCIATED WITH NATURAL GAS PROCESSING AND COMPRESSED AIR FACILITIES

Sources of Water

Most natural gas contains substantial amounts of water. The following are the primary sources of water in natural gas:

Water trapped in the reservoir rock while the rock was being formed.

Water used for extracting oil and gas from wells.

Water Trapped in the Reservoir Rock

Figure 8 shows typical ways in which water, oil, and gas are trapped in rocks. Typically, the gas is trapped between a layer of oil or water and a layer of impervious caprock. The natural gas absorbs water until it becomes saturated.




Gas

Water Oil

Oil Water

Gas

Water

Gas

Oil

OilWater

Gas

ChE 206.01 018vgpro12/4/92

Water

Oil

Source: Katz, Donald L. and Robert L. Lee; Natural Gas Engineering: Production and Storage; McGraw-Hill; 1990; p. 24, Figure 1-13.

Figure 8: Major Types of Reservoir traps




Water Used for Extracting Oil and Gas From Wells

In addition to the water already in the well, natural gas also absorbs the water pumped into wells to extract the oil and gas.

Corrosion In Natural Gas Streams and Compressed Air Facilities

Water accelerates the corrosion processes in natural gas streams and compressed air facilities. Some corrosion does not take place unless water is present. Corrosion must be prevented because it accelerates the wear and tear on equipment.

Blockages In Natural Gas Streams and Compressed Air Facilities

Ice - Water forms ice in natural gas and compressed air streams in low temperature conditions, particularly in cryogenic conditions. Ice can block flow lines and cause blockages in equipment.

Hydrates - At temperatures that are generally above the freezing point of water, hydrates can form in natural gas streams at high pressures and low temperatures. Hydrates can block flow lines and cause blockages in equipment.

Corrosion Products - Can block flow lines and cause blockages in equipment. They also increase the use and cost of filters and separators.

Examples of Problems Caused by Water in Saudi Aramco Process Streams

This section briefly summarizes some of the problems that water has caused in Saudi Aramco gas streams.

In January of 1992, hydrates blocked the supply of fuel gas to the Al-Wusta desalination plant. The sales gas system supplies 450 MMSCFD of fuel gas to this plant.




The Shedgum gas plant supplies fuel gas to the Shedgum power plant and the Saudi cement plant. It also requires fuel gas for its own uses. During the summer, the gas plant can use wet regeneration gas from the dehydrators for fuel without any hydrate problems. As temperatures drop with the approach of winter, however, the formation of hydrates forces the gas plant to use more expensive dry fuel gas instead of wet regeneration gas.

Like the Shedgum gas plant, the Berri gas plant also uses wet regeneration gas for its internal fuel. This use of wet fuel gas also results in occasional hydrate problems. Since the Uthmaniyah gas plant uses dry gas for its internal fuel, it does not suffer hydrate problems.

GOSPs at Abu Ali have had problems with hydrates forming across the hydrocarbon liquid and water level control valves of their high pressure production traps.

During cold weather, Saudi Aramco has also had problems with the formation of hydrates in smaller pipelines and tubing as well as instruments. Since smaller tubing and instruments, such as level indicators, are more exposed and cool down to ambient temperatures more quickly, hydrates form in them more readily.

Dry sales gas has caused virtually no corrosion problems in Saudi Aramco pipelines. The pipelines that carry sour gas and condensate from the GOSPs to the gas plants have experienced some corrosion and metal loss. However, external corrosion threatens Saudi Aramco pipelines more than internal corrosion.




METHODS AND EQUIPMENT USED TO MEASURE THE WATER CONTENT OF NATURAL GAS STREAMS

This section discusses the following methods and equipment used to measure the water content of natural gas streams:

Bureau of Mines Dew Point Tester Cobalt bromide method Electronic moisture analyzers Titration with Karl Fischer Reagents Valve freeze method

Measuring the water content of natural gas streams with dew points less than -40F [less than 10 ppm(wt)], can be very difficult.

Bureau of Mines Dew Point Tester

The Bureau of Mines Dew Point Tester measures the dew point of a gas sample by measuring the temperature at which water begins to condense on a highly polished stainless steel mirror. This tester can measure dew points above 32F with uncertainties as low as 1F, but it can only measure dew points between -80F and -100F with a precision of 4F. The method used with a dewpoint tester is defined by an ASTM standard. Figure 9 shows a Bureau of Mines dew point tester.




100

200 300

400

5000

Deflector

Gas outlet valveChiller outlet

Chiller

Thermometer

Stainless steel mirror

Cooling tube

Mirror

Refrigerant valveCooling tube

Deflector

Gas inlet valve

ChE 206.01 021vgpro12/9/92

Window

Source: Deaton and Frost in Manning, Francis S. and others, Oilfield Processing of Petroleum, Volume One: Natural Gas; PennWell Books, Tulsa: 1991; p. 48, Figure 4-4.

Figure 9: Bureau of Mines Dew Point Tester




As shown in Figure 9, gas enters a high-pressure, stainless steel or nickel plated brass chamber through the inlet valve. The deflector, in the chamber, directs the gas onto the stainless steel mirror and then the gas exits through the outlet valve. Refrigerant in the cooling tube (attached to the chiller) cools the stainless steel mirror. As the stainless steel mirror cools, water in the gas stream condenses on the mirror.

The dew point of the gas is measured by using an exterior mirror to simultaneously observe the interior stainless steel mirror and the thermometer through the window. The temperature at which dew begins to form on the stainless steel mirror is the dew point temperature of the gas stream.

The Bureau of Mines dew point tester can not be operated automatically. The use of the dewpoint tester can be time consuming, and its accuracy depends on operator skill. The following precautions and actions can improve the quality of test results:

Being sure that the dew condensed on the stainless steel mirror is water and not hydrocarbon liquids or glycol.

Cooling the mirror slowly (2F/min.) when within 5F of the dew point of the gas.

Allowing of the mirror to warm and observe at what temperature the dew clears. Compare this result with the test result.

Measuring of the water content at several different pressures.

Removing air from the tester.

Using an illuminated magnifier and /or an LED temperature readout in poor lighting conditions.




Cobalt Bromide Method

Cobalt bromide changes color when moisture contacts it. Therefore, the cobalt bromide method measures the moisture content of propane LPG by intimately contacting it with cobalt bromide. Cobalt bromide changes color at a water content of 25 ppm to 30 ppm.

Briefly summarized, GPA Publication 2140-90 specifies the following procedure:

1. The temperature of the gas is controlled with an ice bath.

2. The cobalt bromide is exposed to the propane LPG at a specified pressure.

3. After a specified time, the color of the cobalt bromide is observed and recorded.

4. If the color is unchanged, the pressure is reduced and the test repeated.

5. If the color is still unchanged, the LPG is considered dry.




Electronic Moisture Analyzers

Aluminum Oxide Humidity Sensor

The aluminum oxide humidity sensor consists of a thin, porous layer of aluminum oxide (Al2O3) sandwiched between two electrodes. One electrode is aluminum and the other is a permeable metal such as gold. This arrangement creates an aluminum oxide capacitor in which the aluminum oxide acts as a dielectric. Figure 10 shows the mechanical construction and a cross-section of an aluminum oxide sensor.

Permeable gold

Pore

Pore base

Aluminum

Anodized (Al203) surface

Gold electrodeAluminum electrode

ChE 206.01 023vgpro12/9/92

Source: TF-2: Aluminum Oxide Moisture Sensor Probe; Panametrics ltd.; Shannon, Ireland; October 1991.

Figure 10: Mechanical Construction and Cross-Section of Aluminum Oxide Sensor




As the aluminum oxide adsorbs water, the impedance of the capacitor changes. The amount of water adsorbed by the aluminum oxide depends on the partial pressure of the water in the sample gas. Therefore, an electronic circuit can be used to measure the water content of the sample gas.

The accuracy of aluminum oxide sensors compares favorably with that of the Bureau of Mines dew point tester. Other advantages of these sensors include their light weight, portability, and continuous measurements and readings. Aluminum oxide sensors are especially suitable for the analysis of very dry gases. The disadvantages of aluminum oxide sensors include slow response times and the relatively difficult removal of contaminants.

Conductivity Cell

Conductivity cells (Hygromat measuring cells) consist of two stainless steel plates separated and electrically insulated by a ceramic layer with eight holes. These holes are partially filled with a hygroscopic salt-glycerin solution. This liquid absorbs water until it and the surrounding sample gas reach equilibrium. The conductivity of the salt-glycerin solution increases as its the water content increases. Conductivity cells offer long term stability (typically better than 4F over 6 months), but the meter must be kept at a constant temperature.

Electrolytic Moisture Analyzers

Electrolytic moisture analyzers are one of the most accurate and fundamental means of measuring water content. They use the adsorption and electrolysis of the water in a sample gas to measure water content. An electrolytic cell consists of two wires spirally wound around the inner wall of an insulating tube. A thin film of phosphorous pentoxide separates the two wires. A semipermeable membrane separates the electrolytic cell and the sample gas.

Figure 11 shows a schematic of the operation of an electrolytic moisture analyzer. In Figure 11, the sample gas flows across the membrane, which absorbs water in the sample gas. The water diffuses into the phosphorus pentoxide film, then the film electrolyzes the water quantitatively. The electrolytic cell then produces a current that is directly proportional to the water-vapor content of the sample gas.




Electrolytic cell Display meter

MembraneSample flow

H2O molecules

ChE 206.01 028vg12/22/92CP

Source: Mayeaux (1987) and Ranarex (1988) in Manning, Francis S. and others, Oilfield Processing of Petroleum, Volume One: Natural Gas; PennWell Books, Tulsa: 1991; p. 49, Figure 4-3.

FIGURE 11: Operation of Electrolytic Moisture Analyzer

Only the ammeter and flow meter of an electrolytic moisture analyzer requires calibration. However, this calibration requires the use of a calibration gas with a known water content. The accuracy of electrolytic moisture analyzers compares favorably with that of the Bureau of Mines Dew point tester. They are also light in weight, portable, give continuous readings, have fast response times, and readily interface with alarms and other process monitors.

On the other hand, electrolytic cells do not work well below 32F and the phosphorous coating is susceptible to contamination. Improved methods of cleaning and recoating, however, are reducing the effects of contamination.




Titration with Karl Fischer Reagents

Titration with Karl Fischer reagents measures the absolute water content (free and dissolved) of a distillate gas. This method is designed especially for measuring gas samples in which free water has settled out. The method measures the absolute water content of a gas by using a dewatered titration solvent. Figure 12 shows a moisture titrator that uses Karl Fischer reagents.

Theory of operation

Reactioncell

Pumphead and checkassembly

Platinumelectrodes

Electroniccircuitry

Flow meter

ExhaustPressurereducing regulator

Reagent supply

Spentreagent

Orifice

Pump

Exhaust

Solenoid valves(normally closed)

Operating pressure inlet

Orifice

Sample inlet

ChE 206.01 022vgpro12/8/92

Source: UGC Industries in Manning, Francis S. and others, Oilfield Processing of Petroleum, Volume One: Natural Gas; PennWell Books, Tulsa: 1991; p. 50, 4-4.

FIGURE 12: Moisture Titrator Using Karl Fischer Reagents




In the titrator shown in Figure 12, the sample gas enters the reaction cell and bubbles through a known quantity of reagent (0.5 mL). The sample gas then exits via the reagent trap, the pressure reducing regulator, and the flow meter. The platinum electrodes sense when the reagent has reacted with all of the water in the sample, the end of the titration. When the sensors measure the end of the titration, they activate the solenoid valves which signal the pump to inject a new sample of reagent into the reaction cell.

Valve Freeze Method

GPA Publication 2140-90 specifies the procedure for performing the valve freeze method. This method is valid for testing propane-type products. It is not valid for propane containing antifreeze agents.

The valve freeze method is a functional test. The method does not test for water content directly. Instead, it tests for an effect of the water, the freezing up of a test valve. Freezeups are a common result of excessive water in LPG streams.

Briefly summarized, GPA Publication 2140-90 specifies the following procedure:

1. The valve is cooled by flowing a liquid-phase sample of propane through it.

2. The valve is closed to allow a predetermined flow rate.

3. The time required for the valve to freeze up and block the flow is measured and recorded.

4. The test is repeated several times to obtain the average time for the valve to freeze up.




CALCULATING THE SATURATED WATER CONTENT OF HYDROCARBON GASES AND LIQUIDS

Factors Affecting Water Content

Pressure, temperature, and composition affect the water content of natural gases. Increases in temperature or pressure increase the saturation water content of a gas, particularly increases in temperature. For instance, changing the temperature of a gas dramatically affects how much water it can hold. Increasing the temperature of a natural gas at 1000 psia from 80F to 90F increases its saturated water capacity by 36%. The saturated water content of a natural gas is decreased when the pressure is increased.

CO2 or H2S can significantly increase the equilibrium water concentration. Figure 13 tabulates the effects of CO2 and H2S on the water content of saturated natural gas. Note the dramatic effect that temperature has on water content.

VOL % H2S VOL % CO2 lb H2O/MMSCF AT 100F

lb H2O/MMSCF AT 200F

0 0 58.9 630 10 10 63.9 - 20 20 71.9 733

Source: Robinson, et al in Kohl, Arthur and Fred Rosenfield; Gas Purification, 4th Ed.; Gulf Publishing Co., Houston; 1985, p. 584, Table 11-1.

FIGURE 13: Effects of CO2 and H2S on Water content at 1,000 PSIA Saturated Water Content of Natural Gas Streams

Methods of determining the water content of natural gases generally fall into one of the three following classes:

Graphs plotting the temperature and pressure of sweet natural gases.




Graphs plotting the temperature, pressure, and acid-gas content of natural gases.

Equations of state with rigorous multicomponent equilibrium calculations that are generally performed on computers.

Graphs Plotting the Temperature and Pressure of Natural Gases

Graphs plotting the temperature and pressure of sweet gases are suitable for many applications. Pressure-temperature graphs estimate the water content for lean, sweet natural gases containing only small amounts of heavy ends. At pressures below 500 psia, these graphs reliably (about 5% average error) predict water contents of gases containing up to about 10% CO2 and/or H2S.

Graphs Plotting the Temperature, Pressure, and Acid-Gas Content of Natural Gases

Graphs plotting the temperature, pressure, and acid-gas content of natural gases adapt pressure-temperature graphs to account for acid-gas content. The method described in Work Aid 1 supplements the pressure-temperature graph used for sweet gases with graphs plotting the water content of H2S and CO2.

Equation 2 in Work Aid 1 relates the graphs plotting the effective water content of H2S and CO2 with the graph that plots water content of sweet natural gases. Equation 2 predicts the water content of gases containing up to about 30% acid-gas components. This equation may give acceptable results when acid-gas concentrations are between 30% and 50%, but it can lead to serious errors when acid-gas concentrations are greater than 50%.

Graphs that plot the water content of acid-gas mixtures can also be used to calculate the water content of sour gases. Instead of calculating an effective water content for each of the CO2 and H2S components, the mole fraction of the CO2 component is converted into an equivalent H2S mole fraction. This is done by multiplying the mole fraction of CO2 by 0.75.




The table in Figure 14 compares the results calculated using these methods and results determined by experiment. Note that some of the calculated results are within 12% of the experimental data, but that some of the calculated results err by almost 300%.

WATER CONTENT, lb/MMSCF

Mixture

F

psig

Experimental

Work Aid 1A Method 1

Work Aid 1A Method 2

11% CO2 89% C1

100 2,000 40.6 39.5 39.2

11% CO2 89% C1

160 1,000 286 276 287

20% CO2 80% C1

100 2,000 40.6 40.8 44.1

20% CO2 80% C1

160 1,000 282 285 287

8% H2S 92% C1

130 1,500 111 111 112

27.5% H2S 72.5% C1

160 1,367 247 303 273

17% H2S 83% C1

160 1,000 292 210 290

30% C1 60% CO2 10% H2S

100 1,100 81 72 NA

9% C1 10% CO2 81% H2S

100 1,900 442 122 NA

Source: Engineering Data Book, Vol. 2, 10th ed.; GPSA; Tulsa; 1987; p. 20-6, Figure 20-10.

Figure 14: Comparison of Calculated and Experimental Water Contents




Addendum C tabulates equivalent water contents in various units of measurement including dew point temperature, ppm(wt), and ppm(vol).

Work Aid 1 describes the procedure and provides the resources required to calculate the saturated water content of hydrocarbon gases and liquids. Sample Problem: Calculating the Saturated Water Content of Hydrocarbon Gases and Liquids Using both methods described in Work Aid 1A, calculate the saturation water content of the inlet gas described below. Given:

Operating line pressure = 2000 psig Gas inlet temperature = 160F Composition of gas stream = 80% methane, 20% CO2 Molecular weight of gas = 21.6 lb/mole

Solution: (Method 1): 1. From Figure 30, the uncorrected water content of the gas

at 160F and 2000 psig is determined to be 170 lb H2O/MMSCF.

2. From Figure 30, the correction factor for gas gravity (MW = 21.6 lb/mole) at 160F is determined to be 0.98.

3. Since the gas is not in equilibrium with brine, CS = 1. 4. The use of Eqn. 1 to determine the corrected water content

of the hydrocarbon component, WHC, results in the following:

WHC = WHC(unc) (CG)(CS) (Eqn. 1)

= (170 lb H2O/MMSCF) (0.98) (1)

= 167 b H2O/MMSCF

5. From Figure 31, the effective water content of the CO2 component (WCO2) is determined to be 255 lb H2O/MMSCF.




6. There is no H2S component. 7. The use of Eqn. 2 to calculate the total saturated water

content of the gas stream results in the following:

(Eqn. 2)

W = yHC WHC( )+ yCO2 WCO2( )+ yH2S WH2S( )= 0. 80 moles HC

mole gas

167 lb H2OMMSCF

+

0.20 moles HCmole gas

255 lb H2OMMSCF

= 185 lb H2O / MMSCF

Solution (Method 2)

1. The use of Eqn. 3 to convert the actual mole fraction of

CO2 to the pseudo mole fraction of H2S results in the following:

yH2S(pseudo) = yCO2 (0.75) (Eqn. 3)

= (0.20 mole CO2/mole gas) (0.75)

= 0.15 mole fraction (pseudo)

2. The use of Eqn. 4 to convert the actual mole fraction of the hydrocarbon to a pseudo mole fraction based on the pseudo mole fraction of H2S results in the following:

yHC(pseudo) = 1 - yH2S - yH2S(pseudo) (Eqn. 4)

yHC(pseudo) = 1.0 - yH2S - yH2S(pseudo)= 1.0 - 0.15 mole (pseudo) H2S

mole gas

= 0.85 mole (psuedo) H2Smole gas

3. From Figure 33, the water content of the gas stream is determined to be 0.49 bbl/MMSCF.

4. The use of Eqn. 5 to convert the units of measure of the water content determined in Step 3 to lb H2O/MMSCF results in the following:

W = Wbbl (H2O) (Eqn. 5)




W = Wbbl H2O( )= 0.49 bbl H2O

MMSCF

350 lb H2Obbl H2O

= 172 lb H2O MMSCF

Answer: Through the use of Method 1, the saturated water content of the gas is calculated to be 185 lb H2O/MMSCF. Through the use of Method 2, the saturated water content of the gas is calculated to be 172 lb H2O/MMSCF.

Equations-of-State Methods

Graphs plotting temperature, pressure, and acid-gas contents do not predict the distribution of the hydrocarbons between hydrocarbon liquid, aqueous liquid, and gas phases. Nor do these graphs predict the water content of hydrocarbon-liquid phases. Calculations that account for distribution across these phases require the use of equations of state.

The Santis-Breedveld-Prausnitz, Nakamura-Breedveld-Prausnitz, and Peng-Robinson equations of state can be used to calculate the water content of a hydrocarbon-rich or inorganic-rich gas in equilibrium with a water-rich liquid. The Soave-Redlich-Kwong and Peng-Robinson equations of state have been used to calculate the water contents of three-phase (water or vapor; water-rich liquid; hydrocarbon-rich liquid) systems.

The use of equations of state to calculate water content is too complex and involved to be done routinely by hand. Therefore, computer programs have been designed to perform these calculations. Generally, these programs produce results that agree very well with experimental results.




Saturated Water Content of Hydrocarbon Liquids

The solubility of water in hydrocarbon liquids is a function of temperature. Therefore, graphs plotting the solubility of water against temperature can be used to determine the water content of hydrocarbon liquids.

Water solubility can be substantially higher in sour hydrocarbon liquids. The accurate estimation of the solubility of water in sour hydrocarbon liquids requires the use of equations of state. Computer programs such as SimSci PRO/II, or Hyprotech HYSIM perform these calculations.

Work Aid 1B describes the procedures and provides the resources required to calculate the saturated water content of hydrocarbon liquids.

The following sample problem demonstrates the use of Work Aid 1B for calculating the saturated water content of hydrocarbon liquids.

Sample Problem: Calculating Saturated Water Content of Hydrocarbon Liquids Given: A new propane coalescer dryer needs to be sized for field installation. Refer to Work Aid 1B and determine the saturated water content of propane leaving a coalescer dryer at 80F.

Solution: From Figure 34, 80F (x-axis) intersects the propane curve at 0.015 lb water/100 lb of hydrocarbon. Answer: The saturated water content of propane at 80F is 0.015 lb water/100 lb of hydrocarbon, or 150 ppm(wt).




WORK AID 1: PROCEDURES AND RESOURCES FOR CALCULATING THE SATURATED WATER CONTENT OF NATURAL GAS STREAMS AND HYDROCARBON LIQUID STREAMS

Work Aid 1A: Procedures and Resources for Calculating the Saturated Water Content of Natural Gas Streams

Method 1

To calculate the saturated water content of a sweet natural gas stream, perform Steps 1 through 4. To calculate the saturated water content of a sour natural gas stream, perform Steps 1 through 7.

1. Use Figure 30 to determine the uncorrected water content of the hydrocarbon components, WHC(unc).

2. Use the graph inset in Figure 30 to determine the

correction factor for gas gravity, CG. 3. If necessary, use the graph inset in Figure 30 to

determine the correction factor for salinity, CS. 4. Use Eqn. 1 to determine the corrected water content of

the hydrocarbon components, WHC.


where:

WHC = Corrected water content of the hydrocarbon components

WHC(unc) = Uncorrected water content of the hydrocarbon components

CG = Factor to correct for gas gravity

CS = Factor to correct for gas salinity




5. If necessary, use Figure 31 to determine the effective water content of the CO2 component, WCO2.

6. If necessary, use Figure 32 to determine the effective

water content of the H2S component, WH2S. 7. Use Eqn. 2 to calculate the total saturated water content of

the gas stream. W = yHC (WHC)+ yCO2 (WCO2) + yH2S (WH2S) (Eqn. 2)

where: W = Saturated water content of gas stream, lb H2O/MMSCF

Wxx = Effective saturated water content of each component, lb H2O /MMSCF

yxx = Mole fraction of component in gas stream





Figure 30: Water content of hydrocarbon gas





Figure 31: Effective Water Content of CO2





Figure 32: Effective Water Content of H2S




Method 2

1. Use Eqn. 3 to convert the actual mole fraction of CO2 to a pseudo mole fraction of H2S.

yH2S(pseudo) = yCO2 (0.75) (Eqn. 3)

where:

yH2S(pseudo) = Mole fraction of CO2 converted to a pseudo mole fraction of H2S

yCO2 = Mole fraction of CO2 in gas stream

2. Use Eqn. 4 to convert the actual mole fraction of the hydrocarbon to a pseudo mole fraction based on the total pseudo mole fraction of H2S.

yHC(pseudo) = 1.0 - yH2S - yH2S(pseudo) (Eqn. 4)

where:

yHC(pseudo) = Pseudo mole fraction of hydrocarbon component (based on the pseudo mole fraction of H2S)

yH2S(pseudo) = Mole fraction of CO2 converted to the pseudo mole fraction of H2S

3. Use Figure 33 to determine the water content of the gas stream. For gas with pressures other than 300 psia, 1000 psia, and 2000 psia, use logarithmic interpolation.





Figure 33: Water Content of Acid Gases (Converted to Pseudo H2S Concentrations)




4. Use Eqn. 5 to convert the units of measure of the water content determined in Step 3 to lb H2O/MMSCF.


where:

W = Water content of natural gas stream, lb H2O/MMSCF

Wbbl = Water content of natural gas stream, bbl H2O/MMSCF

H2O = Density of water, lb H2O/bbl

= 350 lb H2O/bbl H2O




Work Aid 1B: Procedures and Resources for Calculating the Saturated Water Content of Hydrocarbon Liquid Streams

Use Figure 34 to calculate the water content of hydrocarbon liquids.


Figure 34: Solubility of Water in liquid hydrocarbons




WORK AID 2: PROCEDURES AND RESOURCES FOR DETERMINING THE HYDRATE-FORMATION TEMPERATURES OF SWEET AND SOUR GAS STREAMS

Work Aid 2A: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (Gravity Graphic Method)

1. Calculate the weight of component per mole of gas mixture by multiplying the mole fraction of each component by the molecular weight of each component. Record the partial molecular weight of each component in the right column of the table provided with the exercise.

2. Calculate the total molecular weight of the gas mixture. To make this calculation, total the partial molecular weights in the right column of the table provided with the exercise. Record the total weight at the bottom of the right column of the table provided with the exercise.

3. Use Eqn. 6 to calculate the specific gravity (relative to air) of the gas mixture.

sp. gr.(gas) = MWgasMWair (Eqn. 6)

where: sp. gr.(gas) = Specific gravity of the gas stream

MWgas = Molecular weight of gas stream, lb/mole

MWair = Molecular weight of air

= 29 lb/mole

4. Use Figure 35 to determine the hydrate-formation temperature of the gas stream.





Figure 35: Pressure-Temperature Curves for predicting Hydrate formation




Work Aid 2B: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (PRO/II)

A separate PRO/II printout is required for each gas stream composition. Therefore, each exercise provides a printout for the composition of the gas stream to be analyzed. The following procedure details the steps for using a PRO/II printout to determine the hydrate-formation temperature of a gas stream.

1. Locate the intersection of the hydrate formation curve and the operating pressure.

2. Read the corresponding temperature.




Work Aid 2C: Procedures and Resources for Determining the Hydrate-Formation Temperatures of Sweet and Sour Gas Streams (HYSIM)

A separate HYSIM printout is required for each gas stream composition. Therefore, each exercise provides a printout for the composition of the gas stream to be analyzed. The following procedure details the steps for using a HYSIM printout to determine the hydrate-formation temperature of a gas stream.

1. Identify the phase envelope of the gas stream.

2. Identify the hydrate-formation line of the gas stream.

3. Identify the intersection of the hydrate-formation curve and the operating pressure.

4. Read the corresponding temperature.




GLOSSARY

absorption The assimilation of one material into another.

In natural gas dehydration, the use of an absorptive liquid to selectively remove water vapor from a gas stream.

activated alumina A regenerable aluminum oxide base desiccant.

adsorption Adhesion of molecules of gases, liquids, or dissolved substances to a solid surface, resulting in a relatively high concentration of the molecules at the place of contact.

associated gas Associated gas that is recovered during the processing of crude oil is very rich in liquifiable components.

BPOD Barrels per operating day.

butane (C4) C4H10. Light hydrocarbon found in natural gas. Butane is a gas at atmospheric conditions.

calcium chloride A consumable desiccant that cannot be regenerated.

connate water Water retained in the pores, or interstices, of a reservoir formation from the time the formation was created. Connate water is also called interstitial water.

debutanizer A piece of equipment that separates butane, with or without lighter components, from a mixture of hydrocarbons and leaves a bottoms product that is virtually butane free.

DEG Diethylene glycol.

dehydration The act or process of removing water from gases or liquids.




depropanizer A piece of equipment that separates propane, with or without lighter components, from a mixture of hydrocarbons and leaves a bottoms product that is virtually propane free.

desiccant A substance used in a dehydrator to remove gaseous and/or liquid water.

dew point The temperature and pressure at which a liquid begins to condense out of a gas.

dry gas A gas whose water content has been reduced by a dehydration process or a gas containing few or no hydrocarbons commercially recoverable as liquid product. Dry gas is also called lean gas.

ethane (C2) C2H6. Light hydrocarbon found in natural gas. Ethane is a gas at atmospheric conditions.

free water Condensed (liquid) water.

gas processing The separation of constituents from natural gas for the purpose of making marketable products.

glycol A group of compounds used to dehydrate gaseous or liquid hydrocarbons or to inhibit the formation of hydrates.

GOSP Gas-oil separator plant. See oil and gas separator.

heavy ends The parts of a hydrocarbon mixture that have the highest boiling point and viscosity. Hexanes and heptanes in a natural gas stream.

heptanes plus (C7+)

The parts of a hydrocarbon mixture or the last component of a hydrocarbon analysis that contains the heptanes and all hydrocarbons heavier than heptane.




hydrate Ice-like solids that form when free water combines with components in a gas stream. These ice-like solids form at temperatures higher than the freezing temperature of pure water.

interstitial water Same as connate water.

lean gas The residue gas remaining after recovery of natural gas liquids in a gas processing plant. Unprocessed gas containing few or no recoverable natural gas liquids. Lean gas is also called dry gas.

liquefied natural gas (LNG)

Natural gas that has been liquefied for shipping. Requires severe cooling (-256F). Not as easily liquefied as LPG. Requires high pressure and very low (cryogenic) temperatures.

liquefied petroleum gas (LPG)

Butane, propane, and other light ends separated from gasoline or crude oil by fractionation or other processes. Liquefied petroleum gases revert to a gaseous state at atmospheric conditions.

MBOD 1000 barrels of oil per day.

MEG Monoethylene glycol. Also referred to as EG.

mercaptan A compound chemically similar to alcohol in which sulfur replaces oxygen in the chemical structure. Many mercaptans have an offensive odor and are used to odorize gas.

MMSCF Million standard cubic feet.

MMSCFD Million standard cubic feet per day.

molecular sieves Solid desiccants composed of crystalline metal aluminosilicates (zeolites) that can be regenerated.




natural gas A highly compressible and expandable mixture of hydrocarbons having a low specific gravity and occurring naturally in gaseous form. May be found as either a gas or a liquid depending on temperature and pressure conditions.

natural gas liquids (NGL)

Those hydrocarbons liquefied above ground at field facilities or at gas processing plants. Natural gas liquids include propane, butanes, and natural gasoline.

natural gas plant A facility that recovers natural gas liquids (heavier hydrocarbon components including butane and propane) from natural gas.

oil and gas separator

Processing equipment that separates liquid components from gaseous components in a gas stream directly from a well. Separators are either vertical or horizontal and either spherical or cylindrical. Separation usually relies on gravity. The heavier liquids settle to the bottom and the gases rise to the top.

regeneration A process by which a catalyst or a chemical reagent is restored close to its original reactiveness.

rich gas Same as wet gas.

saturated vapor A vapor at its dew point.

sour Hydrocarbon gas containing sulfur compounds such as hydrogen sulfide and methyl mercaptan.

sour gas A gas containing substantial quantities of hydrogen sulfide and/or mercaptans.

specific gravity (gas)

The ratio of the weight of a gas at a specific temperature and pressure to the weight of air at the same temperature and pressure.




stripping The process of removing the more volatile components from a mixture. Stripping sweeps out the volatile components by passing the hot bottoms from a flash drum or tower through a stripping vessel through which steam or inert gas is passed.

sweet gas A gas that has no more than the maximum sulfur content allowed by a sales gas contract or by law.

sweeten To remove sulfur or sulfur compounds from gas or oil.

TEG Triethylene glycol.

TREG Tetraethylene glycol.

van der Waal's forces

Secondary bonds arising from structural polarization. Bonding between atoms caused only by transient electrostatic dipoles.

water dew point The temperature at which water vapor in a gas mixture starts to condense.

wet gas A gas containing water or a gas that has not been dehydrated. Wet gas is also called rich gas.




ADDENDUM

Determine the process load on the gas stream described below. The gas stream is entering a chiller. To determine the process load, perform the following tasks: Use the gravity graphic method to determine the hydrate-

formation of the gas stream.

Use the PRO/II printout shown in Figure 37 to determine the hydrate-formation of the gas stream.

Calculate the water content of the gas stream at the saturation temperature of the inlet gas.

Calculate the water content of the gas stream at the temperature of the chiller.

Determine the process load on a hydrate inhibition system.

- Calculate the rate of water condensed out of the gas stream by the chiller.

- Determine how far below the hydrate formation temperature of the gas stream the chiller temperature is.

The operating conditions of the gas stream are as follows:

Saturation temperature of gas = 80F

Chiller temperature = 47F

Operating pressure = 450 psig

Figure 36 lists the composition of the gas stream.




COMPONENT

MOLE FRACTION

MOLECULAR WEIGHT

lb/mole OF MIXTURE

N2 0.0060 28.0

CO2 0.0004 44.0

H2S 0.00 34.3

C1 0.6094 16.0

C2 0.2134 30.1

C3 0.1222 44.1

i-C4 0.0092 58.1

n-C4 0.0288 58.1

i-C5 0.0039 72.2

n-C5 0.0053 72.2

n-C6 0.0013 86.2

C7+ 0.0001 100.2

Total Gas Stream

1.00 --

Figure 36: Table for Calculating the Molecular weight of the gas stream




Hydrate-Formation Temperature (Gravity Graphic Method)

Determine the hydrate-formation temperature of the gas stream described in Figure 36. Use the gravity graphic method described in Work Aid 2A. Use the right column of Figure 36 to help calculate the specific gravity of the gas stream.

Hydrate-Formation Temperature (PRO/II)

Use the PRO/II printout shown in Figure 37 to determine the hydrate-formation temperature of the gas stream. Refer to Work Aid 2B.

Figure 37: PROCESS Printout of Hydrate-Formation Temperatures




Water Content (Inlet Temperature)

Calculate the saturated water content of the gas stream at the saturation temperature of the inlet gas stream. Use Method 1 described in Work Aid 1A. For this calculation, consider this gas stream to be 100% hydrocarbon. Use the molecular weight that was calculated in Figure 36.

Water Content (Chiller Temperature)

Calculate the saturated water content of the gas stream at the temperature of the chiller. Use Method 1 described in Work Aid 1A. For this calculation, consider this gas stream to be 100% hydrocarbon. Use the molecular weight that was calculated in Figure 36.

Rate of Water Condensed in Chiller

Since the temperature of the chiller is lower than the hydrate-formation temperature (calculated above) of the gas stream, hydrate inhibition or dehydration is required. If hydrate inhibition is to be used, the designer must determine the rate at which the water is condensed. He must also calculate the difference between the hydrate-formation temperature and the chiller temperature. To calculate the rate at which water is condensed (W), subtract the water content of the gas at the chiller temperature (Wchiller) from the water content of the gas at the saturation temperature of the inlet gas (Winlet). This calculation does not account for the condensation of hydrocarbons. If significant quantities of hydrocarbons condense, overall mass balances must be performed to determine the amount of free water formed. To calculate the difference between the hydrate-formation temperature and the chiller temperature (T), subtract the chiller temperature (Tchiller) from the hydrate-formation temperature (TH). Use the hydrate-formation temperature determined with PRO/II.




ADDENDUM A: MAJOR SAUDI ARAMCO DEHYDRATORS

Aramco dehydration facilities

Khurais, Gas Lift for Crude Oil (Currently Mothballed)

Dehydration method: Glycol (TEG) contactor Total gas flow: 50 MMSCFD Number of units: 4 Product gas spec: 8 lbs H2O/MMSCF

Udhailiyah, Gas Lift for Water Production (Currently Mothballed)

Dehydration method: Glycol (TEG) contactor Total gas flow: 720 MMSCFD Number of units: 6 Product gas spec: 1.8 lbs H2O/MMSCF

Abqaiq Plants, 340 (Currently Mothballed)

Dehydration method: Glycol (MEG) injection Total gas flow: 30 MMSCFD Condensers per deethanizer: 1 Product gas spec: 40 F dew point depression

Abqaiq Plant 462 (Currently Mothballed)

Dehydration method: Molecular sieve Total gas flow: 170 MMSCFD Number of dehydrator towers: 2 in adsorption, 1 in

regeneration/standby Product gas spec: 5 ppm(vol) H2O Regeneration gas: Dry deethanizer overheads Adsorption: Downwards Regeneration: Downwards Cooling: Downwards




Safaniya Onshore Facilities

Dehydration method: Glycol (TEG) contactor Total gas flow: 860 MMSCFD Number of units: 3 Product gas spec: 7 lbs H2O/MMSCF

Shedgum Gas Plant (Gas)

Dehydration method: Molecular sieve Total gas flow: 1100 MMSCFD Number of parallel modules: 4 Number of dehydrator towers per module: 2 in adsorption, 1 in regeneration/standby Product gas spec: < 0.1 ppm(vol) H2O Regeneration gas: Dry product gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards

Shedgum Gas Plant (NGL)

Dehydration method: Activated alumina/molecular sieve Total NGL flow: 60 MBOD Number of parallel modules 4 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration Product liquid spec: < 0.1 ppm(vol) H2O Regeneration gas: Dry product gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards

Uthmaniyah Gas Plant (Gas)

Dehydration method: Molecular sieve Total gas flow: 1100 MMSCFD Number of parallel modules: 4 Number of dehydrator towers per module: 2 in adsorption, 1 in regeneration/standby Product gas spec: < 0.1 ppm(vol) H2O




Regeneration gas: Demethanizer overhead gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards

Uthmaniyah Gas Plant (NGL)

Dehydration method: Activated alumina Total liquid NGL flow: 60 MBOD Number of parallel modules: 4 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration Product liquid spec: < 0.1 ppm(vol) H2O Regeneration gas: Demethanizer overhead gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards

Berri Gas Plant

Dehydration method: Molecular sieve Total gas flow: 600 MMSCFD Number of parallel modules: 1 Number of dehydrator towers per module: 3 in adsorption, 1 in regeneration/standby Product gas spec: 1 ppm(vol) H2O Regeneration gas: Dry product gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards

Ju'aymah Fractionation Plant (Ethane)

Dehydration method: Molecular sieve Total ethane gas flow: 90 MMSCFD Number of parallel modules: 1 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration/standby Product gas spec: Not available Regeneration gas: Wet ethane gas Adsorption: Downwards Regeneration: Upwards Cooling: Upwards




Ju'aymah Fractionation Plant (Propane)

Dehydration method: Molecular sieve Total propane LPG flow: 95 MBOD Number of parallel modules: 2 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration/standby Product spec: 3.5 ppm(wt) Regeneration gas: Vaporized propane product Adsorption: Upwards Regeneration: Downwards Cooling: Downwards

Ju'aymah Fractionation Plant (Butane)

Dehydration method: Molecular sieve Total butane LPG flow: 46 MBOD Number of parallel modules: 2 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration/standby Product spec: 2.0 ppm(wt) Regeneration gas: Vaporized butane product Adsorption: Upwards Regeneration: Downwards Cooling: Downwards

Yanbu Fractionation Plant (Propane)

Dehydration method: Molecular sieve Total propane LPG flow: 122 MBOD Number of parallel modules: 2 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration/standby Product spec: 3.5 ppm(wt) Regeneration gas: Vaporized propane product Adsorption: Upwards Regeneration: Downwards Cooling: Upwards




Yanbu Fractionation Plant (Butane)

Dehydration method: Molecular sieve Total butane LPG flow: 58 MBOD Number of parallel modules: 2 Number of dehydrator towers per module: 1 in adsorption, 1 in regeneration/standby Product spec: 2.0 ppm(wt) Regeneration gas: Vaporized butane product Adsorption: Upwards Regeneration: Downwards Cooling: Upwards

Ras Tanura Refinery, Plant 25

Dehydration method: Molecular sieve Total gas flow: 50 MMSCFD Number of parallel modules: 1 Number of dehydrator towers per module: 2 in adsorption, 2 in regeneration/standby Product spec: 2 ppm(wt) H2O Regeneration gas: Dry product gas Adsorption: Downwards Regeneration: Upwards Cooling: Downwards

Ras Tanura Refinery, Plants 9, 10, 16, 40, 490

Dehydration method: Plant 9: molecular sieve Plants 10, 16, 40, 490: activated alumina Total propane LPG flow: Plant 9: 34 MBOD Plant 10: 62 MBOD Plant 16: 27 MBOD Plant 40: 30 MBOD Plant 490: 66 MBOD Number of parallel modules: Plant 9: 3 (1 in standby) Plants 10, 16, 40, and 490: 1




Number of dehydrator towers per module (Plants 9, 40): 1 in adsorption, 1 in regeneration/standby (Plants 10, 16, 490): 2 in adsorption, 1 in regeneration/standby Product spec: Plant 9: 10 ppm(wt) H2O Plant 10: 2 ppm(wt) H2O Plants 16, 40: 5 ppm(wt) H2O Plant 490: 3.5 ppm(wt) H2O Regeneration gas: Vaporized LPG product Adsorption: Upwards Regeneration: Downwards Cooling: Upwards

Figure 38 and Figure 39 summarize Saudi Aramco's major desiccant dehydration units. Saudi Aramco uses mostly mole sieves and activated alumina in its solid desiccant dehydrators.

PLANT/UNIT

TYPE OF SERVICE

FLOW RATE DRYING

SPECIFICATION

Uthmaniyah Gas Plant

Sweet NGL liquid 60 MBOD 0.1 ppm(vol)

Shedgum Gas Plant Sweet NGL liquid 60 MBOD 0.1 ppm(vol)

Ras Tanura #10 LPG (propane) 62 MBOD 2 ppm(wt)



Ras Tanura #490 LPG (propane) 66 MBOD 3.5 ppm(wt)

Figure 38: Major Activated Alumina Dehydration Units




PLANT/UNIT TYPE OF SERVICE FLOW RATE DRYING SPEC (H20)

Shedgum Gas Sweet NGL gas 1100 MMSCFD 0.1 ppm(vol)

Plant Sweet NGL liquid 60 MBOD 0.1 ppm(vol)

Uthmaniyah Gas Plant

Sweet NGL gas 1100 MMSCFD 0.1 ppm(vol)

Berri Gas Plant Sweet NGL gas 600 MMSCFD 0.1 ppm(vol)

Ju'aymah NGL Ethane 90 MMSCFD N/A

Fractionation LPG (propane) 95 MBOD 3.5 ppm(wt)

Plant LPG (butane) 46 MBOD 2.0 ppm(wt)

Yanbu NGL LPG (propane) 122 MBOD 3.5 ppm(wt)

Fractionation LPG (butane) 58 MBOD 2.0 ppm(wt)

Plant Ethane 90 MMSCFD N/A


Ras Tanura #25 Sour gas 50 MMSCFD 2.0 ppm(vol)

Abqaiq Sour gas N/A N/A

Figure 39: Major Molecular Sieve Dehydration Units




ADDENDUM B: EQUATIONS USED IN ChE 206.01


where: WHC = Corrected water content of the hydrocarbon gas component

WHC(unc) = Uncorrected water content of the hydrocarbon gas component

CG = Factor to correct for gas gravity

CS = Factor to correct for gas salinity

W = yHC (WHC)+ yCO2 (WCO2) + yH2S (WH2S) (Eqn. 2)

where: W = Saturated water content of gas, lb H2O/MMSCF

Wxx = Effective saturated water content of each component, lb H2O /MMSCF (from Figure X or Figure Y)

yxx = Mole fraction of component in gas stream

yH2S(psuedo) = yCO2 (0.75) (Eqn. 3)

where: yH2S(psuedo) = Mole fraction of CO2 converted to the psuedo mole fraction of H2S

yCO2 = Mole fraction of CO2 in gas stream

yHC(psuedo) = 1.0 - yH2S - yH2S(psuedo) (Eqn. 4)

where: yHC(psuedo) = Psuedo mole fraction of hydrocarbon component (based on the psuedo mole fraction of H2S)

yH2S(psuedo) = Mole fraction of CO2 converted to the psuedo mole fraction of H2S





where: W = Water content of natural gas stream, lb H2O/MMSCF

Wbbl = Water content of natural gas stream, bbl H2O/

che 206.01 introduction to hydrate inhibition and dehydration

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solid desiccants