1

Gas Processing – State of the Art - Design Guide Line

Mahin Rameshni, P.E. President & CEO, Rameshni &

Associates Technology & Engineering LLC

Gas Treating in gas industries, and in oil and chemical facilities is getting more complex due to emissions

requirements established by environmental regulatory agencies. In addition, increasing demand of using

new wells with complex components and new sources of sour gases is encouraging gas specialists to

look forward to the new technologies, new solvents, and new ways to find solutions. In response to this

trend, gas preconditioning upstream, or final step(s) for gas conditioning downstream of the gas-treating

unit, are emerging as the best options to comply with the most stringent regulations. The final steps of

gas conditioning are a combination of different processes to remove impurities such as elemental sulfur,

solids, heavy hydrocarbons, and mercaptans that current commercial solvents are not able to handle. In

cases where there is no sulfur recovery / tail gas unit installed downstream of the gas plant to destroy

the remaining impurities, meeting the product specification is very crucial. Solvents could be

contaminated with undesired elements, causing plugging, foaming, corrosion, or changing the required

product specification. Over the years, many papers have been presented due to the gas preparation

required prior to any gas treating system. There is no indication, however, of any unique process that is

able to handle all of the impurities.

In cases where sulfur recovery and tail gas units are installed downstream of the gas plant, gas

preconditioning may not be required and most of the impurities will be destroyed in the sulfur recovery

unit. However, with the increasing sulfur content in crude oil and natural gas and the tightening

regulations of sulfur content in fuels, refiners and gas processors are being pushed to obtain additional

sulfur recovery capacity. At the same time, environmental regulatory agencies in many countries

continue to promulgate more stringent standards for sulfur emissions from oil, gas, and chemical

processing facilities. It is necessary to develop and implement reliable and cost effective technologies to

cope with the changing requirements. In response to this trend, several new Claus tail gas technologies

are emerging to comply with the most stringent regulations.

Typical sulfur recovery efficiencies for Claus plants are 90-96% for a two- stage plant, and 95-98% for a

three- stage plant. Most countries require sulfur recovery efficiency in the range of 98.5% to 99.9% or

higher. Therefore, the sulfur constituents in the Claus tail gas need to be reduced further.

The key parameters affecting the selection of the gas-treating and tail-gas cleanup process are:

• Selection of gas preconditioning process upstream or final gas

conditioning downstream of the gas treating unit based on nature

of impurities

2

• Gas pressure and temperature

• Feed gas composition, including H2S content, CO2 and

hydrocarbons, and other contaminants

• Process configuration

• Selection of the dehydration process

• Product specification, such as H2S, CO2, H2O, hydrocarbons, and

mercaptans

• Optimization of the existing equipment

• equired recovery efficiency

• Concentration of sulfur species in the stack gas

• Ease of operation

• emote location

• Sulfur product quality

• Costs (capital and operating)

In response to the above trends, selection of the right tools is very crucial. Those tools could be a “right”

technology, a “right” solvent, a “right” simulator, and a proper economic design with low- energy

consumption to reduce operating and capital costs.

Generic and specialty solvents are being divided into three different categories to achieve sales gas

specifications: 1) chemical solvents 2) physical solvents 3) and physical-chemical (hybrid) solvents. In

other words, regular gas units could be identified as amine units for H2S removal, dehydration process,

turbo expander for deep chilling, and caustic treatment for removing sulfur compounds from liquid

product. Or they could be specified as solvents for H2S Selectivity, solvents for CO2 emoval, and

solvents for organic Sulfur emoval.

Final selection is ultimately based on process economics, reliability, versatility, and environmental

constrains. Clearly, the selection procedure is not a trivial matter and any tool that provides a reliable

mechanism for process design is highly desirable. Acid gas removal is the removal of H2S and CO2 from

gas streams by using absorption technology and chemical solvents.

This paper emphasizes on the selection criteria for gas preconditioning and the final steps of gas

conditioning processes for industry needs.

3

The various gas-treating process technologies with commercialized chemical, physical, and hybrid

solvents to meet the various environmental regulations are presented. This paper also demonstrates

how these processes are chosen based on the selection criteria mentioned above.

The various Claus tail gas-treating technologies developed and commercialized to meet the various

environmental regulations are presented. Depending on the process route selected, an overall sulfur

recovery efficiency of 98.5% to 99.9% or higher is achievable. The latter recovery corresponds to less

than 250 parts per million by volume (ppmv) of SO2 in the offgas going to the thermal oxidizer prior to

its’ venting to the atmosphere.

As the results of the new revolutions in challenging the various solvents and different process

configurations, gas processing in gas industries and refineries has become more complex. In response to

this trend and to comply with the product specifications, more equipment and more process upstream

or downstream of gas processing should be implemented.

The selection criteria for gas processing is not limited to the selection of gas treating configurations by

itself; it is expanded to the selection criteria of more side process / down streams configurations, to

complete the gas processing in order to meet the product specification and to satisfy environmental

regulatory agency requirements.

For instance, if the H2S concentration of gas to the sulfur recovery unit is low, the acid gas enrichment

unit is recommended. Acid gas from the gas-treating unit flows through the acid gas enrichment unit

where the H2S has substantially separated from the CO2 and N2. The stream that is enriched in H2S is fed

to the sulfur recovery unit while the desulfurized CO2 and N2 stream is sent to the thermal incinerator.

Figure 1 represents the basic gas treating and sulfur recovery facilities. Acid gas and liquid sweetening

will be followed by the other process that is shown in figure 1. Liquid sweetening will be discussed in the

following sections.

Figure 1- Basic Gas Treating & Sulfur Recovery Facilities

4

Acid gas removal is the removal of H2S and CO2 from gas streams by using absorption technology and

chemical solvents. Sour gas contains H2S, CO2, H2O, hydrocarbons, COS/CS2, solids, mercaptans, NH3,

BTEX, and all other unusual impurities that require additional steps for their removal.

There are many treating processes available. However, no single process is ideal for all applications. The

initial selection of a particular process may be based on feed parameters such as composition, pressure,

temperature, and the nature of the impurities, as well as product specifications. The second selection of

a particular process may be based on acid/sour gas percent in the feed, whether all CO2, all H2S, or

mixed and in what proportion, if CO2 is significant, whether selective process is preferred for the

SU/TGU feed, and reduction of amine unit regeneration duty. The final selection could be based on

content of C3+ in the feed gas and the size of the unit (small unit reduces advantage of special solvent

and may favor conventional amine).

Final selection is ultimately based on process economics, reliability, versatility, and environmental

constraints. Clearly, the selection procedure is not a trivial matter and any tool that provides a reliable

mechanism for process design is highly desirable.

The variety of the acid gas sources that have different gas compositions, pressure, temperature, and

nature of impurities and might require different means of gas processing to meet the product

specification, are presented in table I.

Table I- Acid Gas Sources

Natural Gas Processing LNG Facilities

Petroleum efining Synthesis Gas Treating

Chemicals and Petrochemicals Coal & Heavy Oil Gasification

LPG Systems Pipeline Dew Point Control

Landfill Gas Facilities Feed to Tail Gas Treating

Ammonia & Hydrogen Plants

Selection of the right tools is very crucial. Establishing and conducting all the elements together at the

same time, would generate such a beautiful art in gas treating.

Natural Gas Processing

Natural gas is one of the common sources of gas treating, with a wide range in CO2/H2S ratios and high

pressure treating. If natural gas is not an LNG application, it could be treated with selective H2S removal

if significant CO2 is present. If C3+ is present, the desirability of using physical or mixed solvents is

reduced. If organic sulfur is present, the desirability of using physical or mixed solvents is increased.

It is favored to use proprietary solvents if natural gas has significant CO2 and /or H2S for large units/ and

to use conventional solvents for small units particularly with modest acid /sour gas levels.

5

Petroleum Refining

Petroleum refining is another source of gas treating with low CO2 content, unless the refinery has

catalyst cracking unit, in which case the gas may contain COS, organic sulfur, cyanides, ammonia, and

organic acids. The acid gas from hydrotreating and hydrocracking essentially contains H2S and ammonia.

The gas treating pressures and H2S specifications vary for individual applications, and MEA/DEA/MDEA

or formulated amines are the typical solvents. The refinery typically has multiple absorbers and a

common regenerator as listed below:

• Fuel gas treating

• Hydrotreater product/fuel gas

• Hydrotreater recycle gas

• Hydrocracker product/fuel gas

• Hydrocracker recycle gas

• LPG liq-liq contactor

• Thermal/catalyst cracker gases

• Services independent or combined as practical

Synthesis Gas Treatment

Synthesis gas treatment is characterized by high CO2 and low (or no) H2S. If the amount of CO2 is limited,

it is preferred to use selective H2S treating via formulated/hindered amine, mixed solvent, or physical

solvent. If H2S is not present and there is modest or essentially complete CO2 removal, it is preferred to

use activated MDEA, hot potassium, mixed amine, and physical solvent.

Data Base Outline

In order to select the optimized process, gas-treating units are divided into several categories and each

one requires different solvents, simulator, or available technology. However, each project is required to

be evaluated with more than one technology in order to meet the project specification, circulation rate,

and duties, which is truly dependent on the gas composition (such as H2S, CO2 and NH3). In addition, the

selected process must be evaluated to make sure it is economic.

Table II represents the most common process being used in gas plant industries.

6

Table II- Data Base Outline

HP Gas Treating System, Bulk CO2 Removal from Natural Gas, and

Selective H2S Removal

Physical Solvent Process (SELEXOL, Murphreesorb, IFPEXOL)

Other Solvent Process (DEA, MDEA, DGA, aMDEA, Sulfinol M/D, Flexsorb, Gas/SPEC *SS, Membrane +

amine, UCASOL, Chevron-IPN, Benfield, K2CO3)

Tail Gas Treating (H2S Recycle & Selective Cat. Oxidation Process

Typical Solvent (MDEA, HS-101/103, Gas/Spec *SS, Sulfinol, Flexsorb)

BS /Amine Process Shell SCOT/ ACO BOC ecycle

esulf Dual-Solve BS / Wet Oxidation

MCC CBA Sulfreen

BS /Selectox BS/Hi-Activity/POClaus Super Claus

Incinerator Tail Gas

Wellman-Lord Clintox Elsorb

Claus Master Cansolv Bio-Claus

Clausorb

Acid Gas Enrichment

Typical Solvent (MDEA, Sulfinol M/D, FLEXSORB, UCARSOL, Gas/SPEC *SS)

Ammonia Plants

Physical Solvents, aMDEA, Hot Potassium, Dow 800 series, etc.

Cryogenic Systems

Chemical Solvents

Enhanced Oil Recovery (EOR)

Chemical & physical Solvents

EOR CO2 Recovery Plants

Similar to Bulk CO2 emoval

Ethylene Plants

Similar to Bulk CO2 emoval

Flash Regeneration CO2 Removal

Similar to Bulk CO2 emoval

7

Hydrogen Plants

Chemicals Solvents

LPG Treating

Chemical Solvents

Oil Refinery Systems

Chemical & Physical Solvents

Dehydration systems

EG, DEG, TEG, Solvents, Methanol, Molecular Sieve Process, etc.

Unusual impurities are on the increase by demand of exploring new sources of the sour gas.

Following are some the unusual impurities that may require additional removal steps in gas -treating.

Feed gas compositions should be evaluated for needs of gas preparation prior entering to any gas plant.

Contaminated gas will damage the solvent and cause plugging, pipeline cleaning of liquids and solids,

corrosion, foaming, and changing product specifications. This paper addresses different aw Gas

Preconditioning and Final Conditioning processes.

• Elemental Sulfur

• Heavy Hydrocarbons (CnHm) & BTEX, such as Benzene & C8+

• COS, CS2, SH, Mercaptans, Hg

• Solids, Carbon

Elemental Sulfur Removal

Several studies have being performed regarding the elemental sulfur removal in gas plant industries.

Elemental sulfur causes the “series” problem within the gas plant such as plugging of exchangers, crystal

forming and contaminating the solvent, and changing the product specifications.

GPSA Engineering Data Book and the Perry and Chilton Chemical Engineering Handbook, show that the

gravity-based scrubbers are not effective for particles smaller than approximately 1 micron, whereas

filtration is effective for particles as small as 0.01 micron.

Sulfur is one of the elements that have a tendency to bond extensively to itself and chains in a similar

fashion to carbon, and produces S8. Chains can break and react with other molecules such as H2S or

produce solid sulfur that is suspended in the water.

Sulfur has the potential to act as a fairly strong oxidizing agent and causes corrosion in stainless steel

equipment.

8

Inline Separator / Filtration System

All gas-sweetening units should have a well-designed inlet separator. Inline separator has been used as a

filtration system to remove the particles and to remove any entrained solids. The inline separator should

be designed not only on the basis of inlet fluid volumes but also on surge capacity to handle slugs of

liquid hydrocarbons, H2O, and well-treated chemicals. In cases where solids or liquids are known or

anticipated to be a problem, a high-efficiency separator such as a coalescing filter separator should be

used.

The second stage of filtration should be performed by using the carbon filter for removing particles

down to 5 microns. The activated carbon filter should always be located downstream because the

deposition of solids would plug the carbon filter and prevent its regeneration.

If the gas is contaminated with the large amount of the elemental sulfur, even more steps should be

taken before entering the gas into the inline separator. Otherwise, inline separator will plug.

The latest filtration system is the implementation of designing the special media for the elemental sulfur

removal. This filter can facilitate the separation of the sulfur in conjunction with simultaneous liquid

aerosol removal. The liquid quantity would be available for assisting the separator, i.e. whether or not

additional water injection ahead of the filter would be necessary. This could be done by simply adding a

water injection upstream of the inlet nozzle. Due to the hazardous (lethal) nature of the gas, it would be

advisable to have the ability to steam or nitrogen-purge a unit that would need to be serviced. Basically,

the installation of this filter provides the ability to simultaneously water-wash the gas while providing

for sub-micron elemental sulfur removal. The filter media allows small liquid droplets to coalesce by

impingement. As larger droplets grow, they become sufficiently heavy to drain through the glass fibers.

To prevent plugging of the glass fibers, a pleated paper of prefilter could be used.

Disposal Solvent Injection

DAD’s and DMDS are well known as the disposal solvents that could be injected to the well to absorb

the elemental sulfur. The rich fluid, which contains elemental sulfur, is disposed and the solvent will not

be regenerated.

Sulfur Scrubbing by Using Chemical Solvent

The elemental sulfur removal is achievable by using absorption oil as a sulfur solvent in sour gas wells to

control sulfur deposition. This solvent is based on a mixture of alkylnaphthalenes diluted in a mineral oil;

both can physically combine with the precipitated sulfur. The solvent will be regenerated and its

behavior in corrosion inhibitors is outlined. This solvent, with an oil-soluble inhibitor having proper

phase behavior, can effectively control corrosion in sour gas wells with high reservoir water production.

Application of a solvent in sour gas wells should satisfy the following important characteristics:

• No corrosion with the well fluid

9

• Sufficient sulfur solubility

• No irreversible reactions with precipitated sulfur

• Stability under conditions

• Low vapor pressure

• Corrosion prevention

• Ability to separate from water

• Suitable uniform quality

• Suitable viscosity

• Ability to be regenerated and recirculated

• Simple recovery of the absorbent sulfur

The liquid is injected at the wellheads and travels by gravity through the annulus. The solvent mixes with

the upcoming gas and formation water and is reproduced by the well fluid. The annulus cross-section

narrows around the couplings of the tubing connectors. At high injection rates, the annulus becomes

partially filled up, forming a liquid column and creating slugs that travel through the tubing.

The produced liquid phases are separated at the surface by 3 three-stage systems consisting of a free-

water knockout drum, a separator, and the scrubber of the glycol dehydrator. The formation-

water/solvent mixture is collected in tanks at each well site.

The temperature decrease shifts the sulfur solubility of the gas to lower values. Depending on the

particular super-saturation of the gas, sulfur precipitation could take place in the cooler. To prevent

plugging of the cooler tubes, a small volume of solvent is injected downstream of the free-water

knockout drum, the sulfur loading capacity is about 30 g/L.

Slug Catchers

If the elemental sulfur content in the feed gas is very high, slug catchers are highly recommended to

remove the elemental sulfur. Slug catchers should be designed with enough capacity to remove all the

particles.

Gravity-Based Scrubber

The elemental sulfur could be removed by using the gravity-based scrubber with a separation flash drum

or settling storage tank that should be sized with sufficient residence time.

10

Heavy Hydrocarbon Removal

During phasing-in of new wells, feed gas is enriched with heavy hydrocarbons and oil. Hydrocarbon

liquids are known to cause foaming in amine systems. It has been found that hydrocarbon liquid may

reside in the piping; however, the liquid flow regime must be evaluated.

Then, the first option is to drain these hydrocarbons from pipelines. This liquid could be drained from a

pipe by installing dip legs at different locations such as at the end of header, and between the final two

branches.

The purpose of carbon filtration removal of hydrocarbon molecules and chemical contaminants, which

promote amine foaming, is to remove hydrocarbons prior to the amine unit.

Selective solvents have a capability of removing trace sulfur compounds, but hydrocarbon losses with

the acid gas are high.

Hydrocarbons have a higher solubility in physical solvent than in water; therefore, a higher physical

solvent concentration should result in an increase in hydrocarbon content in the acid gas. There are

other options could be used for hydrocarbon removal, such as:

• Using physical solvent for gas treating if applicable.

• Draining the heavy hydrocarbons from pipelines prior to gas plant.

• Providing a Water Wash Scrubber (with a separation flash drum

with sufficient residence time, the dissolved hydrocarbon can

gravity-separate from the bulk solution) and using baffles & weirs.

• Providing a gas carbon filter upstream of multi-cyclone separator

and coalescing filter.

• Providing skimming facilities such as skimming pots for flash drums

with sufficient residence time.

• Using mole-sieve bed downstream of the gas treating (mole-sieves

could be designed with multi-beds for the dehydration, aromatic

removal, and Hg removal, etc. in one package).

• Adding one or two fractionation columns within gas treating for the

removal of the remaining hydrocarbons, and to recover the C2-C4

and blend it back to the treated gas to maintain the required

heating value.

• If the amine-based solvent is applicable, some hydrocarbon removal

could be achieved by minimizing the lean amine, running stripper

with lower pressure, and using low circulation rate.

11

• If the sulfur recovery unit is located downstream of the gas plant,

the heavy hydrocarbons and BTEX could be destroyed by designing

a suitable burner to achieve 2,200 °F minimum. If the acid gas

feeding to the sulfur recovery unit has the low percent of H2S (Lean

Gas), oxygen enrichment is recommended.

If the gas has retrograde properties close to its hydrocarbon dew points, it is of particular importance to

minimize pressure losses. Drums could be equipped with proper hydrocarbon condensate withdrawal,

such as skimming pots.

BTEX Emissions

An amine unit operates by contacting an amine solution with the sour gas or liquid feed counter-

currently in an absorber column. H2S and CO2 in the feed are absorbed by the amine in the solution,

and the sweetened gas exits the top of the column. ich amine exits the bottom of the column and is

sent through the regeneration system to remove the acid gases and dissolved hydrocarbons, including

BTEX. The lean solution is then circulated to the top of the absorber to continue the cycle. The

sweetened gas exiting the absorber is saturated by water from its contact with the amine. The

overheads, including BTEX from the amine regenerator column, are sent to a sulfur recovery unit.

The aromatic compounds including benzene, Toluene, Ethylbenzene, and Xylene (collectively known as

BTEX), are included as hazardous factors in air pollutants.

If the raw gas contains appreciable amounts of H2S, a sulfur plant is used to treat the overheads from

the rich amine stripper. This treating normally destroys any BTEX or other hydrocarbons. Several

operating parameters directly affect the amount of BTEX absorbed in an amine unit, such as inlet BTEX

composition, contactor operating pressure, amine circulation rate, solvent type, and lean solvent

temperature.

MDEA absorbs the lowest amount of BTEX compared to DEA and MEA; therefore, it is recommended to

use MDEA where BTEX is observed in the sour gas, (if it is applicable).

Several operating parameters directly affect the amount of BTEX absorbed in an amine unit. These

factors include the inlet BTEX composition, contactor operating pressure, amine circulation rate, solvent

type, and lean solvent temperature. Following is a list of strategies that should be followed to limit the

BTEX emissions from gas plant:

• Minimize the lean amine temperature. The amount of BTEX

emissions in amine systems decreases with an increase in lean

solvent temperature.

• Use the best solvent for treating requirements. (i.e. MDEA absorbs

the lowest amount of BTEX).

12

• Minimize the lean circulation rate. BTEX pick up increases almost

linearly with an increase in circulation rate.

• If the stripper pressure is higher, the overall BTEX emissions are

lower.

Sulfur has the potential to act as a fairly strong oxidizing agent and cause corrosion in stainless steel

equipment.

H2S is very soluble in molten sulfur; so then H2S would be expected from typical solubility’s of gases into

liquids. Sulfur reacts with hydrocarbons to form mercaptans, which are present in sour gas. The high

solubility of sulfur in CS2 has been recognized. Other solvents are oily disulfides, amines, alkanolamines,

and aromatic hydrocarbons. Amines and alkanolamines compounds are extensively used in German

sour-production schemes and depend on the following reaction for taking up sulfur.

NH2 + H2S � NH3 + HS9

Technology has been patented for loop systems using this approach.

Sulfur should be managed and it is reasonable to predict that a suitable chemical base might prevent

sulfur deposition. Acid-base reactions are rapid compared to decomposition reactions and could act to

capture the sulfanes as ionic polysulfides before decomposition occurs.

If water is contaminated with bicarbonate, that water becomes corrosive. This is a suggestion here that

indicates aqueous sodium bicarbonate should be injected into the bottom of the wellbore to control

sulfur deposition until production matures and the formation water takes over.

If the gas containing high levels of sulfur, say more than 10 tons per day is to be removed, then a

regenerable H2S adsorption / desorption process, such as a Claus process for the conversion of the

removed H2S into elemental sulfur, is normally favored.

If less than a few hundred pounds/day of sulfur needs to be removed, fixed beds of chemical absorbents

will remove H2S to any level required. The used catalysts and absorbents can be sold to the metal

recovery industry, and there are no disposal problems.

Integration with Membranes

Membranes are now being used widely for the purification of natural gas containing high levels of CO2.

For instance, it has developed a membrane-based process to separate and recover hydrocarbons,

including propylene and ethylene, from nitrogen and light gases. Unfortunately, the membranes

available presently lack selectivity, and it is not possible to precisely control the rate of diffusion of the

various components present across the membrane. Therefore, it is rare for the stripped gas to meet the

sales gas specification.

13

Integration with Molecular Sieves

Molecular sieves are used extensively to dry natural gas. In this role, they will also remove H2S but

because water is significantly more powerfully bonded than H2S, they are not very effective for the

combined H2S/H2O removal duty.

The new technology is using the molecular sieves as a multi-bed combination, each for a specific duty.

This combination could be a dehydration bed, in addition to a removal bed for heavy hydrocarbon(s),

Hg, or any other impurities that could be effectively selected for removal technology. These beds should

be cost effectively designed.

COS /CS2 Removal

Some of the chemical and physical solvents are capable of removing COS / CS2 at some level; however,

the solvent may not be able to meet the product specification. In that case, using another conditioning

process is feasible. The molecular sieves process could be used for COS / CS2. The amine reclaimer

system is an alternative for COS / CS2. eclaimer operation is a semi-continuos batch operation for

removal of degradation product from the solution and removal of suspended solids and impurities.

eclaimer operates on a side stream of 1-3 percent of total solvent circulation rate. If a physical solvent

is being used for the acid gas removal, COS / CS2 could be improved by increasing the fresh solvent

circulation rate since the semi-solvent is already saturated and providing an additional chiller system

would increase the absorption process.

Any gas treating, including natural gas and refinery offgas, are contaminated with mercaptan and COS.

Any gas-treating unit operates by contacting a solvent solution with the sour gas or liquid feed counter-

currently in an absorber column. H2S and CO2 in the feed are absorbed by the solvent in the solution,

and the sweetened gas exits the top of the column. ich solvent exits the bottom of the column and is

sent through the regeneration system to remove the acid gases, dissolved hydrocarbons, and COS.

Several operating parameters directly affect the amount of COS absorbed in a gas treating unit, such as

inlet COS composition, contactor operating pressure, solvent circulation rate, solvent type, and lean

solvent temperature. The chosen solvent should be capable of absorbing COS in the absorption process

and release the COS to the acid gas in the regenerator. The acid gas from the regenerator is sent to the

sulfur recovery unit to decompose any sulfur compounds, including COS.

Pure physical solvent is particularly effective in a high-pressure system, high-acid gas treatment for

removing H2S, CO2, COS, organic sulfur species, and a wide range of other gas stream contaminates.

Usually, two absorbers are designed with physical solvents, one absorber for H2S removal with semi-lean

physical solvent and another absorber for CO2 and COS removal with lean, pure solvents. If more

absorption of COS is required, additional free-COS, free-lean solvent should be fed to the H2S absorber,

or semi-lean physical solvent has to be cooled prior feeding the H2S absorber.

14

The purpose of the amine reclaiming units is to distill the water and amine from the fouled solution

leaving behind the entrained solids, dissolved salts, and degradation products that cause foaming and

corrosion problems.

The reclaimer is an integral part of a successful amine sweetening process. It normally operates on a

side stream of the lean amine solution leaving the bottom of the stripper column. The temperature of

the reclaimer is to be controlled through the cycle. The presence of COS, CS2, FeSO2, free oxygen, and

other contaminants can poison the amine. In such cases, a reclaimer is often used to regenerate the

degraded amine. Amine degradation depends on different factors. All of the feed to the reclaimer is

assumed to go overhead except the degraded amine. A flash calculation would be essentially impossible

since the composition and properties of the degraded amine vary widely and are never accurately

determined. The reclaimer has only one inlet stream that comes from the reboiler, and two outlet

streams (the reclaimer OVHD and the reclaimer dump). The reclaimer operating temperature is in a

range of 300-350 ° F and, usually, 1-5 percent of the lean amine would be fed to the reclaimer.

Effect of NH3

When small amounts of ammonia are present in the sour gas, nearly all of the ammonia should be

scrubbed from the sour gas by the amine solution. Due to the high solubility of ammonia in water, the

ammonia may build up in the circulating rich-amine solution and present several problems in the

absorber and stripper. Some of the operational problems with ammonia are meeting the project

specification, flood in the stripper, inability to hold the pressure control set points on the condenser or

reboiler.

These problems all have the same root cause. Ammonia is absorbed at the pressure and temperature in

the absorber, rich amine is loaded with ammonia fed to the stripper, and the K value for ammonia in the

condenser is considerably less than one. Therefore, most of the ammonia is vaporized in the stripper,

and is returned in the reflux. This process continues to build up until steady-state ammonia either

overcomes the low K value in the condenser or forces its way to the reboiler against high K value in the

tower.

Dehydration Process

Gas hydrates are crystalline compounds composed of water and natural gas in the pipelines. The

conditions that tend to promote hydrate formation include the following: low temperature, high

pressure, and a gas at, or below, its water dew point with free water present. The formation of hydrates

can be prevented by using any of the following methods:

• Adjusting the temperature and pressure until hydrate formation is

not favored.

• Dehydrating a gas stream to prevent a free water phase.

• Inhibiting hydrate formation in the free water phase.

15

EG, DEG, and TEG are the most widely used solvents for bulk removal of water from natural gas.

Methods of calculations are the K-chart method and Hammer Schmidt’s Equation, which are both

presented in GPSA, 1994, and computer simulation.

Use of amines in aqueous solutions saturates the sweet gas with water vapor, regardless of whether the

entering sour gas is wet or dry.

For some amine processes, this means that a dehydration step necessarily follows sweetening. One

process, which overcomes this shortcoming, is the use of MDEA or DEA in combination with ethylene or

diethylene-glycol.

The combination of amine and glycol will usually do an excellent job in removing acid gas constituents,

but generally does not dehydrate as well as a conventional glycol installation.

Using other technologies, capable of water removal, could be EG injection, methanol-protected cold

processes, hydrate- formation temperature predications, and Cold Finger Drizo. Finally, the molecular

sieve process is an alternative for the dehydration process in addition to removal of other impurities.

The most common amine design configuration includes one single absorber, one single regenerator, and

all related equipment such as pumps, filters, and heat exchangers. Sometimes other configurations

required to be considered to be able to design the gas treating units, in addition to being able to meet

the project requirement. Other considerations are listed below as a reference:

• One single absorber, and one single regenerator

• One single absorber, and several flash stages

• Absorber A in series with absorber B, and single regenerator

• Absorber A/B in parallel with a common regenerator

• Split –flow configuration using absorber A, B, or A/B

• Absorber A/B with two lean amine feeds

• Absorber A/ B and regenerator with side heaters / coolers

• Single –Stage Co-current static mixing element

• Absorber A/B with amine pump-around

• One single absorber, one single regenerator, with amine and Semi-amine split flow

• H2S & CO2 Absorbers, one single egenerator, with amine and Semi-amine split flow

• Molecular sieve process

• Membrane process

Figure 2 represents the typical amine unit configuration. Some of the above configurations are not

common processes; therefore, a brief description follows:

Absorber with pump-around may be used when a gas stream containing, for example nine mole percent

of CO2. In order to reduce the total circulation of the solvent, an internal recycle or pump-around circuit

is used with a heat exchanger to cool the stream. The process enables recovery of 89% of CO2 in the

feed gas.

16

Split- flow may be used to provide a significant reduction in the amount of stripping steam needed. Lean

and semi-lean solvent enters the absorber to sweeten the gas. The partially stripped semi-lean solvent

stream is drawn off the third tray of the regenerator.

Molecular sieve process may be used for selectivity of H2S removal in the presence of CO2.

In this process, the gas passes through one of two to four fixed beds of molecular sieves, where the H2S

along with H2O and organic sulfur compounds are removed from the gas by a process similar to

adsorption. When the bed becomes saturated with H2S, the main gas flow is switched to another bed,

which is freshly regenerated. Twenty percent of the sweet gas is heated to 600 -700 °F, and passed

through the fouled bed to regenerate it. The hot regeneration gas is then cooled and processed by an

amine unit to remove H2S from the regeneration gas. The regeneration gas is sweetened; it rejoins the

main gas stream downstream of the sieve beds.

Liquid Treating

Liquid treating is another amine unit for sweetening hydrocarbon liquids by using DEA, MDEA, or MEA

solvent.

The acid condensate-sweetening unit removes H2S and CO2 from the acid condensate feed by liquid-

liquid contacting the sour condensate with lean solvent such as DEA.

The sour condensate flows through the acid condensate coalesce filter where particulate matter is

removed and entrained water is coalesced and separated. The acid condensate then flows to the acid

condensate contactors where CO2 and H2S are absorbed by the lean DEA solution.

The contactors are liquid-liquid contactors containing 2 or 3 packed sections. The treated condensate

from the acid condensate contactor is washed using a recirculating water wash. The treated condensate

and the wash water are mixed in the water-wash static mixer. The mixer is then coalesced into two

liquid phases and separated in the water-wash separator.

Makeup water is continuously added to the circulating water-wash circuit to control the buildup of DEA

in the wash water and to help maintain the water content of the DEA system. Water is also

continuously withdrawn from the water-wash circuit and mixed with the rich DEA solution.

In this process, liquid hydrocarbon enters the bottom of a packed absorber and lean amine enters the

top of the absorber. Sweet liquid leaves the absorber from the top and rich amine leaves the absorber

from the bottom. The most common liquid–liquid absorbers are packed contactors, jet educator-mixers,

and static mixers. However, other processes such as Merox, Molecular Sieve, KOH, and Iron Sponge

could do the liquid treating process.

17

Generic and specialty solvents are divided to three different categories to achieve sales gas

specification; however, these solvents may be called chemical solvents, physical solvents, and physical-

TO

AC

IDG

AS

FL

AR

E

AC

ID G

AS

TO

SR

U

PU

RG

EW

AT

ER

SW

EE

TP

RO

DU

CT

GA

S

SO

UR

GA

S

SO

UR

OIL

/W

AT

ER

CW

MA

MIN

ED

RA

IN

ST

M

MA

KE

-UP

CO

ND

EN

SA

TE

MA

KE

-UP

CO

ND

EN

SA

TE

CO

ND

Fig

ure

2,

Typic

al A

cid

Gas

Rem

oval D

iagra

m

18

chemical (hybrid) solvents. On the other hand, regular amine units are divided into an amine unit for H2S

removal, molecular sieve dehydration, turbo expander for deep chilling, and caustic treating for

removing sulfur compounds from liquid product, or finally, are divided to:

• Solvents for H2S selectivity

• Solvents for CO2 removal

• Solvents for organic sulfur removal

The primary differences in process by using generic amines are in solution concentrations. MEA is

ordinarily used in a 10 to 20 percent by weight in the aqueous solution. DEA is also used in the 10 to 30

percent by weight in the aqueous solution. DIPA, DGA, and MDEA are used in higher concentrations.

Typical concentration ranges for DIPA and MDEA are 30 to 50 percent by weight in the aqueous solution.

DGA concentrations range from approximately 40 to 70 percent by weight.

Selective H2S Removal2

The absorption of H2S and the selectivity of H2S over CO2 are enhanced at a lower operating

temperature; consequently, it is desirable to minimize the lean amine temperature.

To achieve low H2S slippage in the absorber operating at high pressure, it is necessary to strip the amine

to a very-low H2S loading (typical loading is < 0.01 mole-acid gas/mole amine). Steam stripping occurs in

the regenerator at high temperature and reverses the reactions given above. The steam reduces the

partial pressure of H2S and CO2 over the amine, thus reducing the equilibrium concentration (or loading)

of these components in the amine.

For highly selective H2S removal, solvents by The DOW Chemical Co. (Gas Spec), Union Carbide (Ucarsol),

BASF (aMDEA), EXXON (Flexsorb), and others have been developed that exhibit greater selectivity and

H2S removal to lower treated gas specifications. However, these solvents are MDEA-based solvents.

These solvents have other applications; such as H2S removal from CO2 enhanced oil recovery (O)

enrichment processes.

Solvents for H2S selectivity are used for refinery systems with high CO2 slip, tail gas treating, natural gas

treating, H2S removal from liquid hydrocarbon streams, natural gas scrubbing, and refinery systems with

LPG streams containing olefins.

Bulk CO2 Removal

Solvents for CO2 removal are used for natural gas treaters, landfill gas facilities with high CO2 feed,

ammonia and hydrogen plants, and natural gas or LNG facilities with downstream cryogenic facilities.

MDEA solvent and mixtures of amines can be used for bulk CO2 removal. However, this performance is

19

very sensitive to one or more of the operating parameters, such as liquid residence time on the trays,

circulation rate, and lean amine temperature.

MDEA has a number of properties, which make it desirable for applications such as:

• High solution concentration up to 50 to 55 wt %

• High-acid gas loading

• Low corrosion

• Slow degradation

• Lower heats of reaction

• Low- vapor pressure and solution losses

Amine solvents and physical solvents are used over a wide variety of process conditions, ranging from

atmosphere pressure for refinery off-gas and Claus tail gas treating, to high pressure for natural gas

sweetening.

Amine solution in water is very effective at absorbing and holding H2S and CO2 from weak acids, when

dissolved in water. The weak acids react with the amine base to help hold them in the solution.

Therefore, a chemical solvent (such as amine) is used for these components.

The Hot Potassium Carbonate Process has been utilized successfully for bulk CO2 removal from a

number of gas mixtures. It has been used for sweetening natural gases containing both CO2 and H2S. If

gas mixture containing little or no CO2, potassium bisulfide is very difficult to regenerate, and it is not

suitable.

Physical Solvent Process3

Physical solvents for organic sulfur removal are used to remove sulfur compounds such as carbonyl

sulfide, carbon disulfide, dimethyl disulfide, methyl mercaptan, ethyl mercaptan, and C3- mercaptan. The

feed to the gas treating units are from natural gas and refinery offgas, landfill gas recovery, ammonia

production, coal and heavy- oil gasification, syngas treating, and pipeline dew point control. The physical

solvent has low volatility, low to moderate viscosity, high boiling points, and excellent chemical and

thermal stability.

Acid gas (such as H2S, CO2, CH3SH, CS2, and SO2) is more soluble in these solvents than CH4, C2H6, Co, H2,

N2, and O2. Heavier hydrocarbons and water are also soluble in these solvents. The selectivity of physical

solvents to the acid gases over the hydrocarbons is best achieved by control of solvent polyglyme

distribution, water content, and operating conditions. Physical solubility of components in physical

solvent is related to the ratio of the number of solute molecules and the number of solvent weight,

which decreases the number of molecules per unit mass. Consequently, capacity for the solute is

reduced. Another interesting interaction is the SO2 polyglyme relationship. SO2 is highly soluble in these

solvents by an order of magnitude greater than H2S. The interaction is reversible with a heat solution of

approximately 35 KJ/mol, or roughly twice that of H2S.

20

Sometimes, gas contaminants (like mercaptans and trace sulfur compounds) do not form acids in water

and are relatively unaffected by amine solutions.

To remove these contaminants, we resort to simple absorption in a fluid using a physical solvent. Water

has a small amount of absorption or solubility for mercaptans, but not enough to be effective in meeting

the light specifications. Therefore, solvents that are classified as a “hybrid” solvent are designed to

merge the effects of chemical and physical solvent technologies. This solvent is usually about 20-30%wt

water, 40-60% amine, and 10-40% physical solvent.

Figure 3 represents the typical physical solvent configuration. The configuration should be optimized

based on the acid gas composition. Table III represents the main processes available in gas industries.

Table III- Main Available Processes

Physio-Chemical Physical MIXED SOLVENTS Miscellaneous

Conventional Amines Selexol LE-701 Solids Beds

Proprietary Amines Methanol Sulfinol M/D Chemical Adsorption

Activated Murphree sorb Exxon ange Physical Adsorption

Formulated K2CO3

Hindered Amines Chemical

Hot Carbonate edox

800 Slurries

Table IV represents the solvent capabilities4.

Solvent Meets

ppmv,

H2S

emoves

Mercap.

COS, Sulfur

Selective

H2S

emoval

Solution

Degraded by

MEA Yes Partial No Yes (COS,CO2,

CS2)

DEA Yes Partial No Some (COS,

CO2,

CS2)

DGA Yes Partial No Yes (COS,CO2,

CS2)

MDEA Yes Partial Yes (1) No

21

T

a

b

l

e

I

V

-

S

o

l

v

e

n

t Capabilities

(1) These processes exhibit some selectivity.

(2) Hi-Pure version.

(3) Hydrolysis COS only.

Equilibrium Behavior of Solvents

The design of chemi-sorption processes requires a clear understanding of the equilibrium between the

solvent and the dissolved gas. In general, the solvent consists of an active component, such as an

alkanolamine, together with diluents, physical sorption promoters, and corrosion inhibitors. Because of

the presence of these additional components, the solubility of the dissolved gas is usually given in

moles-of-solute per mole-of-active sorbent known as solvent loading.

At constant solute partial pressure, the solubility of the dissolved gas varies with the liquid

concentration of the active component. Flash calculation for H2S and MDEA shows that the more

concentrated MDEA solution exerts a higher partial pressure at the same solvent loading.

To achieve a specified outlet concentration of the absorbed component in the absorber, it is necessary

that the stripped solvent leaving the regenerator must contain a concentration of solute less than that

which would be in equilibrium with the gas leaving the absorber at the conditions at the top of the

absorber column.

It is known, H2S reacts with aqueous solutions of certain amines at a faster rate than CO2.

In order to account for this selectivity, it is necessary to incorporate tray efficiency into equilibrium state

models for these units. The stage efficiency is a function of the kinetic rate constants for the reactions

between each acid gas and the amine, the physio-chemical properties of the amine solution, the

pressure, temperature and the mechanical tray design variables, such as tray diameter, weir height, and

Sulfinol Yes Yes Yes (1) Some (CO2,CS2)

Selexol Yes Yes Yes (1) No

Hot

Potassium

Benfield

Yes (2) No (3) No No

Iron Sponge Yes Partial Yes

Mol Sieve Yes Yes Yes (1)

Strefford Yes No Yes Yes (CO2 at high

Conc.)

Lo-cat Yes No Yes Yes (CO2 at high

Conc.)

22

weir length. The Murphree Efficiency Equation is known as the most common approach to design the

amine units as well as the equilibrium solubility and phase enthalpy.

Vapor-phase enthalpy is calculated by the Pen-obinson Equation of State, which integrates ideal gas-

heat capacity data from a reference temperature liquid-phase enthalpy, and also includes the effect of

latent heat of vaporization and heat of reaction.

The absorption or desorption of H2S and CO2 in amine solutions involves a heat effect due to the

chemical reaction. This heat effect is a function of amine type and concentration and the mole loading

of acid gases. The heat of solution of acid gases is usually obtained by differentiating the experimental

solubility data using a form of the Gibbs-Helmholtz Equation. The heat effect results from evaporation

and condensation of amine and water in both the absorber and regenerator of liquid enthalpy. Water

content of the sour water gas feed can have a dramatic effect on the predicted temperature profile in

the absorber and should be considered especially at low pressures.

23

Fig

ure

3,

Ty

pic

al

Ph

ys

ica

l S

olv

en

t C

on

fig

ura

tio

n

H2S

AB

S.

CO

2 A

BS

.

SA

LE

SG

AS

H2S

RE

Cyl

DR

UM

L/R

EX

CH

AN

GE

R

LP

C

LP

S

NO

. 1

CO

2R

EC

YC

LE

FL

AS

HD

RU

M

NO

. 2

CO

2R

EC

YC

LE

FL

AS

HD

RU

M

TO

VE

NT

VE

NT

GA

SF

LA

SH

DR

UM

AG

T

O S

RU

FE

ED

GA

S

FIL

TE

RS

EP

AR

AT

OR

CH

ILL

ER

/R

EF

RIG

ER

AT

OR

CH

ILL

ER

/R

EF

RIG

ER

AT

OR

24

Software

The commercial simulation software provided by Hysim/ Hysis, D.B. obinson, and Tsweet, is widely

used in the gas processing industry. All three programs use thermodynamic models that Kent and

Eisenberg develop it. However, each one has been fitted using proprietary data as well. Therefore, the

result of each simulator might be different for the same case. All listed commercial programs claims that

are able to handle any type of generic amine design, but sometimes will not have the same results or

even it is not possible to use them as a suitable tool to solve the entire problem. Therefore, it is wise to

use engineering judgment and to design a gas plant, to meet all gas treating design aspects.

Typical Product Specifications

Table V represents the typical product specifications for refining, gas processing, and tail gas-treating

plants.

Table V- Typical Product Specifications

Refining Gas Processing Tail Gas Treating

Fuel gas treating : 50 to

100 ppmv

CO2 LNG Plant: 50

ppmv

H2S USA: 10 ppmv

LPG: copper strip CO2 General: 2% vol H2S General: 150 to 200

ppmv

H2S : 1 to 4 ppmv

Tendency to Foam at High Concentration

If foaming occurs, it is often caused by some alien compound being introduced into the system, such as

a corrosion inhibitor being injected at the wellhead. Other root causes could be pipeline liquids and

solids entering the amine system through an ineffective, raw-gas preconditioning system, contaminants

in the circulation amine, or dissolved amine degradation products and additives in the system.

Operational problems with amines, including excessive losses, foaming, corrosion, hydrogen cracking

and blistering, are symptoms of poor performance, which can be traced to the accumulation of amine

heat-stable salts. The ion exchange-based process removes both the heat stable salts anions and any

metalcations from any amine system.

Foaming in an amine sweetening process can result in a number of different problems, (e.g. reduced

plant gas, decreased efficiency, specifications cannot be met, and amine losses).

Foaming could be caused from suspended solids, condensed hydrocarbons, amine degradation

products, and overheating of amine or any foreign material such as makeup water, corrosion inhibitor,

etc.

25

Silicon-based, and a few other types of antifoam agents, have been found to work reasonably well in

many cases. Antifoams are surface-active molecules that change the surface tension of liquid to reduce

foaming. In addition, the solution should be kept clean by using adequate mechanical and carbon

filtration, carbon should be changed when it is spent, heat stable salts should be prevented from

building up, and proper metallurgy should be selected.

Corrosion in Amine Unit

Corrosion in amine units (especially in DEA units) needs very special attention for the repair of existing

equipment as well as inspection of the entire unit with the following procedures:

• Initial inspection of repaired equipment

• e-inspection of undamaged equipment

• Equipment and piping requiring examination

• Examination and procedures and methods

• Wet-fluorescent magnetic-particle testing

• Dry magnetic-particle testing

• Shear-wave ultrasonic testing

• Visual testing

• Visual testing

• Surface preparation

For amine units, PWHT is recommended for all carbon steel equipment, including piping, exposed to

amine at service temperature of 180 ° F and higher. Not only the maximum operating temperature but

also effect of heat tracing and steam-out on the metal temperature of components in contact with the

amine should be considered.

Industry experience has shown that many reported instances of ASCC in DEA units have occurred in non-

PWHT carbon steel equipment exposed to temperatures higher than 180 0F. However, some cracking

problems have been reported in DEA units at temperatures below this value.

In some cases, equipment including piping has been known to crack during steam-out, owing to the

presence of amine. Each user company should evaluate the need for PWHT at temperatures below 180 °

F in equipment such as absorbers and contactors.

MEA degrades to form acidic and basic products.

Acidic degradation forms multi-acids and eventually reacts with bases to form heat-stable salts, which

are removed by carbon filtration; however, acids cause corrosion. To reduce or prevent corrosion,

remember to consider the following items:

• Keep contaminants out of unit

• Use filtration, wash feed

• Select adequate metallurgy

26

• Avoid buildup to heat-stable salts

• Design to limit reboiler tube temperatures

• Limit flow velocities

• Avoid air ingress

• The acid gas composition leaving the acid gas removal has an impact on sulfur recovery efficiency.

If the H2S concentration of gas to the sulfur recovery unit is low, the acid gas enrichment unit is

recommended. H2S, hydrocarbons, and ammonia content would establish the criteria for sulfur recovery

designs and efficiency and to overcome the remaining impurities that heritage from acid gas processing.

The conventional sulfur plant could be converted to the oxygen enrichment to process more sour gas

and to destroy the impurities require the higher temperature for destruction at the same time. If the

solvent in the existing gas plant has been changed in order to process more acid gas, the downstream

units such as the SU/TGU need some equipment modifications for capacity expansion. In general

commercially available technologies offer three levels of oxygen enrichment: low-level (up to 28%),

medium-level (up to 45%), and high-level (up to 100%) providing additional capacity of about 25%, 75%,

and 150% respectively. All of the existing major equipment can be reused for low-level oxygen

enrichment. For medium-level oxygen enrichment a specially designed burner is needed. High-level

oxygen enrichment requires the implementation of technology staged or recycle process. The process

involves the addition of a new reaction furnace burner, reaction furnace, and waste heat boiler

upstream of the existing equipment. The solvent in the tail gas unit could also be converted to a more

selective solvent, in order to be capable of processing more acid gas. The process involves the addition

of a new quench circulation pump; quench water cooler, and an amine cooler, to increase the cooling

duty. Otherwise, all of the existing major equipment can be reused.

Using oxygen enrichment with the proper burner design for ammonia and BTEX destruction would allow

the burner to operate with the higher temperature and would destroy the undesired elements. It might

be required to convert the catalyst to TiO2 to destroy the impurities such as COS/CS2.

The design criteria for sulfur recovery units could be the following:

• Higher air/oxygen demand

• Dilution effect on Claus equilibrium

• Dilution effect on vapor loss

• COS/CS2 loss (TiO2 & BS)

The emission level is pending on the selection criteria of the sulfur recovery designs and the tail gas

treating in terms of the oxygen enrichment level and the selection of the special solvent, respectively, to

achieve SO2, CO, NOX, and H2S (10 ppmv max) to the acceptable level.

The operating cost and sulfur product quality is ultimately based on the following items:

• Chemical consumption amine vs. liquid edox

• Catalyst requirement (TiO2 & others)

• Byproducts (water & steam)

27

• Contaminants (liquid edox, bio processes)

• Access to means of disposal (agricultural use & blend-away in a large pool)

Figure 4 represents the sulfur recovery efficiency based on dry H2S content.

The dry H2S content could be calculated prior to design of the sulfur recovery units.

Figure 4 – H2S Content VS. SRU Recovery

Revamp Options

The acid gas processes, sulfur recovery units, and the tail gas units could be evaluated in terms of

reconfigurations, and economic impact to meet the new requirements and increase the capacity as

follows:

• Transition from generic to proprietary solvents in acid gas removal

• Transition from air to oxygen in sulfur recovery units, to increase the capacity and destroy NH3,

BTEX, and heavy hydrocarbons

• econfigure catalyst in the reactors

• Transition from generic to proprietary solvents in tail gas units

• Increase the amine concentration to process more feed gas

• Evaluation of the existing equipment

• Evaluation of the existing plot plan for any addition of the new equipment

• Converting from Strefford Process to amine process

References

90

92

94

96

98

0 10 20 30 40 50 60 70 80 90 100

Reco

very

, %

H2S Content, % dry

28

1. Process Screening and Selection for efinery Acid Gas emoval

Processing, Gupta, and S.., et. al., Energy Progress, 6:4, pp. 239-

47, December, 1986

2. Tertiary Ethanolamines More Economical for emoval of H2S and

CO2, iesenfeld, F.D., et. al., Oil & Gas Journal, pp. 61-65,

September 29, 1986

3. Modeling acid gas treating by using AG physical solvents, Don D.

Zhang Presented at Laurence eid Conference 1999.

4. Gas Processors Suppliers Association, 10th

edition, Volume 2,

Section 21