AMINE GAS TREATING 101
Unique Design Features of Perry Gas Amine Units for Superior Performance
By: Charles R. Perry, P.E.
Chairman Emeritus
Perry Gas Processors, L.P.
Mr. Perry is a 1951 graduate in Chemical Engineering from the University of Oklahoma, where he studied under the
Gas Processing Icons, Professor Laurence Reid and Dr. John Campbell. He became a Registered Professional
Engineer in Texas in 1956. He worked for Union Carbide Chemicals Co. and served 2 years in a Medical Research
Laboratory in the U. S. Army. He then worked 11 years for Sivalls, Inc., designing lease equipment and in
marketing. In 1967, he started his own company as President and CEO, of what became Perry Gas Companies,
Inc. This company was merged with Parker Drilling Co. in 1980, and he remained with the company for another
two years. Mr. Perry has authored many technical papers regarding Gas Processing, and has been awarded
several U. S. and Foreign patents. He was awarded the Hanlon Award by the Gas Processors Association in 1988,
“for outstanding achievements and contributions to the gas processing industry.” Mr. Perry was also named the
Industry Honoree for the 2012 Permian Basin International Oil Show.
Perry Gas Processors, L.P.
P.O. Box 13,270
Odessa, Texas 79768
432-332-0100
Copyright © 2015 Charles R Perry All Rights Reserved
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PREFACE: The predecessor paper to “Amine Gas Treating, 101,” regarding the design of gas
treating units, was written first in 1973 and was entitled “Fundamentals of Gas Treating.” It was
first presented at what later became, the Laurence Reid Gas Conditioning Conference
(LRGCC), by Charles Perry and V. Wayne Jones, with Perry Gas Companies, Inc. Several
updated versions of this paper were later presented in the following years in the basic sessions
of the LRGCC. As time went by, it became quite popular as a basic gas treating paper, and
numerous copies have been distributed over the years. It was written during the “golden years”
of gas processing when so much of the technology still in use today was first developed.
In recent years, very few overall basic amine treating papers describing new technology have
been written. Many procedures used very successfully in the past have fallen by the wayside,
and/or lost. Gas treating was formerly used primarily to remove hydrogen sulfide. However with
all of the shale gas being developed now, the majority of gas treating today is used to remove
carbon dioxide, both to get Carbon Dioxide down to the normal 2% or less specification to be
sold, or to pre-treat gas for cryogenic processing where Carbon Dioxide not removed may
freeze.
This paper, “Amine Gas Treating, 101,” has been written by Charles Perry for several purposes
including (1) to furnish a basic manual for gas treating; (2) to bring forward treating procedures
used so successfully in the past that may have been overlooked today; (3) to attempt to
recognize new technology that has been developed since the “golden years” in gas processing.
And lastly, as Charles Perry has stated, “It is important that we write down information about gas
treating technology that has worked so well for the industry in years past; I just feel it is
important to get as much of this information as possible written down before my generation is
gone.”
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Table of Contents
Gas Treating in 2015 ......................................................................................................................................5
The Evolution and History of Amine Gas Treating .......................................................................................5
The Amine Process for Gas Treating .............................................................................................................8
Amine Solution Circulations Requirements.................................................................................................12
A Word of Caution about Amine Contaminants and Degradation Products ...............................................14
A.
A Tour Through an Amine Gas Treating Unit ..................................................................................15
1.
Inlet Gas Scrubber(s).........................................................................................................................15
2.
The Contactor ....................................................................................................................................16
3.
Outlet Scrubber .................................................................................................................................17
4.
Outlet Gas Dehydrator ......................................................................................................................18
B. The Flash Tank, Filtration, and Heat Exchange Systems: .....................................................................18
1.
The Flash Tank ..................................................................................................................................18
2.
The Rich Amine Filter System ..........................................................................................................18
3.
The Heat Exchange System ..............................................................................................................21
4.
The Solution Cooler ..........................................................................................................................21
C. The Still, Reflux Condenser, Reflux Accumulator, Reboiler, and Surge Tank Systems: ......................22
1.
The Still .............................................................................................................................................22
2.
The Reflux Condenser.......................................................................................................................24
3.
The Reflux Accumulator System ......................................................................................................24
4.
The Reboiler System .........................................................................................................................25
5.
The Surge Tank System ....................................................................................................................27
D. Amine Unit Pumps: ................................................................................................................................28
E. Automatic Control Panel: .......................................................................................................................29
In Conclusion: ..............................................................................................................................................30
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ILLUSTRATIONS
Figure 1. Simplified Flow Sheet ……………………………………….. 9
Figure 2. Contactor Capacities ………………………………………… 16
Figure 3. The Reboiler System ………………………………………… 22
Figure 4. Still Diameter …………………………………………………. 23
TABLES
Table 1. Flash Tank Sizes Required …………………………………. 18
Table 2. Size Activated Carbon Filters Required …………………… 20
Table 3. Reboiler Design Heat Loads ………………………………… 25
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AMINE GAS TREATING 101
By: Charles R. Perry, P.E.
Gas Treating in 2015
As we look back at the history of gas treating, it is obvious that the majority of the problems in
operating treating units were addressed in the 1970’s, the 1980’s, and the 1990’s. Prior to these
decades, as indicated in the “Evolution of Amine Gas Treating” section below, an “amine treater”
was frequently referred to as “a mean treater,” and oil companies and company personnel
avoided treating sour gas like it was the plague.
Many of these old solutions of the past were never reported in literature and the resolution of
these problems depended on being passed along verbally to future personnel. It has been my
observation that my generation did not do a very good job of passing along these secrets of
good operating practices. This failure to have available these lessons learned in the past, along
with new problems that have developed in recent years, has made operation of current amine
units a much less pleasant experience than it needs to be.
This paper has been prepared to reveal many of the past solutions to operation of “generic”
amine units and to address newer problems that have developed in recent years.
The Evolution and History of Amine Gas Treating
The removal of Acid Gases (CO2 and H2S) from other gases using alkanol amine solutions was
first described in 1930 in U.S. Patent 1,783,901 issued to R. R. Bottoms, and assigned to the
Girdler Corporation. The process was later called the “Girbotol Purification Process,” and was
first used in refineries for purification of refinery fuel gas. By 1939-1940, the Girbotol Process
was beginning to be adapted to treat natural gas.
During the 1940’s, several amine treating plants were built to remove both hydrogen sulfide
(“H2S”) and carbon dioxide (“CO2”) from natural gas, and there were several plants in
commercial operation by the end of the decade.
Various units used monoethanol amine
(“MEA”), diethanol amine (“DEA”), or even triethanol amine (“TEA”). As experience with amine
treating progressed, DEA became the preferred solution for refineries, since it developed fewer
degradation products. MEA became the preferred solution for gas sweetening because it was
able to remove more hydrogen sulfide from gases. And TEA was intriguing in that it appeared
to be selective in removing most of the hydrogen sulfide while leaving most of the carbon
dioxide in the gas being treated. However TEA had difficulty in treating gas to the desired
specifications. Toward the end of the ‘40’s, published articles on amine treating showed that
major problems with amine degradation and corrosion were beginning to occur, and many
technical resources were being committed to solve these problems.
The 1950’s and 1960’s was an era when the early icons in gas treating appeared. To name a
few, they included Laurence Reid, Dr. John Campbell, and Dr. R. L. Huntington from the
University of Oklahoma; Bob Maddox with Oklahoma State University; Jim Conners with Phillips
Petroleum Co.; Fred Zapffe with Lone Star Gas Co.; Bill Pearce with Dow Chemical Co.; Les
5
Polderman, Bob Blake, Don Wonder, and Ken Buttwell with Union Carbide Chemical Co.; Bob
Smith with Travis Chemical Co., Calgary; Andy Younger with Dome Petroleum Co., Calgary; Art
Kohl with Flour Corp.; and I guess I should include myself, Charles Perry with Perry Gas
Processors, Inc. All of these gentlemen wrote and published numerous papers and books on
amine treating. These published articles addressed most of the known problems in amine
treating and suggested solutions for these problems. This vast amount of technical information
and articles published in this era became the basis for the technology used today for designing
amine treating units. And many of these articles are still current today.
The reputation of amine gas treating units during this period was one of difficult operations and
trouble. Operators of an amine unit frequently referred to them as “a mean unit,” instead of “an
amine unit.” At the time that Perry Gas Processors started its business by specializing in amine
gas treating units in 1967, very few gas system operators, or lease surface equipment
manufacturers had any desire to build or operate these “a mean units.” In 1968 Perry Gas
Processor’s made its first attempt to lease an amine gas treating unit to a major oil company,
but the company declined and said that their personnel had no interest is spending the amount
of time necessary to keep one of these units running. So Perry Gas suggested an arrangement
under which a unit would be leased to the company and would include operation of the unit by
Perry Gas personnel, with compensation based on a fee per MCF actually processed. This
major company liked this suggestion, and they asked for a proposed contract for such an
arrangement. At this time, there had been no installation of amine units to be operated by the
lessor of the unit, so there was no proto-type contract available. Perry Gas prepared a draft of a
proposed contract including the features which, in the opinion of Perry Gas, would accomplish
the intent of the parties, and expected the major company would offer comments and/or
changes which they felt were needed. To the surprise of Perry Gas, this major company
executed the “draft contract” and returned it. And this became the first “contract operated amine
treating unit” installed in the U.S. It was located in Crockett County, Texas, about 10 miles
south of McCamey.
Because this amine unit was the first such unit to be leased with operation included, and with
income to Perry Gas to be totally dependent on its operation and throughput, Perry Gas
developed a design that resulted in the plant operation to be very dependable even when it was
unattended most of the time. It was necessary that Perry Gas design the unit to operate
continuously and with no failures to perform, or else the plant would be uneconomical. But the
success of this plant led to Perry Gas contracting for, and installing numerous other contract
treating plants. It also led to Perry Gas publishing a technical paper entitled, “Design and
Operating Amine Units for Trouble Free Unattended Operation,” which was presented at the
1969 Gas Conditioning Conference in Norman, Oklahoma.
During this time, MEA was used almost exclusively for treating natural gas, where outlet
specifications called for gas containing no more than 0.25 grains of H2S per 100 std. cu. ft. of
gas (or 4 ppm.) Refinery fuel gas treating units for refinery fuel gas (which always contained
numerous trace contaminants), mostly used DEA in a water solution due to DEA being less
susceptible to forming degradation products with the contaminants in the gas. For refinery fuel,
there were no formal specifications for how much hydrogen sulfide the outlet gas could contain,
so no one was really concerned, and gas containing 25 grains of H2S per 100 std. cu. ft. was
acceptable. So the conventional wisdom was that DEA was not suitable for treating natural gas
6
because it could not remove hydrogen sulfide down to the required 0.25 grains per 100 std. cu.
ft.
However, DEA offered several advantages over MEA: (1) concentrations of 30% to 50% DEA
could be used with little complications, whereas when concentrations of MEA exceeded 20%,
the solution became corrosive; (2) Acid Gas loading in cubic feet per gallon of the rich amine
could be at least double the cu. ft. of Acid Gas per gallon of solution that could be handled by
MEA; (3) there were fewer contaminants that formed in treating natural gas with DEA than were
formed in MEA; and (4) DEA did not need a side stream reclaimer reboiler to keep the solution
clean. But there was still the concern about whether or not DEA could provide outlet gas with
less than 0.25 grains of H2S per 100 SCF of gas.
In the late 1960’s, reports began to appear of DEA being used to treat high pressure gas outside
of the U.S. where the outlet H2S content was not as stringent as in the U.S. Then in 1971,
Perry Gas Processors announced plans to build and contract operate its Pyote Plant, as an
MEA plant with 50 MMCFD capacity at 1000 psig operating pressure. Ken Buttwell with Union
Carbide approached Perry Gas with a suggestion that the company consider using 30% DEA,
rather than 15% MEA. The mechanical design of the plant had been completed, and
construction was already underway. After considering all the potential advantages of DEA, and
assessing whether or not H2S could be removed to provide outlet gas with less than 0.25 grains
of H2S, the company decided to take the chance and to charge the plant with 30% DEA and
evaluate its performance. Everyone involved was startled after the plant was started; the outlet
gas was treated to less than 0.01 grains of H2S per 100 std. cu. ft.! Inasmuch as the potential
Acid Gas loading of the amine solution was double what was possible with MEA, the company
re-rated the capacity of the plant with DEA to be 100 MMCFD, with no additions or changes of
the plant equipment. The Pyote Plant was later expanded to 250 MMCFD capacity. The Pyote
Plant was the first large DEA plant for treating high pressure natural gas constructed in the U.S.,
and for many years, was the largest DEA plant in the U.S. (It should be noted that certain Perry
Gas proprietary features in its standard amine plant design were necessary to achieve these
results.)
During the 1980’s, a lot of interest developed in methyldiethanol amine (MDEA) for gas treating.
Sometimes plants were charged with amine solution containing 30% to 60% MDEA only, while
other plants used a solution containing both DEA (25% to 30%) and MDEA (25% to 30%). The
two main attractions for using MDEA were (1) it was somewhat selective in that it could remove
H2S to less than 0.25 grains per 100 SCF, and still let a significant amount of the carbon dioxide
(CO2) slip through with the treated gas, and (2) higher concentrations of MDEA (up to 50%)
could be used allowing heavier loading of the amine solution in terms of cu. ft. of acid gas
pickup per gallon of solution. (MDEA, being a tertiary amine, has a slower reaction rate with
CO2, which probably accounts for the selectivity in letting CO2 slip through.) The main problem
encountered with the MDEA was cost and the ability to achieve theoretical high performance.
However, degradation seemed to be somewhat less when the solution contained at least some
MDEA.
During the 1990’s, chemical companies who manufactured amines began to offer customized
blends of amines which varied somewhat based on the gas composition. Initially the blends
were thought to contain mixtures of DEA and MDEA, along with corrosion inhibitors. As time
7
went by, the customized solutions appear to contain mostly MDEA with certain corrosion
inhibitors and/or reaction accelerators (such as piperazine). A few of these customized
solutions still contained DEA. The main advantage in using these solutions with reaction
accelerators was to achieve higher loadings, particularly of CO2. Inasmuch as these blends are
proprietary and customized, it is necessary to present the chemical company with inlet gas
compositions and pressures, and outlet gas required specifications to obtain the chemical
company’s recommendation of the blend to use. These custom blends are more expensive
than MDEA or DEA alone, but it is claimed that higher loading of acid gas in the solution is
obtainable with less degradation of the amine and less corrosion of the equipment. (It should
be noted that certain Perry Gas proprietary features in its standard amine plant design have
been very successful in minimizing amine degradation and corrosion in both DEA and MDEA
solutions. These necessary features will be discussed later in this manual.)
The Amine Process for Gas Treating
In the broad category of the “Amine Process for Treating Gas,” contaminants that are weak
acids, such as carbon dioxide (CO2) and hydrogen sulfide (H2S), (so called “Acid Gases”), are
removed from natural gas by reacting these weak acids with a water solution of a weak base,
namely, an alkanol amine. This reaction forms a soluble salt (amine carbonate or amine sulfide)
in water solution, which readily decomposes when heated to approximately 225 degrees F. To
complete the process, the amine salts are decomposed with heat and the Acid Gases are
separated from the solution and disposed of, leaving the amine solution to be re-circulated to be
used again for further removal of Acid Gases. The “alkanol amines” which may be used for this
purpose include monoethanol amine (“MEA”), diethanol amine (“DEA”), occasionally triethanol
amine (“TEA”), and/or methyldiethanol amine (“MDEA”).
Although mechanically the process is operated as if it is an absorption-desorption process, it is
not this type of a process. The difference is that instead of “absorption” of the Acid Gases in the
amine solution, the Acid Gases chemically reacts with the amine in solution to form salts of
these Acid Gas components.
8
Figure 1 is a Simple Flow Sheet which indicates the flow through a typical amine unit. The flows
through the amine unit are as follows:
The gas to be processed enters the unit through one or more Inlet Gas Scrubber(s), where
solids and entrained liquid droplets are removed from the inlet gas. Experience has shown that
so-called filter-separators will do the best job of removing suspended solids and liquids
entrained in the inlet gas to be processed. (This inlet scrubbing is the first step in accomplishing
a cardinal principle in treating gas, i. e., “cleanliness is next to Godliness.” As we go through
this manual, the importance of maintaining clean amine solution will be apparent; cleanliness of
the amine solution is the most important thing to assure successful and efficient treating of the
gas.)
After inlet scrubbing, the raw gas being treated is run into the base of the “Contactor,” where this
raw gas contacts “lean amine solution,” which has been stripped of Acid Gases. The raw gas
and the lean amine solution run countercurrent to each other, on either bubble trays (bubble
caps or valve trays) or packing. (The “Contactor” is sometimes referred to as the “absorber,”
but to be technically correct, this vessel is a “Contactor.”) Since the Acid Gases are removed by
a chemical reaction with the amine in the solution, there are two fundamental things to
remember about a chemical reaction: (1), The rate of reaction of the Acid Gases with the amine
is directly related to the temperature of the amine and gas when they come into contact with
each other; a rule of thumb is that the reaction rate doubles for every 10 degrees centigrade the
temperature rises. (From a practical standpoint, the inlet temperature for the gas needs to be
80 degrees F or higher to cause a reaction rate fast enough to remove essentially all of the Acid
9
Gases before the gas exits the Contactor.) (2) The reaction of Acid Gases with amine is
exothermic (releases heat as the reaction occurs.) This means both the gas and the amine
temperatures rise in the Contactor. It is common to find that the temperature about 3 or 4 trays
from the bottom of the Contactor to be at the highest temperature anywhere in the Contactor.
This is referred to as the “temperature bulge” of the Contactor.
Should gas entering the Contactor be at less than 80 degrees F, then it may be necessary to
take steps to raise the inlet gas temperature to above 80 degrees F. Since the lean amine
normally has to be cooled by the Amine Solution Cooler, this represents available heat at no
cost to operation of the amine unit. So a lean amine/inlet gas heat exchanger may be installed
to solve this problem.
Lean gas containing essentially no Acid Gases will exit the Contactor from the top, and the gas
is piped to an Outlet Scrubber. This Outlet Scrubber may collect some water that is condensed
in the outlet gas, but its most important function is to collect any amine solution that carries over
with the outlet gas when foaming occurs, to prevent loosing this amine. This Outlet Scrubber is
piped to dump any liquids collected back into the rich amine solution coming out of the bottom of
the Contactor.
This reaction between the Acid Gases in the raw gas stream to be treated occurs in the
“Contactor.” This weak Acid Gas salt in water solution containing the Acid Gases (the “rich
amine solution”) exits the Contactor through a motor valve controlled by a level controller in the
bottom of the Contactor.
The rich amine solution from the base of the Contactor is run into the inlet of the Flash Tank,
where some dissolved and/or entrained natural gas in the rich solution, as well as a small
amount of acid gas “flashes” out of the rich solution due to a reduction in pressure from the
Contactor pressure to the Flash Tank pressure, (which will normally will run at less than 100
psig.) Most Flash Tanks are horizontal to allow more liquid surface which will allow release of
more flash gas. Some Flash Tanks also have provisions to skim off any liquid hydrocarbons
that may be entrained in the rich amine solution, with a manual drain to remove them. This
hydrocarbon skimming is a backup for removing liquid hydrocarbons, and in no way does it
replace the need for good inlet scrubbing of the raw gas to remove all liquid hydrocarbons
before they ever enter the amine solution system. The gas vented from the Flash Tank will
equal about 150 to 200 SCD per gallon of DEA solution circulated, but it will contain
approximately 50%-90% natural gas. This flash gas may be connected to the burner fuel gas in
order to salvage this fuel and improve overall fuel gas efficiency of the unit.
The rich amine solution, after removal of the flash gas, is piped to the inlet of the full stream
Activated Carbon Filter. This Filter utilizes a patented combination of a coarse (4 X 10 mesh),
low density, deep bed (minimum of 5 ft.), of activated carbon to accomplish both mechanical
removal of minute solids in the amine solution and adsorptive removal of any liquid
hydrocarbons entrained or dissolved in the rich amine solution. (Heat stable amine salts which
are discussed later, [or “HSAS,”] will also coagulate with trace amounts of liquid hydrocarbons
that may still be present in the amine solution. This coagulation containing the HSAS will be
removed along with the hydrocarbons by the Activated Carbon Filter.) This Filter is an essential
device to keep the amine solution “water white” clear. It is also essential that it be installed on
10
the rich amine stream. Iron sulfide and iron carbonate particles are insoluble in the Rich Amine
Solution, and should be removed while they are still insoluble. If they remain in the Rich Amine
Solution stream, then after it is completely stripped of the acid gases, it will reverse the reaction
converting these insoluble contaminants back into soluble iron ions and free acid gases, and
thus these contaminants cannot be removed with filters in the Lean Amine Solution stream.
Rich Amine Solution leaving the Filter will normally be between 80 and 120 degrees F, and is
piped to the Lean/Rich Amine Solution Heat Exchanger, where it exchanges heat with the Lean
Amine Solution from the Reboiler/Surge Tank. Outlet Rich Amine Solution will leave the Heat
Exchanger at approximately 180 to 210 degrees F.
This heated Rich Amine Solution is piped to enter the Still on the third tray from the top (or to an
inlet spreader about 2 feet from the top of the bed in a Still filled with packing.) When the Rich
Amine Solution (which will be at 180 to 210 degrees F) enters the top part of the Still, Acid
Gases will be removed immediately and rise through the 2 top trays, where it is washed by the
reflux from the Reflux Accumulator, which will be mostly water. (The overhead vapor from the
Still is cooled in the Air Cooled Reflux Condenser, where most of the steam is condensed to
water, and the Acid Gases will remain gaseous. This mixture of water and Acid Gases enters
the Reflux Accumulator where the liquid water containing trace amounts of amine, is separated
from the Acid Gases, and is pumped back into the Still to furnish “reflux” on the top two trays of
the Still.) This reflux water on the top two trays is very important to reduce amine losses in the
unit. It will remove all but minute traces of amine vapors from the Acid Gas-Steam mixture
rising through the top section of the Still, which will almost completely eliminate amine losses
with the Acid Gases vented.
The Rich Amine Solution will drain through the lower trays (or packing) of the Still countercurrent
to steam vapor rising from the Reboiler. This steam will heat the Rich Amine Solution to 250 to
260 degrees F in the Still, and will furnish the heat to decompose the remaining amine salt of
Acid Gases and amine for this endothermic (heat absorbing) reaction.
It is very important that the Reboiler furnishes enough steam to accomplish this all in the Still. If
the Reboiler is generating insufficient steam, Acid Gas stripping will move all the way down into
the Reboiler. Should this occur, the Lean Amine Solution will no longer be sufficiently stripped
of Acid Gases to allow complete removal of Acid Gases from the Raw Inlet Gas Stream in the
Contactor. Also, the high concentration of Acid Gases in the Reboiler will be extremely
corrosive on the Reboiler shell and firetubes. Generally, if the Still head temperature is
maintained at 190 degrees F or higher, then the Acid Gas stripping will only occur in the Still and
will not slide into the Reboiler. Should the stripping occurring in the Still slip down into the
Reboiler, then it may be necessary to shut the plant down completely and restart and circulate
the solution for a while with enough Reboiler heat to assure that the Acid Gas stripping occurs in
the Still.
The Lean Amine Solution in the Reboiler will overflow into the Surge Tank Compartment in the
end of the Reboiler. The Surge Tank and Reboiler are equalized in pressure, but the Reboiler
has a baffle which prevents the steam in the Reboiler vapor section from contacting the Lean
Amine Solution in the Surge Tank Compartment.
11
Lean Amine Solution from the Surge Tank Compartment at approximately 250 degrees F. flows
to the Lean/Rich Heat Exchanger where it exchanges heat with the Rich Amine Solution,
heating the Rich Amine Solution to about 180 - 210 degrees F, and cooling the Lean Amine
Solution from 250 degrees F down to approximately 150 degrees F.
Lean Amine Solution from the Lean/Rich Amine Solution Heat Exchanger is pumped by the
Booster Pump through the air cooled Solution Cooler, and then to the suction of the Main
Solution High Pressure Pump(s). These Pump(s) then pump the Lean Amine Solution back to
the top tray of the Contactor, where the cycle starts over again.
This is an overall description of how the “Amine Gas Treating Process” works. The function of
each component in the Amine Gas Treating Unit will be explained and discussed in detail later
in this manual. Refer now to Figure 1, which is a schematic diagram of a flow sheet of a
standard amine treating unit. You will need to refer to Figure 1 periodically as you read through
the rest of this manual.
Amine Solution Circulations Requirements
Amine Solution circulation is the heart of amine gas treating. Beginning with the solution itself,
only de-mineralized water should be used for makeup in the amine solution, in order to minimize
dissolved solids which would otherwise buildup in the Amine Solution. (A small amount of the
water in the Amine Solution is lost continuously by evaporation. Therefore any dissolved solids
in the makeup water will tend to concentrate in the solution as replacement make-up water is
added.)
Obviously, equal care should be taken to minimize any contaminant buildup from the amine
makeup. Makeup amine should be stored in a separate clean tank dedicated to amine for
makeup only.
In working with the following Amine Solution circulation formulas, it will be necessary that the
total acid gas content in the gas stream which is to be treated be calculated as volume percent
in the Inlet Raw Gas Stream. CO2 is normally reported as a volume percent in the gas stream.
However, H2S is most frequently reported in “grains of H2S per 100 std. cu. ft. (“SCF”) of raw
gas. To convert this to volume percent, multiply the grains H2S per 100 SCF by 0.0016 to
obtain the volume percent H2S in the gas stream. (If the gas contains 1000 grains/100 SCF
H2S, then it will contain 1000 X 0.0016 or 1.6% H2S. Add the % H2S to the % CO2 to obtain the
total percent Acid Gas in the gas stream.)
The various types of amine available (mentioned above) should be carefully considered to
determine the best available amine for each application. The following discussion describes
when each type amine performs best:
1.
Monoethanol Amine (MEA) is the best amine to use when the Contactor operates at less
than 100 psig and the outlet gas specification is 0.25 grains of H2S per 100 std. cu. ft. MEA
solution should not contain more than 20% MEA, and preferably should be 15% or less to
minimize corrosion in the system. Optimal, safe acid gas pickup by MEA solutions should be
12
based on reacting 0.33 lb. molecular weight of acid gas with each lb. molecular weight of MEA.
Amine solution circulation required may be calculated with the following formula which is based
on 0.33 mol of acid gas pickup per mol of MEA:
GPM = 40.2 Q (x/z)
Where:
GPM = gallons per minute per of amine solution
circulation required
Q = MMCFD of Inlet Gas processed
x = Inlet percent Acid Gas in the gas stream being treated
z = weight percent MEA in the amine solution
2.
Diethanol Amine (DEA) is the most universal amine to use. While its Acid Gas pickup
capacity is somewhat lower than MDEA, it is considerably less expensive, and in most cases,
the amine plant being used will have sufficient excess capacity to provide enough extra
circulation to treat the gas stream. DEA solutions will provide outlet H2S concentrations of less
than 0.25 grains H2S per 100 SCF so long as the contactor pressure exceeds 100 psig. DEA
may be utilized in concentrations of 30% to 50%, but the optimum concentration is around 35%.
(Note: pure DEA will freeze at 68 degrees F. For convenience, DEA is normally stored and
shipped with 10% water dissolved in it which lowers the freeze point to -12 degrees F.) DEA
does not tend to form corrosive components like MEA does, so the higher concentrations of
DEA in the solution will perform satisfactorily. Maximum, safe Acid Gas pickup by DEA
solutions should be based on reacting 0.7 lb. molecular weights of Acid Gas with each lb.
molecular weights of DEA, assuming extra clean amine solution is maintained. Amine solution
circulation required may be calculated with the following formula which is based on 0.7 mol of
acid gas pickup per mol of DEA:
GPM = 33.1Q (x/z)
Where:
GPM = gallons per minute of amine solution
circulation required
Q = MMCFD of gas processed
x = percent Acid Gas in the gas stream being treated
z = weight percent DEA in the amine solution
3.
Methyldiethanol Amine (MDEA) is used to selectively remove H2S down to less than
0.25 grains H2S per 100 SCF, while removing only part of the CO2. It is also used when the only
Acid Gas in the Raw Gas Stream is CO2. MDEA can be used in higher concentrations (up to
60% in water) without being excessively corrosive. This allows heavier Acid Gas loadings for a
given circulation rate which can save on utilities consumed. While its Acid Gas pickup capacity
is higher than DEA, it is considerably more expensive, so overall costs of amine and fuel gas
13
should be carefully estimated and balanced to obtain the most economical treating. MDEA
solutions will provide outlet H2S concentrations of less than 0.25 grains H2S per 100 SCF so
long as the contactor pressure exceeds 100 psig and circulation is adequate. MDEA may be
utilized in concentrations of 30% to 50%, but the optimum concentration is around 40%. MDEA
does not tend to form corrosive components like MEA does, so the higher concentrations of
MDEA in the solution will perform satisfactorily. Optimal, safe Acid Gas pickup by MDEA
solutions should be based on reacting 0.5 lb. molecular weights of Acid Gas with each lb.
molecular weights of MDEA. Amine solution circulation may be calculated with the following
formula which is based on 0.5 mol of Acid Gas pickup per mol of MDEA:
GPM = 50.2 Q (x/z)
Where:
GPM = gallons per minute of amine solution
circulation required
Q = MMCFD of gas processed
x = percent Acid Gas in the gas stream being treated
z = weight percent MDEA in the amine solution
4.
Special Solutions using MDEA, or sometimes mixtures of MDEA and DEA are offered by
various chemical suppliers. Each supplier offers their own Special Solutions which includes
some corrosion inhibitors and/or reaction accelerators to allow even heavier Acid Gas loadings
without risking excessive corrosion of the Amine Unit equipment. Should an operator desire to
use a Special Solution, he should contact the chemical supplier furnishing that Special Solution
for recommended circulation rates and Amine Solution concentrations. However in most cases
of removing CO2 only, a mixture containing 47% to 48% MDEA with some other proprietary
additives will perform very nicely.
A Word of Caution about Amine Contaminants and Degradation Products
As has been emphasized throughout this manual, Amine Units work far better when the Amine
Solution is clean and free of degradation products. This begins with special attention to
removing all solid and liquid contaminants in the inlet gas stream. Makeup amine and makeup
water also require special attention to not allow contaminants to enter with them. And even with
every effort to keep contaminants out of the Amine Solution, over time one can anticipate some
contamination of the Amine Solution. Good filtration of the Rich Amine Solution can remove
what few contaminants that manage to get into the solution.
An operator must be very careful to prevent any strong acids from entering the solution. Strong
acids will react with amines irreversibly to form Heat Stable Amine Salts (or “HSAS.”) HSAS
destroys amine resulting in excessive addition of amine make-up. HSAS also are very
corrosive, resulting in finely divided iron compounds (usually iron oxide, iron sulfide, and/or iron
carbonate) to contaminate the solution.
14
One HSAS which is particularly troubling is the amine salt formed by reacting amine with formic
acid. When amine is exposed to oxygen at high pressures (or carbon monoxide at high
pressures), the amine will react with them to make formic acid which will then react with the
amine to form amine formate. This is a serious enough problem that it is simply unwise to
attempt to treat any gas containing either oxygen or carbon monoxide using any of the amine
solutions.
There is a large amount of literature about amine contaminants and degradation products, and if
there is any problem or contaminant encountered in amine treating, a thorough study of this
literature should be made.
A. A Tour Through an Amine Gas Treating Unit
The Amine/Gas Contactor System:
The Amine/Gas Contactor System is composed of (1) Inlet Gas Scrubber(s), (2) the Contactor
vessel, (3) Outlet Gas Scrubber(s), and (4) an Outlet Gas Dehydrator.
1. Inlet Gas Scrubber(s)
Inlet Scrubbers are not normally included in packaged amine treating units, other than if there may be an
integral Scrubber located in the base of the Contactor. Normal design pressure for Inlet Scrubbers is 1000
or 1200 psig. Good Inlet Scrubbers are essential and are necessary to satisfactorily treat gas. It is
absolutely essential that any solids or liquids entrained in the Raw Inlet Gas Stream be removed from the
gas before it enters the Contactor. Combination filter/separators are the preferred equipment to be sure all
entrained liquids and solids are removed from the gas before it enters the Contactor. Inlet scrubbing is so
important that a “backup” Inlet Scrubber between the main Inlet Scrubber and the Contactor (such as the
integral Inlet Scrubber in the base of the Contactor) may be desirable to also be installed, to provide
redundant inlet scrubbing. The dump lines from the Inlet Scrubber(s) typically are dumped to a waste
storage tank. If the gas is rich and the liquids collected are mostly condensate, it may be desirable to
connect the dumps to condensate storage tanks.
Accessories should include the following:
One Safety valve sized to relieve the full inlet gas design flow
One Scrubber Liquid Level controller, with either internal float, or caged
external float.
One Scrubber liquid outlet throttling motor valve (controlled by above Level
Controller)
One set of gauge cocks and gauge glass
One temperature indicator
15
2. The Contactor
The Contactor is a vertical high pressure column (design pressure of 1000 to 1440 psig with
1/16 inch corrosion allowance, and stress relieved), with 20 trays minimum installed for MEA,
DEA, or MDEA treating. The diameter of the column should be sufficiently large to allow the
column to operate at less than 70% of both vapor and liquid flood points when fully loaded with
the unit design quantity of gas. MDEA reacts more slowly with the Acid Gas components, so
more trays may be needed for MDEA to allow longer contact time of the amine solution with the
gas, usually for a total of 24 to 26 trays. Inasmuch as amine solutions have a tendency to foam,
tray spacing should always be 24 inch minimum. Also, amine Contactors have varying loads of
Inlet Gas, and valve trays are the preferred trays to accommodate the varying loads
encountered in amine Contactors. Tray downcomers should be large enough to provide 7
seconds retention time (based on the downcomer being full) for the Amine Solution, to allow
adequate time for the entrained gas to disengage from the Amine Solution.
Figure 2 below is a graph which indicates Contactor capacities for various diameter Contactors
at various operating pressures:
Figure 2: CONTACTOR CAPACITIES
45
48 inch
40
35
42
MMCFD Capacity
30
25
36 inch
20
30
15
10
24
5
20
16
0
100
300
500
700
900
Contactor Pressure, PSIG
16
1100
Contactor vapor disengaging area above the top tray should have a height equal to three
times the tray spacing. At the top of this disengaging space, just below the top head seam, a six
inch wire mesh mist extractor should be installed.
The bottom of the Contactor deserves similar scrutiny as does the top. Normally, the bottom
tray downcomer will be about 6 inches longer than the rest of the downcomers, and will have a
seal pan on the bottom of it. It is critical that inlet gas flow velocity not affect the operation of
this bottom downcomer and seal pan. This can be accomplished with a flow diverter over the
gas inlet nozzle, and/or with a baffle to prevent gas flow around the downcomer and seal pan. It
is also desirable to provide a horizontal baffle to provide the Rich Amine Solution a quiet settling
space in the bottom to allow breakout of entrained gas from the liquid before it exits the
contactor.
Accessories should include the following:
One Safety valve sized to relieve the full inlet gas design flow
One amine Liquid Level controller, with either internal float, or caged
external float, throttle acting.
One amine solution outlet throttling motor valve (controlled by above Level
Controller)
One set of gauge cocks and gauge glass
Two temperature indicators
3. Outlet Scrubber
An Outlet Scrubber is good “insurance” to recover amine solution carried out the top of the
Contactor when foaming occurs. (It is normally designed for 1000 or 1200 psig pressure.)
Furthermore, it will prevent contamination of the glycol in the Dehydrator on the outlet treated
gas stream. The dump line from the Outlet Scrubber should tie into the Rich Amine Solution
return line, ahead of the Flash Tank. The Outlet Scrubber may be somewhat less sophisticated
than the Inlet Scrubber, but as a minimum, it should include a wire mesh mist extractor, an inlet
diverter, and a horizontal baffle to provide a quiet settling section for any liquids caught by the
Outlet Scrubber.
Accessories should include the following:
One Safety valve sized to relieve the full inlet gas design flow
One Outlet Scrubber Liquid Level controller, with either internal float, or
caged external float.
One Scrubber liquid outlet throttling motor valve (controlled by above Level
Controller)
One set of gauge cocks and gauge glass
One temperature indicator
17
4. Outlet Gas Dehydrator
A Dehydrator is necessary after an amine treating unit. When the gas contacts the amine-water
solution, it becomes fully saturated with water vapor. For the gas to be merchantable, (as well
as prevent line freezes downstream of the amine unit,) the outlet gas must contain no more than
7 lbs. water vapor per million standard cu. ft., which will require a dehydrator. Standard
triethylene glycol gas dehydrators are most frequently used for this service. These units are
readily available from several manufacturers of oil field lease equipment.
B. The Flash Tank, Filtration, and Heat Exchange Systems:
1. The Flash Tank
Normal design pressure is 100 to 150 psig with 1/16 inch corrosion allowance, and is stress
relieved. It may be a horizontal or vertical gas-liquid separator in which the liquid loading is far
greater than the gas loading. The liquid load will determine the sizing of the vessel. Typically,
the liquid retention time in the Flash Tank for design purposes is 5 minutes. The amount of gas
is normally low, so gas vapor space is not critical for horizontal Flash Tanks, but should be no
less than 25% of the ID of the vessel, to allow as much liquid surface as possible and for
minimum liquid depths. This amount of liquid retention time will allow most of the entrained gas
to break out of the liquid.
The following Table 1 provides dimensions of vertical Flash Tanks that will meet the settling
requirements for the Amine Solution in the Flash Tank:
Table 1: FLASH TANK SIZES REQUIRED
GPM CIRCULATION
25
40
60
100
FLASH TANK SIZE REQUIRED
30” OD X 8’ 0”
36” OD X 8’ 0”
42” OD X 10’ 0”
48” OD X 10’ 0”
2. The Rich Amine Filter System
The rich amine filter system is a critical component in an amine unit to keep the amine solution
free of contaminants. (The Filter is normally 100 psig design pressure with 1/16 inch corrosion
allowance, and is stress relieved.) Good filtration is even more important if the amine unit is
equipped with plate and frame heat exchangers to keep the exchangers from plugging.
Although some operators prefer to also have Lean Amine Filters, they should never be
considered a replacement for the Rich Amine Filter. In actual practice, Lean Amine Filters are
not needed and seldom materially improve the cleanliness of the amine solution being
circulated. The successful and dependable operation of any amine gas treating unit will depend
on the unit being equipped with a suitable full flow activated carbon filter, AND, that the filter be
18
operated at all times (unless being regenerated), and that the activated carbon bed be
maintained in good condition. The operator can readily determine whether or not the filtration
system is operating satisfactorily as well as the condition of the bed, by observing the amine
solution to see that it is “water white” and observing changes in the pressure drop across the
filter bed.
There are multiple reasons that Rich Amine Filters are superior to Lean Amine Filters. First is
that fact that most contaminants enter the amine solution with the inlet gas, and the rich amine
solution will be where the greatest contaminant load in the amine solution will be found.
Removing these contaminants as soon as possible after they enter the amine solution prevents
them from causing harm (such as corrosion and/or foaming) to other parts of the amine unit.
There is also another factor that makes filtration of the rich amine solution more desirable: Due
to corrosion, finely divided iron ions will collect in the solution and will form iron sulfide and/or
iron carbonate in the Contactor where the amine solution absorbs the H2S and CO2. Both of
these contaminants are insoluble in the amine solution; however, if near complete stripping of
the H2S and CO2 is occurring in the Still, then these components convert back to soluble iron
ions, and thus cannot be removed by lean amine filtration.
Iron sulfide in the lean amine solution is particularly bad when treating gas to remove H2S. Iron
sulfide particles adsorb and retain other sulfide ions on the surface of the iron sulfide particles.
This prevents stripping them out as H2S in the Still. This results in incomplete stripping of the
H2S from the lean amine solution, resulting in the lean amine solution containing too much H2S,
which makes it very difficult to achieve less than 0.25 grains H2S per SCF in the treated gas.
Thus it is critical to remove essentially all iron sulfide particles from the rich amine solution.
In 1968, Perry Gas Processors saw these and other advantages in having ultra clean amine
solution (“water white” solution) to be able to successfully treat sour natural gas with MEA. At
that time, filtration of amine solution in most commercially available units consisted of a 3% to
5% side stream cartridge type filter. The result of this minimal filtration was dark brown or black
amine solution containing large amounts of entrained solids as well as emulsified liquid
hydrocarbons, all of which were visible in the solution. In addition, the solution undoubtedly
contained considerable amounts of soluble degradation products as well as heat stable salts
(“HSAS”.). Treating gas with this type solution to meet the ridged 0.25 grains of per 100 SCF of
gas specification was at best extremely difficult, and most of the time, was completely
unattainable. Large MEA amine plants were routinely equipped with side stream “reclaimer”
reboilers in which 2% to 5% of the amine circulation was run through a small reboiler in which
the entire side stream was vaporized which left the heavy compounds and solids in this side
stream reboiler kettle. Periodically, these unvaporized contaminants were dumped. This
allowed larger plants to keep the solution clean enough to treat the gas most of the time. But
smaller amine units without reclaimer reboilers were simply down most of the time.
In an attempt to improve the cleanliness of amine solution in its amine treating units, Perry Gas
Processors began to experiment` with different types of filtration utilizing activated carbon.
(Activated carbon filters had demonstrated their ability to sometimes keep amine solutions
clean, but results were not consistent with the many variations of filter systems that were used.)
As a results of these experiments, in 1969 Perry Gas Processors developed and filed for a U.S.
19
patent on a unique filtrations system utilizing a combination of: (1) full stream filtration of the
amine solution being circulated; (2) use of a filtration bed of low density, activated carbon of a
relatively large size (4 X 10 mesh); (3) a deep bed of this carbon (minimum 5 feet); and (4) filter
bed loadings not to exceed 15 gals. per minute per sq. ft. of filter bed cross section. The patent
application claiming this combination to achieve good filtration, was filed on May 7, 1969 and
was granted as U.S. Patent No. 3,568,405 on March 9, 1971. Later, several foreign patents
were also obtained by Perry Gas Processors claiming this design. During this period of time,
Perry Gas Processors refined its operating techniques to extend the filter bed life, thus reducing
costs for using this filtrations system. Operations were based on: (1) The average life of a fresh
carbon bed was about 1 month; (2) a technique was developed to regenerate the bed using 15
psi steam flowing downward through the bed and draining steam condensate along with liquid
and solids removed from the activated carbon through a drain line on the filter; (3) Regeneration
takes about 4 hours, and the condition of the bed after regeneration was almost as if it were
new; (4) the bed could be regenerated 6 to 12 times before it needed to be removed and
recharged with new carbon.
(While steam regeneration of the carbon in the Perry Activated Carbon filters was quite
successful, as time went by, a source of low pressure regeneration steam became a problem;
originally, low pressure truck mounted steam units were used, but the industry stopped using
these for other purposes, and they were phased out.)
(Then in 2013, Perry Gas developed a proprietary process that is a modification of
standard amine units, whereby steam from the amine reboilers is utilized as a source of steam
for regeneration, which worked very well. This does divert some of the reboiler heat from
regeneration, but experience has shown that this diversion of heat is minimal and does not
require any reduction of flow through the unit.)
A description of, and operating information on these activated carbon amine solution filters
appears in the technical paper, “Activated Carbon Filtration of Amine and Glycol Solutions,”
presented at the 1974 Gas Conditioning Conference in Norman, Oklahoma. The condition of
solution from amine plants equipped with these activated carbon filters and resulting minimal
amounts of HSAS remaining in the solution is described in detail in the technical paper,
“Performance of Gas Purification Systems Utilizing DEA Solutions,” presented at the 1975 Gas
Conditioning Conference at Norman, OK.
The following Table 2 indicates the size Activated Carbon Filter required for various Amine
Solution circulation rates:
Table 2: SIZE ACTIVATED CARBON
FILTERS REQUIRED
GPM CIRCULATION
25
40
60
100
SIZE FILTER REQUIRED
24”OD X 7’ 0”
30”ID X 8’ 0”
36”ID X 8’ 0”
48”ID X 8’ 0”
20
3. The Heat Exchange System
The heat exchanger exchanges heat from the lean amine solution to the rich amine solution,
and it serves two purposes: (1) it is a means of cooling the lean amine solution from the
Reboiler, and (2) it conserves heat and improves the overall fuel gas efficiency of the amine unit
by raising the temperature of the rich amine solution feed to the Still.
The Heat Exchange System should be tube and shell heat exchangers. Experience has shown
that while plate and frame exchangers have a very high heat exchange efficiency, they do tend
to foul quickly, and disassembly, cleaning and then reassembling them is difficult and damages
frequently occurs which usually causes a need to exchange plate and frame exchangers for
shell and tube exchangers. In comparing these two types of exchangers, the shell and tube
exchangers are probably the most simple and trouble free, plus there is minimal trouble with
tube plugging. However, shell and tube exchangers are larger and will require more skid space.
Plate and frame exchangers will be smaller and require less skid space, and heat exchange will
be more efficient with less area required. However, passage ways for the fluid flow through
plate and frame exchangers are much smaller and more inclined to plug if the amine solution
contains any suspended solids. So these exchangers will have to be disassembled and cleaned
periodically.
Optimal heat exchange for amine units would have approximately a 40 to 60 degree F.
approach (i.e., the lean amine inlet to the exchanger will be 245 to 260 degrees F, and the rich
amine solution out of the exchanger will be 185 to 220 degrees F. The outlet lean amine
solution will be about 160 degrees, and the inlet rich amine solution into the exchanger will be
100 to 130 degrees F.
The so-called “optimal” heat exchange is an economic balance of the capital cost of the heat
exchangers vs. the value of the fuel gas to the unit, based on most recent costs. As costs of
heat exchangers varies, and fuel gas costs rise or fall, the optimal heat exchange approach
temperatures will vary.
4. The Solution Cooler
Lean Amine Solution from the Heat Exchanger will be at approximately 160 degrees F. It
should be cooled to approximately 110 degrees F before pumping it into the Contactor. This
cooling is normally accomplished with an aerial heat exchanger, (normally mounted with the
Reflux Condenser on a common frame with a common fan.) The minimum outlet temperature
will depend on the ambient temperature and usually will require louvers on the unit to prevent
overcooling in the winter.
In some installations where the inlet gas is too cool to initiate the Amine/Acid Gas reaction in the
Contactor, the inlet gas temperature must be raised to at least 80 degrees F. The waste heat
available from the lean solution may be used to warm the inlet gas via an inlet gas/lean solution
heat exchanger, when necessary. Should this be the case, the Solution Cooler should be at
21
least partially bypassed to control the inlet gas temperature and the temperature of the lean
amine solution.
C. The Still, Reflux Condenser, Reflux Accumulator, Reboiler, and Surge Tank Systems:
The Perry Gas 10 to 100 GPM kettle type Reboiler/Still Systems contain a unique, complex,
and very important combination of components which assures (1) near complete stripping of the
Acid Gases from the lean amine solution, and (2) minimal losses of DEA from the unit.
Figure 3 is a drawing of the Reboiler/Still system to show how this system accomplishes these
two very important functions of an amine unit.
1. The Still
The Still is actually a chemical decomposition vessel, which is built as if it were a fractionating
column. In operation, the still pressure will be controlled with a pressure controller and vent
22
valve from the Reflux Accumulator to be 10 to 15 psig. This will raise the boiling point
temperature of the rich amine solution in the Still system to 240 to 260 degrees F. It is
necessary that the column temperature be this high to assure the decomposition of the unstable
amine salt of amine and CO2 and/or of amine and H2S. This column would normally be a 25
psig design with 1/8 inch corrosion allowance and stress relieved, and is either a packed
column if it is 24 inch or smaller in diameter, or an 18 to 20 tray column (either sieve trays or “v
grid” trays) if the column is 30 inches are larger in diameter. Rich amine solution at 185 to 210
degrees F (from the Heat Exchanger) enters the Still about 2 feet below the top of the packing in
a packed column, or onto the third tray in a trayed column. In a packed column, steam rising
from the reboiler rises through the void spaces between the column packing, where the packing
has rich amine solution draining over it. This contact of steam with the rich amine solution will
raise the solution to its boiling point. In a tray column, the steam rises through the sieve holes,
or through v grid slots, and bubbles through the rich amine solution flowing across the tray, and
the rich amine solution temperature is raised to its boiling point. The following Figure 3 is a
Graph to determine the Still diameter necessary for various Amine Solution circulation rates:
Figure 4 STILL SIZE REQUIRED
450
400
GPM CIRCULATION
350
300
250
200
150
100
50
0
0
10
20
30
40
50
60
70
80
90
100
NOMINAL STILL ID - INCHES
As the rising steam in the Still comes in contact with the rich amine solution, the weak amine
salts of amine/CO and/or amine/H2S begins to decompose into amine and CO2 and/or amine
and H2S. As the CO2 and H2S comes out of the solution, the excess steam rising through the
column sweeps these gases to the top of the Still and this steam/acid gas mixture is piped to the
Reflux Condenser.
The rich amine solution drains through the packing (or trays), and as it drains down through the
column, it is essentially stripped of any CO2 and/or H2S. When the Still system is working
properly, very little, if any CO2 or H2S enters the Reboiler; almost all of it is stripped from the rich
amine solution while in the Still.
23
Other instruments that should be included with the Still include:
Still pressure gauge and/or recorder
Still temperature indicator and/or recorder
Still head temperature indicator and/or temperature controller
Insulation of the Still vessel
It is important that the Reboiler have sufficient heat to generate enough steam to be sure that
the stripping of the CO2 is not allowed to slip down into the Reboiler. If this occurs, the fluid in
the reboiler becomes extremely corrosive. Also, once the actual stripping of CO2 is allowed to
slip into the Reboiler, it is almost impossible to get enough additional heat into the Reboiler fluid
to cause the stripping of the CO2 to rise back into the still. Should this occur, about the only way
to return to normal operations in which the stripping of the CO2 and H2S occurs in the Still, is to
shut the gas flow off through the Contactor, and continue to circulate the amine solution through
the unit with no Acid Gas loading, and with normal heat in the Reboiler until amine solution in
the Reboiler is completely stripped of all CO2 in it.
2. The Reflux Condenser
The Reflux Condenser is an air cooled heat exchanger through which the Still overhead vapors
(composed mostly of steam, CO2, H2S , and a trace of amine and trace amounts of
hydrocarbons) are cooled to approximately 110 degrees F or lower. At this temperature,
essential all of the amine and most of the steam as well as any of the heavier hydrocarbons are
condensed to a liquid, and the CO2, H2S, and light hydrocarbon gases are cooled to 110
degrees F.
3. The Reflux Accumulator System
The Reflux Accumulator is composed of a vertical, two phase separator (frequently located in
the base of the Still column). The design pressure of the Reflux Accumulator is 25 psig with a
1/8 inch corrosion allowance and it is stress relieved.
Accessories for the Reflux Accumulator include:
A Gas Pressure Controller
Motor Valve
Gauge Glass
Temperature Indicator
Pressure Gauge
The Still overhead vapors, which have been run through the Reflux Condenser, are piped into
the Reflux Accumulator, where the liquids are separated from the gases. These liquids which is
mostly water are pumped by the Reflux Pump through the Reflux Motor Valve which is
controlled by a Liquid Level Controller in the Reflux Accumulator to the top of the Still, where it
drains through the top 2 feet of packing (in a packed column), or through the top 2 trays (in a
tray column.) This reflux water washes almost all of the amine vapors out of the still overhead
24
vapors. The separated gases, composed of CO2, H2S , and a trace of light hydrocarbons, are
not soluble in the water reflux, and they vent through the Vent Valve, controlled by the Reflux
Accumulator Pressure Controller and are directed to a Flare, or to disposal.
Warning: In recent years there has been a tendency to combine the Reflux stream with the Still
feed stream on amine regeneration units and pipe the combination to feed the top tray of the
Still, to “save on piping costs.” This is a very poor way to save money; simulator runs indicate
that with this mixed Reflux-Feed combination fed to the top tray of the Still column, the amine
loss out the column vent is approximately 100 times greater than what is encountered with the
conventional Feed stream to the third tray of the Still and the reflux to the top tray of the Still.
4. The Reboiler System
The Reboiler is the source of heat for regeneration of the rich amine solution in amine treating
units. For smaller amine units (100 GPM circulation or less), so-called kettle type Reboilers are
used predominantly. Kettle type reboilers are more stable and easier to operate due to the big
amine solution inventory that they contain. This allows the amine unit to handle minor upsets in
operation without having the outlet gas to go off-specification. Amine units larger than 100 GPM
capacity will normally have tubular Reboilers.
Kettle type Reboilers are large 25 psig design pressure horizontal vessels, usually with one
head flanged, and u shaped firetubes welded into this removable head. Some corrosion may
occur in the reboiler, but a 1/8 corrosion allowance is usually adequate when combined with
stress relieving of both the vessel shell and firetubes, and design of the firetubes to be
conservatively based on heat transfer of 6,000 BTU per hour per sq. ft. of firebox tube area. (It
is true that firetubes of this type can readily transfer 10,000 BTU per hour per sq. ft., but this will
occur at a much higher corrosion rate on the firetubes.)
Table 3 specifies design heat capacities for the more common size Reboilers:
Table 3: REBOILER DESIGN HEAT LOADS
GPM CIRCULATION
25
40
60
100
MMBTU/HR. CAPACITY
1.800
3.000
4.500
7.500
FIREBOX AREA, SQ.FT.
300
500
750
1,250
The main lines to and from the Reboiler include (1) a liquid line from the base of the Still column
to drain all of the liquid amine solution out of the Still into the Reboiler, and (2) a larger vapor
line to vent steam generated in the Reboiler into the bottom compartment of the Still.
Another essential requirement of kettle type Reboilers is that they have adequate vapor space
for steam being generated to disengage from the amine solution liquid. (If the Reboiler has
inadequate vapor space, then the steam being generated will lift liquids out of the Reboiler, and
25
carry them into the Reboiler vent line to the Still. This can cause the Still to flood and carry over
amine solution into the Reflux Accumulator and out the vent line.) There are ways that the
amount of vapor space necessary may be calculated, but a rule-of-thumb is that the vapor
space height be at least 25% of the Reboiler vessel diameter, which will furnish adequate vapor
space in kettle type Reboilers.
The theory of firing the kettle type Reboilers is to provide a constant level of heat input into the
Reboiler. A very simple and dependable way to do this is to fire the Reboiler with a manually
adjusted fuel gas pressure controller on the fuel gas to the burners. All gas burners are
equipped with so-called fuel gas spuds with fixed diameter orifices which control the amount of
fuel gas burned to be varied only by fuel gas pressure to the spud. As the fuel gas pressure is
adjusted manually on this spud, the amount of fuel burned per hour (and the amount of BTU
released by this fuel burned) will be a constant, thus providing constant heat input into the
Reboiler.
Determination of the proper amount of heat input into the Reboiler is determined by the Still
head temperature. (The Reboiler temperature will relate only to the back pressure maintained
on the Still and Reboiler, and will only vary with a change in Still pressure. The Reboiler
temperature will be the boiling point temperature for the amine solution at whatever pressure is
being maintained on the Still and Reboiler.) The Still head temperature will vary according to
the ratio of the amount of steam to the amount of CO2 and H2S in the Still vent; the higher the
concentration of these gases, the lower the Still head temperature will be. Experience has
shown that minimum Still head temperature necessary to assure good stripping of the rich
amine solution is about 190 degrees F. For safe and dependable operation, it is best that the
Still Head temperature be run at 200 to 220 degrees F to be sure stripping is complete. So in
operation of a constant fired Reboiler, the operator should visually check the Still head
temperature at least daily, and adjust burner fuel gas pressure to maintain the Still head
temperature in this range.
A designer may be tempted to try to control the Still Head temperature with a Still Head
temperature controller to control the amount of fuel to the burners. However, experience has
proved that this is not a good way to control Still Head temperatures. The problem encountered
is that the long lag time between measuring the Still head temperature and controlling the
amount of heat input to the kettle Reboiler by the burners is simply too long for sensitive control
of the Still Head temperature.
Experience has proven control of the Still Head temperature by manually adjusting the fuel gas
burner pressure is simple, dependable, and maintains a near constant Still Head temperature.
(And if it is not broken, do not try to fix it!)
Other instruments that should be included with the Reboiler include:
Reboiler level gauge
Reboiler pressure gauge and/or recorder
Reboiler temperature indicator and/or recorder
Reboiler adjustable high temperature shutdown
Reboiler low liquid level shutdown
26
Burner pressure control and/or Still head temperature controller
Burner assemblies with flame arrestors
Insulation of the Reboiler vessel
Reboiler smoke stack designed for natural draft air
Adjustment the air/fuel ratio of kettle type Reboiler burners is very important. These burners
should be adjusted to have adequate primary air for a blue flame to get the best fuel gas
efficiency. If the burner primary air is insufficient, a yellow, so-called reducing, flame results,
which generates soot, which is finely divided carbon particles. This soot will collect in the
firetubes. Like any other combustible dust, under certain conditions, soot can be explosive. It
only requires (1) a disturbance to suspend the soot particles in the air in the firetube, and (2) an
ignition source, and then a violent explosion may occur.
5. The Surge Tank System
The Surge Tank is normally an extension of the Reboiler Shell of the same diameter, located on
the end of the Reboiler opposite the firebox. The design pressure of the Surge Tank is 25 psig
with a 1/8 inch corrosion allowance and fully stress relieved. It is totally insulated to prevent
heat loss. A partition which is 75% of the diameter of the vessel with the open area at the top
forms a liquid overflow baffle for liquid from the Reboiler to spill over into the Surge Tank. This
baffle controls the level of liquid in the Reboiler. A second smaller baffle is installed from the top
down to approximately 2 inches below the liquid level in the Reboiler. This baffle has a notch in
the top to equalize pressures in the Reboiler and the Surge Tank. The purpose of this baffle is
to prevent the large amounts of steam vapor generated in the Reboiler liquid from coming into
contact with the liquid in the Surge Tank. A small amount of bleed gas from the fuel gas system
is injected into the top of the Surge Tank to furnish a sweep of gas through the baffle notch into
the Reboiler to prevent any backflow of steam into the Surge Tank.
The Perry Gas 10 to 100 GPM kettle type Reboiler/Still systems contain a unique, complex, and
very important combination of components which assures (1) near complete stripping of the
Acid Gases from the lean amine solution, and (2) minimal losses of DEA from the unit. Figure 3
is a drawing of the Reboiler/Still system to show how this system accomplishes these two very
important functions of an amine unit.
Controls and accessories for the Surge Tank include:
Temperature indicator
Pressure gauge
Gauge glasses
Low Level shutdown switch
The only large connection on the Surge Tank section is an outlet for the lean amine flow to the
Heat Exchanger and Booster Pump.
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D. Amine Unit Pumps:
Pumps required for an Amine Unit include the following:
1.
Amine Solution Booster Pumps are installed between the Heat
Exchanger and the Solution Cooler in the lean amine solution line. The purpose of the Amine
Solution Booster Pump(s) is to provide pressure to pump the amine solution through the
Solution Cooler and provide a positive pressure to the suction to the Main Solution Pumps.
Each Amine Solution Booster Pump (one full capacity pump and one full capacity spare pump)
is a centrifugal pumps designed for circulation of 150% of the design amine solution circulation
rate, NPSH of 5 -10 psia, and a discharge pressure of 50 psig. The Amine Solution Booster
Pump motors should be TEFC or Class 1, Group D, explosion proof.
2.
Main Amine Solution Circulation Pumps are installed downstream of
the Solution Cooler to inject the amine solution into the Contactor at Contactor operating
pressure. The purpose of the Main Amine Solution Circulation Pump is to circulate the lean
amine solution into the Contactor where it reacts with the CO2 and/or H2S in the gas stream
being processed. For 25 GPM or less amine solution design circulation rates, one full capacity
pump and one full capacity spare pump are normally used. For 40 GPM or greater amine
solution design circulation rates, three half capacity Main Amine Solution Circulation Pumps are
sometimes used, with two of these half capacity pumps running at all times and one half
capacity pump in standby. These Main Pumps are normally positive displacement plunger
pumps; however, for larger units, multistage centrifugal pumps may be used as an alternate for
these Main Pumps. Each plunger pump should be equipped with a vertical suction bottle
(approximately 4.5” by 36”) with a 6” to 12” gas cap in the bottle. The suction bottle will provide
a reservoir of fluid to quickly fill the pump cylinders with liquid during the suction stroke of the
pump, which will prevent, or minimize the plunger pumps tendency to have a “hydraulic
hammer” which will happen if the pump cylinders are not fully filled with amine solution during
the suction part of each stroke.
Design discharge pressure should be a minimum of the
Contactor design pressure plus 50 psig. Motors for these pumps should be TEFC or Class 1,
Group D, explosion proof.
3.
The Still Reflux Pumps are installed between the Reflux Accumulator liquid outlet and
the top of the Still. The purpose of the Still Reflux Pumps is to pump the water and trace
amounts of amine which were condensed in the Reflux Condenser back into the Still. Each Still
Reflux Pump (one full capacity pump and one full capacity spare pump) is a centrifugal pumps
designed for circulation of 50% of the design amine solution circulation rate and NPSH of 5 to
10 psia and a discharge pressure of 40 psig. The Still Reflux Pump motors should be TEFC or
Class 1, Group D, explosion proof.
4.
Makeup Water and Amine Injection Pumps: Each amine unit should also be equipped
with pump(s) to inject makeup water and amine from storage tanks into the amine unit.
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E. Automatic Control Panel:
All amine units, whether designed for around the
clock operator attendance, or for unattended operation part of the time, should be equipped with
an Automatic Control Panel which is designed to shut the plant down, and shut off the gas flow
into the unit, if certain malfunctions occur which may cause the unit to fail to achieve outlet gas
composition which will meet gas outlet specifications.
In the event of automatic shutdown, the following should occur automatically:
1.
2.
3.
4.
5.
Shut down all electric motors in the plant.
Close the main burners fuel valves (but not the pilot burner valves) in the Reboiler.
Shut off the main gas flow into the plant.
Sound an alarm in the plant and signal a remote shutdown alarm.
Panel light should show only on first out alarm.
The following shutdowns should be designed to cause a plant shutdown:
1.
Low liquid level in the Reboiler.
2.
High Reboiler Temperature
3.
Low liquid level in the Surge Tank.
4.
Low Still head temperature.
5.
Any motor starter shut down.
6.
Aerial Cooler vibration switch(es).
7.
Power failure.
8.
High H2S and/or CO2 in the outlet gas (to be connected if the unit has an instrument
monitoring outlet gas composition).
9.
Manually tripped Emergency Shutdown Switch.
10.
Spare alarm/shutdown indicators (for other shutdowns if there are any).
The panel may also be equipped with alarms for each of the above shutdowns which are set to
alarm before shutdowns occur. This is particularly useful for 24 hour attended amine units in
that it gives operating personnel an opportunity to correct malfunctions before actual shutdown
occurs.
Another desirable option is for the Control Panel to include data recorders to continuously
record critical operating data, such as:
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Pressure of gas being processed;
Inlet temperature of gas processed;
Reboiler temperature and pressure;
Still head temperature;
Reboiler burner fuel gas pressure;
Filter pressure drop;
Contactor differential pressure;
Flash Tank pressure;
Any other desired critical operating data.
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In Conclusion:
Trouble free operation of amine units depends on clean solution, above all other factors. Once
the amine solution is clean and is “water white,” amine unit operations becomes easy, and the
amine treating unit is no longer “a mean unit.”
Charles R. Perry is a registered professional Chemical Engineer. He graduated from the University of Oklahoma with a BS
degree in Chemical Engineering in 1951. After graduation, he worked for Union Carbide Chemicals Company at Texas City. He
was drafted into the U. S. Army in 1954 and served two years in a tuberculosis research laboratory at Fitzsimmons Army
Hospital in Denver, where he discovered how to use the drug Pyrazinamide effectively in the treatment of tuberculosis.
Ironically, his first technical paper to be published was in the American Review of Tuberculosis on this drug. He joined Sivalls,
Inc. when he was discharged for the Army, where he spent 11 ½ years in the design and development of lease production
equipment.
In 1967, he started his own company, Portable Treaters, Inc., later change to Perry Gas Companies, Inc. Perry Gas originally
specialized in the manufacture of gas treating and dehydration units. The company expanding rapidly, constructed a large
fabrication shop in Odessa, and was the first to offer contract treating of gas, in which the company furnished both the
equipment and operation to treat gas on a cents per mcf basis. The company also expanded into gas gathering, cryogenic
processing, gas transmission, and plant construction. In 1980, the company merged with Parker Drilling Co., an New York
Exchange listed company.
Mr. Perry has written over 25 technical papers, and was awarded numerous domestic and foreign patents in the field of gas
processing. He was active in the Gas Processors Association, serving as a Vice President and as Program Chairman of the
1978 national convention. He has received numerous awards and recognitions, including the Gas Processors Association’s
prestigious Hanlon Award, and the Permian Basin Oil Show’s Industry Honoree. He serves today as Chairman Emeritus of a
new Perry Gas Processors, L.P. and as an expert witness and consultant.
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