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 79768432-332-0100

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 ContentsGas Treating in 2015......................................................................................................................................5The Evolution and History of Amine Gas Treating.......................................................................................5The Amine Process for Gas Treating.............................................................................................................8Amine Solution Circulations Requirements.................................................................................................12A Word of Caution about Amine Contaminants and Degradation Products...............................................14A. A Tour Through an Amine Gas Treating Unit..................................................................................15

1. Inlet Gas Scrubber(s).........................................................................................................................152. The Contactor....................................................................................................................................163. Outlet Scrubber.................................................................................................................................174. Outlet Gas Dehydrator......................................................................................................................18

B. The Flash Tank, Filtration, and Heat Exchange Systems:......................................................................181. The Flash Tank..................................................................................................................................182. The Rich Amine Filter System..........................................................................................................183. The Heat Exchange System..............................................................................................................214. The Solution Cooler..........................................................................................................................21

C. The Still, Reflux Condenser, Reflux Accumulator, Reboiler, and Surge Tank Systems:......................221. The Still.............................................................................................................................................222. The Reflux Condenser.......................................................................................................................243. The Reflux Accumulator System......................................................................................................244. The Reboiler System.........................................................................................................................255. The Surge Tank System....................................................................................................................27

D. Amine Unit Pumps:................................................................................................................................28E. Automatic Control Panel:.......................................................................................................................29In 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 101By: 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

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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

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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

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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.

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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

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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

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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.

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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

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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

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fuel gas 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.

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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 flowOne 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 glassOne temperature indicator

2. The Contactor

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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:

100 300 500 700 900 11000

5

10

15

20

25

30

35

40

45

Figure 2: CONTACTOR CAPACITIES

Contactor Pressure, PSIG

MM

CFD

Capa

city

48 inch

42 inch

36 inch

30 inch

24 inch

20 inch16 inch

16 inch

42 inch

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.

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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 flowOne 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 glassTwo 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 flowOne 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 glassOne temperature indicator

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

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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 FLASH TANK SIZE REQUIRED25 30” OD X 8’ 0”40 36” OD X 8’ 0”60 42” OD X 10’ 0”

100 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 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

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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. 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

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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 SIZE FILTER REQUIRED25 24”OD X 7’ 0”40 30”ID X 8’ 0”60 36”ID X 8’ 0”

100 48”ID X 8’ 0”

3. The Heat Exchange System

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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 least partially bypassed to control the inlet gas temperature and the temperature of the lean amine solution.

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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 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

22

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:

10 20 30 40 50 60 70 80 90 1000

50

100

150

200

250

300

350

400

450

Figure 4 STILL SIZE REQUIRED

NOMINAL STILL ID - INCHES

GPM

CIR

CULA

TIO

N

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.

Other instruments that should be included with the Still include:

Still pressure gauge and/or recorderStill temperature indicator and/or recorderStill head temperature indicator and/or temperature controller

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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 ControllerMotor ValveGauge GlassTemperature IndicatorPressure 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 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.

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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 MMBTU/HR. CAPACITY FIREBOX AREA, SQ.FT.25 1.800 30040 3.000 50060 4.500 750

100 7.500 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 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

25

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 gaugeReboiler pressure gauge and/or recorderReboiler temperature indicator and/or recorderReboiler adjustable high temperature shutdownReboiler low liquid level shutdownBurner pressure control and/or Still head temperature controllerBurner assemblies with flame arrestorsInsulation of the Reboiler vessel

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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 indicatorPressure gaugeGauge glassesLow 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.

D. Amine Unit Pumps:

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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.

E. Automatic Control Panel:

All amine units, whether designed for around the

28

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. Shut down all electric motors in the plant.2. Close the main burners fuel valves (but not the pilot burner valves) in the Reboiler.3. Shut off the main gas flow into the plant.4. Sound an alarm in the plant and signal a remote shutdown alarm.5. 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 Temperature3. 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) Pressure of gas being processed; (2) Inlet temperature of gas processed; (3) Reboiler temperature and pressure; (4) Still head temperature; (5) Reboiler burner fuel gas pressure; (6) Filter pressure drop; (7) Contactor differential pressure; (8) Flash Tank pressure; (9) 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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