Amine Treating Best Operating Practices Resource Guide Searchable Version

CHEVRON RESEARCH AND TECHNOLOGY COMPANY Richmond, California Light Hydrocarbon processing Team

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

JULY 1994

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

;TABLE OF CONTENTS

Page 1.0 INTRODUCTION 1.1 Purpose 1.2 Objective 1.3 Scope

.

. .

. .

. .

. . .

. . .

. . .

. . .

. .

. . ..

.

. .

2.0 AMINE TREATING 2.1 Process Description • . • 2.2 Operating Parameters ... 2.3 Process Control .•.•.. 2 . 4 Equipment . • . . • . ••• 3.0 SOLVENT CHARACTERISTICS 3.1 Amines 3.2 Performance 3.3 Solution Quality 3.4 Amine Degradation 3.5 Heat Stable Salts 3.6 Foaming 3.7 Losses 3.8 Makeup Water 3.9 Filtration 3.10 Reclaiming

..········ · · · · · ·· · · ·· · ·· ·· ·· ·· ··· · · · · ..·· · · · · · · · · · ·· · · · · · · ·· ·

. . .. . . 1. 1 . . . . . . . . 1. 1 . . . . . . . . 1.2

• • • • • • 2. 2 · . 2.9 · . . . . 2.15 • • • 2.22

·· ·· ·

· · · ·

·

··· · · · · · · · · · · · · ·· · · ·· · · · ·

· · 3.1 3.2 · · · 3.5 · · 3.7 · 3.10 · · 3.13 3.14 · · 3.18 · · 3.18

· · · · · ·· · · · · · · · ·

··

3.21

4.0 CORROSION CONTROL 4.1 Corrosion in Amine Treating Plants. . . • . . . 4.1 4.2 Influence of Design and Operating Variables • . . . 4.6 4.3 Use of Alloy Equipment . . •.. . • . . . . 4.8 4.4 Corrosion Inhibitors. . •. ••. 4.10 4.5 Corrosion Monitoring . . . . . . • . 4.11 5.0 MONITORING PLANT PERFORMANCE 5.1 Performance Goals 5.2 Recommended Practice 5.3 Sampling and Analysis 5.4 Monitoring Trends

· ········ · . · .. · · · · · · · · . . · . . ·· · · · · · · · . ··

6.0 ENVIRONMENTAL ISSUES 6.1 Refinery Fuel Gas Sulfur Content . . . 6.2 Disposal of Wastes from Amine units

· 6.1 · 6.2

.7.0 ADDING CAPACITY TO AN AMINE UNIT 7.1 Determining the Capacity of an Amine unit . . . . . 7.2 Temporary Operation at Elevated Rich Amine Loadings 7.3 Debottlenecking an Amine Unit . . . . . . . .. 7.4 Switching from DEA or MEA to MDEA . . . . . . . . . TABLE OF CONTENTS

(1 )

5.1 5.1 5.7 5.7

7.1 7.5 7.6 7.9

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

8.0 PROCESS SIMULATION

8.1 8.2 8.3 8.4

Introduction . . . • . . . . . . How to Create a Simulation of an TSWEET . . . . • • . AMSIM (or HYSIM) . . . . . • • •

•

.

•

•

.

.

.

.

.

.

8. 1

Existing Amine unit 8.2 . • . . . . . . . .8. 3 • • • • • • • • • • 8. 4

9.0 TROUBLESHOOTING 10.0

HYDROCARBON/PARTICULATE REMOVAL BEST PRACTICE

TABLE OF CONTENTS

(2)

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

1.0

INTRODUCTION

1.1

PUrpose

The purpose of the "Amine Treating Best operating Practices Resource Guide" is to assist in the achievement of effective, reliable, economical, and environmentally sound operation of amine units. The guide addresses the removal of H2S and C02 (or "acid gases") from either gas or LPG streams, and is applicable to amine units in refineries as well as those in upstream facilities. In general, the guide emphasizes performance improvement and troubleshooting over design, and is meant to complement best practice guides developed by the refineries. . The guide does not cover processes for acid gas removal using physical solvents, hybrid solvents, caustic or sorbents. Removal of trace amounts of sulfur compounds including H2S, COS, mercaptan and CS2 are covered in a separate guide. 1.2

Objective

The objective of the guide is to help find the best operating practices for a particular amine unit. The discussion covers the operating principles of amine units, common problems that occur, techniques used to recover from operating problems and strategies to avoid problems in the future. The input to the guide comes from a variety of Chevron and industry experience. Because of the wide range of conditions upon which that experience is based, it is not unusual to find contradictions among the various practices that have been prescribed to operate or fix amine units. There are few absolute "best practices" that can be applied rigorously to all amine plants. strict adherence to a standard list of parameters is not necessarily the best practice. General rules can sometimes be broken without serious consequence. Each amine unit has its own tolerance for abnormal conditions which can only be gauged accurately through consistent monitoring and attention. On the other hand there are some basic principles that well run amine units follow. What is presented here is a guide (or process) that c~n be used to evaluate the performance of amine units and set operating parameters accordingly. A major intent of the guide is to help determine what steps should be taken to directionally improve performance.

I NTROOUCTI ON

1.1

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

The key to best operating practice for amine units is to avoid conditions which "stress" the unit; and when problems do develop it is best in the long run to treat the source of the problem rather than the symptom. 1.3

Scope

The following are included within the scope of the guide: • The process flow, parameters and equipment of amine units, • Characteristics of amine solvents, • Typical operating problems (such as foaming and corrosion) and how to minimize them, • The use and interpretation of analytical and operating data for day-to-day monitoring, troubleshooting and quality control, • Environmental concerns, • Use of simulators to evaluate and/or tune the unit, • Considerations for increasing plant capacity.

I NTROOUCTI ON

1.2

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

2.0

AMINE TREATING

Amine treating (or sweetening) is used in a wide variety of applications to remove H2S and C02 from gases and light hydrocarbon liquids. The purpose of the process is to reduce the concentration of the acid gas contaminants sufficiently to meet product sales, flue gas emissions or other process requirements. The process has changed very little over the many years it has been in use. Over the past decade, however, the generic alkanolamines such as MEA, DGA, DEA, and DIPA have been joined by MDEA and proprietary solvents in a move toward increased energy efficiency, reduced corrosion rates and enhanced performance. Gas and liquid feed streams are treated fundamentally the same, except for some differences in the absorber design and some specific operating considerations which will be identified later. For simplicity of presentation, the process will be described in terms of gas treating which is more common. The majority of operating problems in amine plants have to do with the fact that the solvent undergoes continuous thermal cycling in a closed loop, and that feed gas contaminants and degradation products formed during operation can build up in the solvent and lead to foaming, liquid carryover, off-spec product, corrosion and erosion. These conditions can be aggravated by operating the unit outside the recommended ranges of temperature, amine loading, amine concentration, feed composition and fluid velocities. Inherent design details and materials selection also play a role here. Understanding the process principles is the first step in achieving best operating practices for amine units.

AMINE TREATING

2.1

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

2.1

Process Description

The process is based on the simultaneous diffusion of acid gases into and out of the aqueous solvent phase and the reversible chemical reactions that take place between the amine and acid gas components. These reactions and other characteristics of the different amines are discussed in section 3.0. The choice of amine has an influence on plant economics (e.g. capital, solvent and energy costs) and the ability to achieve the required treated gas specifications. The process flow is conceptually the same regardless of the type of amine used. The two main processing steps in amine units are: i) Chemical Absorption. Feed gas (or "sour" gas) is contacted with "lean" amine in an absorber column to remove the acid gases. The treated gas (or "sweet" gas) leaves the top of the absorber. The objective may be: "simul taneous removal II of H2S and C02 to low levels (i.e. 4ppmv H2S and 100 ppmv C02 for gas plants or less than 160 ppmv H2S with no concern for C02 removal for refineries), •

"bulk removal" of C02 (ie. from, 4 mol% to 2 mol% to meet sales gas specification) or

•

"selective removal" of H2S to low levels while "slipping" C02 (i.e. reduce H2S to 4 ppmv and C02 from, say, 4 mol% to 2 mol% for gas plants or less than 160 ppmv H2S with minimum C02 absorption for refineries).

ii) Solvent Regeneration. The "rich" amine containing the acid gases is regenerated by stripping them out in a distillation column. The acid gases are recovered from the regenerator overhead and typically sent to a sulfur recovery unit (SRU) or incinerator. If only C02 is being removed the regenerator gas is vented. The objective is to: reduce the residual "loading" of the lean amine so that the acid gas equilibrium vapor composition is equal to or less than the specified composition of H2S and C02 in the,treated gas.

AMINE TREATING

2.2

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Typical Amine Process Flow A typical flow sheet is shown in Figure 2.1 Absorber Feed streams Depending on the condition of the sour gas, it may be necessary to prepare it for the absorber by first passing it through a knockout drum, centrifugal separator and/or filter separator to remove liquid carryover, condensed liquids and particulates which can cause foaming in the absorber and regenerator. In refineries a water wash column may preceed the absorber to remove organic acids. The "clean" sour gas passes into the lower section of the absorber, up the column through contacting trays or packing and out the top (water saturated). Pressurized lean amine solution enters at the top of the absorber at 100-140 deg F and flows down contacting the gas counter-currently. The lean amine should be 10-15 deg F hotter than the feed gas to ensure that no hydrocarbons are condensed and that any mist carried over from the knockout drum will be vaporized. In very sour streams .this temperature difference may have to be increased to account for the dew point elevation caused by removal of the acid gas. The upper limit on lean amine temperature for effective absorption is 140 deg F while the upper limit of feed gas temperature is 120 deg F. The amine absorbs the acid gases and leaves the bottom of the absorber. Small amounts of hydrocarbon gases are dissolved into the amine, as well. Refinery gases often contain ammonia. Some ammonia will be absorbed in the amine. Absorber Outlets The streams leaving the absorber are hotter than the feed streams due to the exothermic heats of reaction from absorbing the acid gases. Treated gas from the overhead of the absorber passes through a knockout drum and/or water wash to remove and recover entrained amine. Rich amine from the absorber bottoms is let down through the absorber level control valve to a flash drum. Rich Amine The flash drum provides residence time to separate amine from liquid hydrocarbon phase (resulting from entrainment or condensation in the absorber) and releases light hydrocarbon AMINE TREATING

2.3

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

vapors and small quantities of acid gases from the rich amine. In some units the flash gas may pass through a small amine absorber mounted on top of the flash drum so that the gas may be used as fuel. Evolution of light hydrocarbons is important prior to amine regeneration to avoid foaming and sending excessive hydrocarbons along with acid gases to the SRU. Some plants are designed with rich amine filtration at the flash drum liquid outlet to remove particulates carried into the system with the feed gas. However, filtration is typically carried out on the lean amine side where exposure to H2S is minimized. Filtration can be done at either location. Refer to sections 2.4 and 3.9 for further discussion. Next, the rich amine flows through the tube side of the lean/rich . exchanger to recover heat from the regenerator bottoms stream. The hot rich temperature is dependent on the physical characteristics of the exchanger, solvent properties and solvent flow rate. It is possible for a clean or new exchanger to develop hot rich temperatures higher than design. The "hot rich" amine within the exchanger and in the exchanger outlet piping is conducive to corrosion and erosion particularly when the rich loading is high and the hot rich temperature exceeds about 215 deg F. At such conditions H2S and C02 can break out of solution into the vapor phase in amounts sufficient to cause severe corrosion problems. In units where the flash drum level control valve is located at the L/R exchanger outlet and there is no rich amine pump, the flash drum pressure influences the amount of vaporization that occurs within the exchanger. Some natural gas plants are designed with a "high pressure" operating mode (150-200 psig) for the flash drum which has the effect of limiting the evolution of acid gas vapor in the lean/rich exchanger, thus minimizing erosion and corrosion within the exchanger, outlet piping and fittings. The hot amine then flashes across the flash drum level control valve and flows a short distance to the regenerator inlet. However, as a general rule the flash drum is typically set at the lowest practical operating pressure to minimize hydrocarbon content of the amine going into the regenerator and on to the SRU. Amine Regeneration The rich amine from the flash drum is preheated by passing through the lean/rich exchanger and fed to the top of the regenerator. The regenerator typically operates at low pressure (10-20 psig) and elevated bottoms temperature (230-260 deg F), conditions which favor the desorption of the acid gases. The amine flows down through the trays as the acid gases are stripped out by steam passing up the column. Steam is generated from the AMINE TREATING

2.4

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

water in the amine solution on the shell side of the reboiler. It is desirable to operate the reboiler at as low a temperature as possible while maintaining the necessary heat flux (6-8 Mbtu/hr/sqft). 50 psig steam, typically 1 pound of steam per gallon of circulating solvent, is the usual heat medium used in amine reboilers. Hot oil loops and direct fired heaters can also be used. Excessive reboiler tube skin temperatures (above 320350 deg F) cause increased rates of thermal degradation of the amine and should be avoided. units using primary amines like MEA and DGA are often designed with a reclaimer which takes a sidestream from the regenerator bottoms equal to 1-3% of the amine circulation rate. After adding caustic to convert amine salts to sodium salts the reclaimer boils off an amine/water mixture in a batch operation leaving behind degradation products, suspended solids, acids and iron compounds. Reclaimers are essential in DGA plants to reverse degradation caused by cos. Reclaimers are not usually provided for DEA and MDEA units because it is assumed degradation is less severe than for primary amines, and because they have lower volatilities which would mean operation of the reclaimer under vacuum requiring greater expense and operator attention. other methods of reclaiming are discussed in section 3.10. Regenerator overhead vapor consists of acid gases, ammonia (in refineries) and water vapor. Most of the water is condensed in the regenerator overhead condenser and collected in the reflux drum. Some ammonia will form ammonium biSUlfide, soluble in the water. The sour water from the reflux drum is returned to the top of the regenerator and the acid gases are sent to the SRU, incinerator or vent. Ammonia Scrubber In refineries it is common to water wash the offgas in a packed scrubber column to remove ammonia before routing the acid gas to the SRU. This processing step minimizes the precipitation of ammonium bisulfide in the line to the SRU. Makeup water A portion of the sour water may be purged from the reflux drum to provide an outlet for contaminants and to control ammonium bisulfide concentration. The purge rate should be adjusted according to regular test results for ammonium bisulfide content of the sour water. Makeup water or steam.is added to the solvent inventory as required to maintain the water balance (see section 3.8).

AMINE TREATING

2.5

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Lean Amine Lean amine from the regenerator bottom is cooled in the lean/rich exchanger and pumped through an air or water cooled exchanger. Then,the amine passes through a particulate filter (preferably full flow) to remove iron sulfide scale, iron carbonate precipitate (from corrosion), insoluble degradation products, and other particles. In plants where full flow filtration is not available and the system is relatively clean, filtration of a 25% slipstream may be sufficient. A 5 or 10 micron absolute filter is typically used. Backwash filtering systems may require additional tankage. Filters may be located on the rich or lean amine, or both. A 10-20% slipstream of cooled lean amine may be treated by activated carbon to adsorb hydrocarbons which would otherwise build up in the amine solution and cause foaming (see section 3.9). The carbon bed may be followed by a second particulate filter to catch entrained carbon fines. Amine Storage/Surge Some units have a storage/surge tank which provides volume to accommodate swings in amine inventory and liquid levels. Otherwise, surge capacity is provided in the bottom section of the absorber, regenerator and/or flash drum. Concentrated amine for make-up may be stored in a tank. Both tanks are blanketed with fuel gas or nitrogen. Air should be excluded from the storage tanks to prevent oxygen degradation of the amine which can cause increased levels of precursors to corrosive compounds. Finally, the lean amine is pumped back to the· top of the absorber • . Chemical Injection Provisions are usually made to add antifoam (see section 3.6) and sometimes corrosion inhibitors (see section 4.4) and caustic (see section 3.5) to the lean amine by injection pump or shot pot. General Skim nozzles are often provided in the absorber, regenerator, flash drum and reflux drum to skim any hydrocarbon layer that may • accumulate. A more effective means of hydrocarbon removal in the flash drum is by means of three-phase separation with a weir and an overflow sump at one end for removal of the hydrocarbon phase. split Flow An

alternative design shown in Figure 2.2 circulates a semi-lean

AMINE TREATING

2.6

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

amine in addition to the usual lean amine to minimize the operating cost of amine regeneration. The semi-lean amine is withdrawn from the middle of the regenerator and fed to the middle of the absorber where acid gas concentration is high. The lean amine from the bottom of the regenerator is reserved for contacting the gas in the upper part of the absorber. Less lean amine is needed to achieve the same treated gas specifications, thus less energy is expended in the reboiler. However, the semilean stream requires separate pumps and exchangers. Selective B2S Removal Significant energy savings can be made by selectively removing H2S from a feed gas which also contains C02. If C02 removal is not required then MDEA or proprietary solvents (such as UCARSOL HS-10l or Flexsorb SE) are available which allow 70% or more of the C02 to "slip" through the absorber. Also, slipping C02 may be desirable in some cases from the standpoint that C02 acts as a diluent and takes up space in Sulfur Recovery units. When C02 removal is minimized it is possible to realize bene·fits in terms of increased throughput capacity, lower amine circulation rates, improved compliance with environmental regulations and lower regeneration energy. Proprietary selective solvents are more expensive than the primary and secondary amines, however. The process takes advantage of the slower reaction rate of C02 vs. H2S with tertiary amines. The absorber may be designed with fewer stages (12-15) than normal (20-25) or with multiple lean amine feed points to adjust the solvent residence time to achieve the desired amount of slip. Too few stages in the absorber could risk H2S breakthrough. Bulk C02 Removal Bulk C02 removal is often used to meet pipeline sales gas specifications when complete C02 removal is not required. For example, MDEA can reduce C02 from 4% to 2% by slipping half the C02 through the absorber. Bulk C02 removal requires similar considerations as described above for selective H2S removal. Alternatively, in the above example, the same effect can be achieved by feeding half the gas to a DEA absorber and recombining with the untreated half.

AMINE TREATING

2.7

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Liquid Treating

Light hydrocarbon fractions or LPG can be sweetened in similar fashion to gas. In the absorber, LPG becomes the dispersed phase traveling up through the continuous amine phase with interface control at the top of the absorber. The majority of liquid/liquid treaters employ packed absorbers although trayed absorbers are also used. Because of the small density difference between phases and solubility of amine in LPG, managing amine losses is a major operating concern. Liquid treaters tend to be the largest source of solvent losses in refineries. Due to the small density difference between the phases, tower design errors and poor operating conditions have a tremendous impact on losses. In practice, solvent entrainment in the hydrocarbon phase is far more significant than amine solubility.

AMINE TREATING

2.8

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

2.2

Operatinq Parameters

The objectives of an amine unit are to produce a treated gas that meets the required residual acid gas specifications and to provide a clean acid gas from the regenerator overhead. Ideally, these objectives are to be achieved with high reliability and optimal operating costs. To this end there are various key parameters that have to be considered. Key operating Parameters The key operating parameters to consider in an amine unit are: Feed Gas:

Flow Rate Inlet Temperature (80-120 deg F) Inlet Pressure (100-1000+ psig) Hydrocarbon Dew Point H2S, C02 Concentration or Partial Pressures (1-50+ psia)

Acid Gas:

Outlet Pressure (10-20 psig) Outlet Temperature (100-130 deg F)

Amine:

Lean Temperature (100-140 deg F) Circulation Rate Amine Concentration (wt %) Amine degradation

Regenerator:

Reboiler steam Rate (0.9-1.2 lb stm/gal) Reflux Ratio (1.5-4.0 moles water returned to regenerator per mole acid gas from reflux drum)

Flash Drum:

Pressure (2-150 psig)

~~_/

Contaminant Removal: Entrained or dissolved hydrocarbon Particulates Trace sulfur species Organic acids Parameters Influencing Acid Gas Concentration of the Treated Gas • At a particular. set of feed gas and circulation rates, the acid gas concentration of the treated gas leaving the absorber is most directly impacted by three process variables: • Lean amine temperature at top tray • Lean amine loading • Amine circulation rate AMINE TREATING

2.9

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Lean amine temperature is constrained by the available cooling medium temperature and a differential above the inlet gas temperature. The lean loading is a function of reboiler duty which can vary within limits of the equipment. The lean amine circulation rate may be adjustable to some degree and determines the rich amine loading. As an example, the following table shows the sensitivity of the treated gas to lean loading and lean temperature using a basis of 30 wt % DEA assumed to be at equilibrium with the treated gas at the top of the absorber: 30 wt% DEA in Equilibrium with B2S at Typical Absorber Overhead Conditions Pressure (Psia)

PPMv B2S at Temp. Lean Loadinq (Mols B2s/mol Amine) 100 eD F 125 eD F

500 250 100

.01 .01 .01

0.9 1.8 4.5

1.5 3.0 7.5

500 250 100

.02 .02 .02

3.3 6.6 16.5

6.6 13.2 33.0

The table above shows that a 25 deg F increase in lean amine temperature on the top tray increases the partial pressure (and, therefore, concentration) of H2S in the treated gas by 50-100%. The effects of total pressure and lean loading are also shown. Simulator predictions of equilibrium concentrations in the low ppm range often differ from the actual values so they should be used with caution. Equilibrium Curves Figures 2.3,4 & 5 show examples of equilibrium curves for MEA, DEA and MDEA. These curves represent partial pressure of H2S or C02 plotted against amine loading. They provide a graphical means of estimating the upper limits of capability of an amine unit. It would be necessary to plot a family of curves to look at partial pressures when both H2S and C02 are present. These curves were generated using the AMSIM program.

AMINE TREATING

2.10

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Approach to Equilibrium Amine absorbers in HzS removal service tend to have more than enough stages so that virtually 100% "approach to equilibrium" between the vapor and liquid is normally achieved in the upper section. For HzS removal it is usually desirable to operate in the "lean end pinch" mode such that the operating curve and equilibrium curve converge somewhere in the upper third of the absorber. This means that the partial pressure of HzS in the treated gas (and thus, the "parts per million HzS") very nearly approaches the equilibrium partial pressure of HzS over the lean amine; the HzS equilibrium partial pressure is determined by the degree of stripping in the regenerator. A thorough discussion of this topic is available in References 2.1 and 2.2. C02 is less likely to reach complete equilibrium with the lean amine due to slower reaction kinetics depending on the specific amine. (Reactivity decreases going from the primary amines, MEA and DGA, to tertiary amine, MDEA). Additional stages and high weirs (4 inches) may be employed to maximize C02 removal. Fewer stages and lower weirs may be employed to minimize C02 removal when using MDEA or proprietary solvents designed to slip C02 intentionally.

As implied above, the residual acid gas content of the treated gas can be expressed in terms of "approach to equilibrium" or ATE. It is useful to be familiar with the ATE concept when evaluating amine unit capacity and performance. ATE at top tray conditions is: (measured lean loading in solvent to the absorber> x 100% (lean loading in equilibrium with treated gas) The equilibrium loading can be obtained from a simulator program or from the solvent vendor. An unusually low ATE at the top of the absorber indicates H2S breakthrough or C02 slip due to insufficient acid gas pickup capacity in the lower section of the column. ATE at bottom tray conditions is: (measured rich loading in solvent from the absorber> x 100% (rich loading in equilibrium with feed gas) Most of the mass transfer and chemical reaction takes place in • the lower part Of the absorber. Typically, an absorber is designed for 70% or less ATE (not 100%) at the bottom for the following. reasons: • to ensure adequate driving force for mass transfer and kinetics • to recover more of the heat of reaction as sensible heat into the rich amine and less into the treated gas AMINE TREATING

2.11

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

• to allow for increases in temperature or acid gas content of feed and prevent acid gas breakthrough or "leakage" overhead • to limit absorber temperature rise due to heat of reaction (due to concerns for corrosion) • to limit extent of acid gas flashing in the hot rich amine from the lean/rich exchanger • to minimize corrosion associated with high rich loading Absorber Temperature Profile The absorber temperature profile provides useful information on performance. Typically the profile has a "bulge" in the lower portion of the column where most of the exothermic chemical reaction takes place. The temperature in the top half and in the treated gas out the top should have about the same temperature as the lean amine. The temperature should increase down through the bottom half, dropping somewhat on the bottom tray or two as the incoming feed gas cools the amine. The rich amine out the bottom should be significantly hotter than the lean into the column. Thus, the heat should go with the rich amine to the regenerator. '!'he degree of temperature rise depends on the acid gas content of the gas being treated. Amine Loading, Lean and rich loadings are commonly determined by laboratory analysis and reported as moles of H2S (and/or C02) per mole of amine. Rich amine samples are quite likely to be in error, on the low side, due to vapor losses during sampling. A simple material balance around an absorber designed for total acid gas removal can be made to check the rich loading: Rich Loading Moles Acid Gas Moles Amine

= =

(Acid Gas Pickup from Feed Gas)+(Lean Loading) (MMSCFD) (Mol% AG in Feed) (Amine Mol wt) (1.832) (Amine Rate, GPM) (wt% Amine) (Solvent, lb/gal) + (Lean Loading)

Note:

"Mol% AG in Feed" includes both C02 and H2S. Typical Amine Amine Solvent Solvent M,ol wt wt% lb/gal @ 120 F

MEA

DEA DGA MDEA AMINE TREATING

61.08 105.14 105.14 119.17

20 30 50 50

8.31 8.53 8.59 8.59

2.12

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Reboiler Heat

Reboiler heat duty (supplied by steam or other heating media) usually represents the largest operating cost of an amine plant. If lean loading is much less than required to achieve cleanup then energy is being wasted. However, some margin of excess duty is desirable in the event of a change in process conditions. Also, there is another reason to keep lean loadings low and that is to avoid lean side acid gas flashing or cavitation at the suction of the amine circulation pump. Lean loadings should not exceed the following values: Amine MEA DEA MDEA

moles of acid gas/ mole of amine 0.15 0.07 0.015

The reboiler provides energy in three parts: sensible heat to bring the amine up to boiling, latent heat to boil up some stripping steam and chemical heat to reverse the acid gas/amine reaction. The heat of reaction is variable depending on the amine and combination of H2S and C02. Approximate values are listed below:· Heat of Reaction (Btu/lb of H2S or C02) H2S C02

MEA DEA DGA MDEA

550 511 674 522

825 653 850 600

Typically, the reboiler operates with about one pound of steam per gallon of circulating solvent, but can range as high as two pounds per gallon. The most important indication· of reboiler performance is the lean loading from the regenerator bottoms. Reflux Rate

The amount of reflux returned to the regenerator is dependent on the amount of steam raised in the reboiler. The amount of steam . raised for stripping depends on the solution purity needed to meet the treated gas specification, the ratio .of H2S:C02, the amine and. the regenerator design. Reflux ratios range from less than 1:1 to 4:1 (moles of water returned to the regenerator per mole of acid gas leaving the reflux drum). The reflux ratio will be at the high end of the scale for MEA units and middle to low end for DEA and MDEA, respectively. This has been explained by AMINE TREATING

2.13

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

the observation that MDEA is less basic and more easily stripped to satisfactory levels than the·primary and secondary amines. For H2S/C02 systems the C02 which evolves actually assists H2S stripping and may reduce the stripping steam requirement, accordingly. Some of the water from the reflux drum may be purged, but most of it is returned to the regenerator to maintain the water content of the amine. Makeup water is added to replace the losses going out with the treated gas and acid gas. Monitoring of the reflux rate is an important part of managing the energy input to the unit and ensuring that lean loading and treated gas specifications are on target. The reflux rate is a measure of reboiler duty, and may be monitored with this in mind. Overhead temperature is another indication of the stripping steam rate and reflux ratio, and is considered a convenient means of monitoring the reflux rate. An amine plant simulator can be used to determine the overhead temperature for a given reflux ratio and column pressure.

AMINE TREATING

2.14

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

2.3

Process Control

Process control techniques can be used to maX1m1ze plant stability and minimize energy usage and other operating costs. The effectiveness of process control in amine plants depends on the degree of automation, operator involvement and timely use of laboratory results. While variations will be dictated by the original design/operating philosophy, process parameters, local regulations and preferences, the process control objectives are similar from one amine plant to another. Amine plants are controlled by a combination of manual and continuous automatic control devices as well as a number of intermittent controls which can be automated or operator initiated. Control set points may need to be readjusted from time to time in response to changes, whether abrupt or gradual, such as: feed gas rate and composition (especially acid gas components), amine strength (including heat stable salts content), amine contamination, heat transfer surface fouling and ambient temperature. The chart which follows is a guide to typical process control strategies used in amine plants.

AMINE TREATING

2.15

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

AMINE UNIT PROCESS CONTROL STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

1. ABSORBER

FLO\J

PRESSURE

Absorber LCV should hold 4-10 minutes surge volune. Operator skims hydrocarbon layer when needed. Submerged gas feed may be permissible to increase contact time in absorber if needed for CO2 absorption.

Maintained by overhead back pressure CV; or floats on downstream pressure. Hold maxinun backpressure on absorber for lowest residual acid gas in overhead. Higher than normal pressure drop across the absorber indicates foaming or flooding.

2. FEED (Sour) GAS

Controlled by upstream process, or absorber inlet exchanger.

LEVEL

Usually not flow controlled unless there are multiple absorbers requiring split flow.

Keep 10-15 deg F cooler than lean . amine. 3. OVERHEAD (Sweet) GAS

4. LEAN AMINE (Absorber Feed)

Regulated by absorber overhead gas PCV; or floats On downstream system. Controlled by cool ing mediun flow to lean amine cooler or air coo l er bypass TCV.

Controlled by FCV on discharge side of amine circulation ~.

Excessive flow wastes energy. Insufficient flow risks high rich loading, H2S breakthrough and corrosion_

Keep 10-15 deg F warmer than absorber feed gas. If lean amine is hotter than about 120 deg F: residual acid gas in overhead may exceed spec.

Adjust flow according to rich loading target value.

If too cold: liquid HC may form, CO2 absorption rate drops and ami ne viscosity increases. 5. RICH AMINE· (Absorber Bottoms)

AMINE TREATING

Absorber LCV regulates the bottoms flow.

2.16

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

6. FLASH DRUM

PRESSURE

FLOW

Flash Drun LCV should hold 10-15 minutes of surge volume. Operator should skim hydrocarbon layer when needed_ Tune the LCV to supply steady flow to the regenerator in preference to a fixed level in the Flash Drun.

Controlled by PCV on the flash gas from the flash drun. Set low enough to flash off most of the dissolved HC. If less than 45-65 psig, head will be inadequate to feed regenerator without a~.

Set pressure high enough to minimize acid gas breakout in the L/R exchanger causing erosion and/or corrosion. (Applies to plants with the flash drun LCV located at the L/R exchanger outlet. )

If the Flash Drun doubles as the primary surge vessel for the closed loop system, then the liquid outlet flow rate (not level) is controlled. Low level indicator or alarm indicates when solvent makeup is needed.

May require fuel gas to pressurize the Drun when flash gas is insufficient.

7. RICH AMINE (L/R EXCHANGER OUTLET)

Rich outlet (See Flash Drun) temperature is dependent on the L/R surface area, surface foul ing and circulation rate.

LEVEL

Regulated by Flash Drun LCV; or by direct flow control if Flash Drun serves as the primary surge vessel.

A clean or new exchanger can transfer excessive heat to the rich stream causing acid gas vaporiZation in the hot rich outlet which occurs above about 215 deg F. In such cases Flash Drun pressure shouLd be increased to help minimize vaporization •

.

AMINE TREATING

2.17

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

8. REGENERATOR

PRESSURE

Regenerator LCV regulates the bottoms f low and should provide 4-10 minutes surge time.

Controlled by acid gas backpressure CV on Reflux DrLIII.

This level may effect the flow hydraulics in the return leg from kettle reboiler, and NPSH of the amine circulation

Regenerator pressure determines the boiling point of the solution in the reboiler. Set pressure as low as possible and still get acid gas to the SRU. Avoid pressure so high as to cause thermal degradation of the amine. 9. LEAN AMINE (Regenerator Bottoms)

Regenerator bottoms temperature is the boiling point of the amine solution which is dependent on amine concentration " and regenerator pressure; it ~ be controlled In: adjusting the steam to the reboiler.

10. ACID GAS

Controlled by the Reflux Condenser control system. Steady temperature control keeps water content of acid gas constant, and helps stabilize SRU operation.

11. REFLUX DRUM

•

pLIIIP.

Regenerator LCV regulates the bottoms flow; does not apply when regenerator bottom is use for surge.

Controlled by acid gas PCV on Reflux DrLIII.

Ref lux DrLIII LCV should hold 6-10 minutes of surge volume.

12. REFLUX (to Regenerator)

Regulated by Reflux DrLIII LCV on discharge side of Ref lux PLIIIP •

13. PURGE (frOm Reflux DrLIII)

Controlled manually or by FCV"to purge contaminants from the system.

AMINE TREATING

LEVEL

FLOW

2.18

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

PRESSURE

14. MAKEUP WATER (or STEAM)

FLOW

LEVEL

Controlled manually or by FCV to continuously add fresh makeup water to the system to replace purge and normal losses. Makeup rate is based on analysis of amine strength.

15. MAKEUP AMINE

16. REBOILER

Operator periodically adds fresh makeup amine solution to the system based on monitoring of system inventory. Reboiler temperature is dependent on amine concentration and regenerator pressure, and £!nne!

Circulation and boilup rates are dependent on the rate of heat input, hydraul ics and type of reboiler.

be inde~ndent l~

. manil2!:!lated. 17. REBOILER STEAM

Should not exceed 260 deg F (bulk) or 350 deg F (skin).

Steam supply system. Controlled by FCV on steam line to Steam pressure reboi ler. Adjust should not exceed 50 according to lean psig to avoid amine loading target degradation. value. LCV on condensate pot controls condensate return. Operator should periodically vent noncondensibles from the pot if needed.

18. SURGE TANK

AMINE TREATING

Heating coils, if required.

Slight positive pressure controlled by fuel gas blanket system. Inert head space is needed to avoid degradation of ami ne by exposure to oxygen.

2.19

Level gauge and alarms indicate when inventory is too low or too high. Leave room in surge tank to hold total amine inventory in the event of a shutdown.

JULY

1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

FLO\J

PRESSURE

19. CARBON BED

LEVEL

Typically regulated by a manua II y controlled valve. Abnormal pressure differential across the bed indicates a bed that has been in.,roperly installed or is fouled; it should be replaced. Changeout the carbon bed when lab

analysis shows no in.,rovement in color or foaming tendency in vs. out of the bed meaning that the bed is no longer removing hydrocarbon. 20. FILTER

Typically regulated a manus II y adjusted valve. by

The operator should backwash (or change out cartridge fil ters) at the point where the pressure drop reaches the reconmended maxinun and the mininun slipstream flow rate .can no longer be maintained. 21. FILTER BACKWASH (for lM"Iits with backwash-type fil ters)

Hot water or steam depending on fi l ter type.

Automatic backwashing system is activated by high pressure drop across filter elements. Cycle time varies depending on IIIIIOU'It of particulates or wax.

22. RECLAIMER (for MEA or DGA, only)

AMINE TREATING

Batch operation.

2.20

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

STREAM OR EQUIPMENT NAME

CONTROLLED VARIABLE TEMPERATURE

PRESSURE

23. CHEMICAL INJECTION (caustic, anti foam, corrosion inhibitor)

AMINE TREATING

FLO\I

LEVEL

Regulated by injection pump or shot pot.

2.21

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

2.4

Equipment

There is no equipment used in amine units that is not used widely in other refining and gas processing facilities. Amine units consist of columns, heat exchangers, separator vessels, pumps, and filters. Absorber Absorbers are trayed or packed columns in which rising gas contacts descending amine. Typical columns have either 20-25 trays or 30-40 feet of packing. Absorbers in hydroprocessor hydrogen recycle loops typically use only 20' of packing due to the high driving force for HS absorption and the amount of H2S that can be left in the swee~ gas (100 ppmv or more). Absorbers in hydrogen plants frequently have an additional 2-4 trays above the amine feed tray where water contacts the sweetened gas and removes any vaporized or entrained amine. This is necessary to protect the methanator, since amines are methanator catalyst poisons. The water is withdrawn from the absorber at the tray above the amine feed tray. Amine absorber trays often require unusually large downcomer areas. Amine absorbers are frequently designed for higher than normal liquid loadings, and amine solutions have a much higher foaming tendency than liquid hydrocarbons exhibit. The combination of these two factors make large downcomers common in amine trays. Many amine absorbers use two-pass or four-pass trays. In absorbers using MDEA or formulated solvents, the weirs may be higher than normal in order to provide greater liquid hold up and thus more time for reaction between CO2 and the amine. Weirs can be 4" or higher in these applications. Packed absorbers are designed for a low pressure drop, typically 0.25" of water per foot of packing, due to the high foaming tendency of amine solutions. Packed sections are usually no more than 15': this reduces the risk of poor liquid distribution. In hydroprocessor hydrogen recycle absorbers, typically only one packed section with one liquid distributor is used. This may lead to liquid distribution problems and loss of efficiency in absorbers with packed sections greater than 20'. The surge volume at the bottom of the absorber should be kept as small as possible, since surge volume can be provided less expensively in lower pressure vessels. Four minutes of circulation volume is a minimum value. Absorbers may be equipped with mist elimination pads to recover entrained amine from the treated gas. These pads should be made from metal rather than plastic. Metal pads will have higher AMINE TREATING

2.22

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

removal efficiencies, since amine solutions will wet metal surfaces better than plastic surfaces. Mist elimination pads will not prevent carryover of amine solution if a foaming upset occurs in the absorber. In order to capture this amine, a treated gas knockout drum downstream of the absorber is required. If a treated gas knockout drum is used, it is not necessary to use a mist elimination pad in the absorber. Flash Drum The flash drum is a separator vessel in which absorbed and entrained hydrocarbons are disengaged from the rich amine. It is almost always a horizontal separator. Flash drums typically operate at pressures between 2 and 150 psig. The flash gas, . depending on the facility and the concentration of H2S, may be sent to the fuel gas system, a vapor recovery unit, or a sulfur recovery unit. For amine units operating at low flash drum pressures a rich amine pump may be required to overcome frictional losses and static head in the line to the stripper. A liquid hydrocarbon phase is frequently produced in the flash drum. If this phase is not recovered as a separate liquid stream, much of it will end up in the acid gas from the stripper reflux drum •. This might cause problems in a Claus plant. In order to remove these liquid hydrocarbons, most flash drums are designed as three phase separator vessels. The liquid residence time in the flash drum is determined by the time required to separate the liquid hydrocarbons from the amine. A residence time of 10-15 minutes should be considered to be a minimum value. In order to reduce the size of the vessel, the normal liquid level can be set above its centerline. Lean/Rich Amine Heat Exchanger The lean/rich amine heat exchanger transfers heat from the lean amine stream leaving the amine stripper to the rich amine being fed to the stripper. It contributes to the energy efficiency of the unit, since without it more heat would have to be added at the stripper reboiler and more removed at the lean solvent cooler. Lean/rich exchangers are designed with temperature approaches between 35 0 Fand 50~. A rule of thumb is that if the rich amine piping between the lean/rich exchanger and the . stripper is carbon steel, the rich amine temperature leaving the exchanger should be no greater than 215 0 F. If stainless steel piping is. used in this section, however, higher temperatures can be used without corrosion problems. In most facilities, the lean/rich exchanger is a shell and tube exchanger. The rich amine is generally the tube side fluid, AMINE TREATING

2.23

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

while the lean amine is on the shell side. This selection is made for two reasons: the rich amine becomes a two-phase mixture as it is heated in the exchanger, and it is more important to minimize the pressure drop of the lean amine. Plate and frame exchangers have been used in some offshore amine units where their lower weight and smaller size are significant advantages. Amine stripper Amine strippers or regenerators are distillation columns in which CO 2 and H2S are driven out of the amine solution. They typically contain between 20 and 25 trays. The rich amine enters the column no lower than the fifth tray from the top. Amine solution descends through the column and is stripped by steam rising from the reboiler. The steam provides the energy to break the chemical bonds between the amine and the acid gas. It also drives the reaction equilibrium in the direction of regeneration by carrying away the H2S and CO2 that are evolved from the amine. Amine solution at the bottom of the column circulates through the stripper reboiler. The reboiler generates the steam that serves as the stripping gas in the column. A variety of reboiler types can be used, including horizontal and vertical thermosyphons and forced circulation reboilers. steam is the most widely used heating medium, although hot oil is used frequently in upstream plants. A few plants use direct~fired reboilers, although these are not preferred due to the risk of overheating the amine and causing degradation. The purpose of the reboiler is to generate stripping steam. stripping of the amine should take place on the first few trays below the feed tray and not in the reboiler. The amine entering the reboiler should be almost completely stripped of H2S and C02. If it is not, acid gases will evolve from the amine in the reboiler. This will cause rapid and severe corrosion in the reboiler, reboiler return line, and the lower section of the stripper. Inadequate stripping of the amine in the column can occur if trays in the stripper are damaged, if the rich amine entering the column is too cold, or if the amount of boilup in the reboiler is too low. The trays above the feed tray serve as wash trays where refluxing water removes vaporized amine from the rising steam and acid gas. , Two trays are used in this section in most designs, although up to five can be used. Some strippers do not use any water wash trays at all. The acid gas and steam exits the top of the stripper and passes through the overhead condenser. This cooler cools the stream to 100-130 o Fand condenses the steam in the overhead stream. The mixture then enters the reflux drum, where separation of the acid gas and condensed water takes place. The AMINE TREATING

2.24

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

acid gas goes to sulfur recovery, flare, or vent, depending on the amount of sulfur it contains and terms of the facility's emissions permits. In order to minimize reboiler energy requirements and amine degradation rates, the stripper should be operated at the lowest possible pressure. Most strippers operate with overhead pressures between 10 and 20 psig. An overhead pressure controller should be used to ensure steady operation of the stripper as well as the downstream SRU if there is one. The water in the reflux drum is returned to the stripper by a reflux pump. Molar reflux ratios of 1:1 to 1.5:1 are typical. The reflux ratio is determined by the boilup rate in the . reboiler. A low reflux ratio indicates inadequateboilup in the reboiler. This is a sign that the column is not operating properly. If the amount of steam rising through the stripper is inadequate, the amine will not be stripped of acid gas before reaching the reboiler. As previously discussed, operation in this mode will lead to corrosion problems. Amine units treating gas produced in certain refinery operations will pick up significant quantities of ammonia. This will accumulate in the stripper reflux drum in the form of ammonium bisulfide. In order to control the buildup of this material, a sour water purge must be taken. Chevron practice is to operate with a purge rate high enough to keep the concentration of ammonia in the reflux drum below 1.0 wt%. This sour water may be processed in a sour water stripper associated with the amine unit, or it may be routed to a sour water treating system elsewhere in the refinery. Pumps There may be two sets of pumps for the lean amine solution: the booster pumps and the circulation pumps. The booster pumps pump the lean amine solution leaving the stripper. They provide enough head to get the amine solution through the lean/rich exchanger, the lean amine cooler, and the filters. These pumps are usually designed for discharge pressures of less than 100 psig. The circulation pumps pressurize the lean amine for high pressure absorbers. They are often two-stage pumps, since the lean amine comes to them from the surge tank at close to • atmospheric pre~sure. Refineries will often perform both functions with a single pump. Lean Solvent Cooler The lean amine cooler cools the amine to the temperature at which it is fed to the absorber. The temperature of the amine leaving AMINE TREATING

2.25

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

this exchanger should be 10-lSoFabove the temperature of the gas entering the absorber. If the amine is cooler than the gas, hydrocarbons may condense and cause foaming. The amine and gas temperatures should be measured as close as possible to the absorber. In amine units where MDEA is used to remove H2S selectively, the performance of the unit will be very sensitive to the temperature of the amine entering the absorber. A temperature change of SOF will have a significant effect on the amount of CO2 that is absorbed. More CO2 removal may increase the temperature of the gas above the top tray, which will increase the equilibrium concentration of H2S in the gas. As a result, close control of the amine temperature at the outlet of the lean amine cooler is essential. Amine Surge Tank The amine surge tank provides storage capacity for the amine inventory in the plant. These vessels should be blanketed by an inert gas to prevent oxygen from coming into contact with the amine. Make-up water and amine are normally added in this vessel. Filters Filters are used to prevent a buildup of particulates in the amine stream. It is necessary to remove suspended particulates which can increase erosion, corrosion, foaming and equipment plugging. Most of the particulates enter the system with the feed gas and collect in the amine. Filters may be located in the rich amine downstream of the flash drum where they will do the most good to protect the lean/rich exchanger and stripper (see section 3.9). Typically the filters are located on the lean side where the filter elements can be changed with minimal risk of exposure to H2S. It is preferred to filter the entire amine stream, although some plants are designed for slipstream filtration. Bag, sock, cartridge, and mechanical filters have been used. Bag filters are recommended when the amine solution contains high levels of particulates because they are less expensive and easier to replace than the other types of filters. Sock filters have a tendency to break when they fill with particulates. The main advantage of mechanical filters is that the elements do not have to be replaced regularly. Mechanical filters are used on the amine plants at Gaviota and Carter Creek. These filters use sheets of fine metal mesh as their elements. When the differential pressure reaches 10 psi, the filters are AMINE TREATING

2.26

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

automatically backwashed with amine solution. The amine is routed to a cone-bottomed backwash tank, where most of the particulates settle to the bottom. Solvent from the backwash tank is returned to the amine storage tank. Gaviota uses a sock filter on the amine leaving the backwash tank to remove any particulates left in the amine. Both Gaviota and Carter Creek have been pleased with the performance of these filters. Particulate filters should remove all particles greater than 5-10 microns in diameter. Filters with an absolute rating of 5 or 10 microns should be used. An absolute rating means that the filter will remove over 99% of the particulates greater than the rated size from the solution. (Vendors also use a IIrelative" rating for filters; these remove a smaller percentage of the particulates greater than the rated diameter from the solution.) If the amine contains too many particulates, it will be very difficult to use 5-10 micron-rated filters because they will plug very rapidly. In these instances, filters rated for 25 micron or larger particles should be used for a brief period. Once these filters begin to last for a reasonable length of time, they should be replaced with filters rated for slightly smaller particles. By working down in this manner, filters rated for 5 or 10 micron particles can be installed eventually. Activated Carbon Beds Activated carbon is used to remove dissolved hydrocarbons and other organic impurities from the amine solution. Normally, a slipstream of 10% to 20% of the circulating amine should pass through the carbon filter. An additional particulate filter may be added downstream of the carbon bed to remove any carbon fines that may be entrained by the amine passing through the carbon bed. The carbon will eventually become saturated with organic impurities and stop removing any more of them from the amine solution. Unlike the particulate filters, the differential pressure across the carbon bed should not increase as the carbon is spent. (If it does, this indicates that the particulate filter is not doing its job and that the carbon filter is being plugged by particulates.) The activity of the carbon filter must be determined indirectly by analyzing the amine. The amine is normally analyzed for hydrocarbon content; this will increase as , the carbon bed becomes saturated. Many operators rely on a visual inspection of the color of the amine entering and leaving the bed to determine when it has become saturated. Once the carbon bed is saturated, it can either be regenerated with steam or replaced. It is estimated that steam regeneration will restore only 80% of the original carbon capacity. After three steam cycles, only 50% of original capacity is restored. So, AMINE TREATING

2.27

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

three or four steam cycles are considered the limit before replacing the carbon.

REFERENCES

2.1

Astarita, G., D. W. Savage and A. Bisio, Gas Treatinq with Chemical Solvents, John Wiley & Sons, 1983, Chapter 15.

2.2

Kohl, A. L., and F. C. Riesenfeld, Gas PUrification, Gulf Publishing Company, 1985.

AMINE TREATING

2.28

JULY 1994

FIGURE 2.1 TYPICAL AMINE PLANT FLOWSHEET

TREATED (DR SWEET>

ACID GAS TO SRU

KNOCKOUT DRUM

PARTICULATE FILTER WATER WASH (FOR H2 PLANTS ONLY) ... \-.(_---1

AMINE COOLER

ACTIVATED CHARCOAL BED

HIGH PRESSURE AMINE CIRCULATION PUMP

REGENERATOR OVERHEAD CONDENSER REFLUX DRUM

LEAN/RICH EXCHANGER

ABSORBER (DR CONTACTOR)

PURGE STRIPPER (DR REGENERATOR)

"50

STEAM MAKE-UP WATER AND AMINE REBDILER FLASH GAS

CONDENSATE

FLASH DRUM

AMINE CIRCULATION PUMP PARTICULATE FILTER

HYDROCARBON

~

o t'I-I

C\iLl.

W-I

a:c::(

S:E ira: o z

~

9 LL

-

I. .J

a.

en

FIGURE 2.3

AMINE EQUILIBRIUM LOADING

-

20 WT% MEA AT 120 DEG F

w

~ 1.0E+02

oC/) CJ 1.0E+01

o-1

,.,,.,.,--'''''~,,..,

EJ""".

,,..,,,,,,,,,,-8--,.......,,------

;;.r 1.0E+00 r::l.-" f::::l-.-"..-_eJ ,,,--,,,,,,-- "'t""..:J

C/)

a..

u.i 1.0E-01 a:

./""B"". . ..---

/'"

/

:::>

~ 1.0E-02 w a: a.. -1

1.0E-03

DEA > MDEA (see Table 3.2.1). Reboiler duty is composed of three components: sensible heat, latent heat of vaporization, and heat of reaction. Table 3.2.1:

Soln strength Wt%

Typical Operating Conditions

MEA

DGA

DEA

DIPA

MDEA

15-20

40-60

25-35

20-40

45-55

Max. Rich Loadings, m/m HzS or total m/m CO z only (3)

S.40 .30-.35

S.50 .30-.40

S.50 .35-.40

S.50 .35-.40

Max. Lean Loadings, m/m (3)

.10-.15

.08-.10

.05-.07

.04-.06

.004-.010

Heat of Reaction, Btu/lb HzS (1,2)

550

674

511

526

522

Btu/lb co z (1,2)

825

850

653

703

600

Notes:

.45-.50 .40-.45

m/m = moles acid gas/mole amine heat of reaction for loadings below 0.5 m/m (1) sources: (1) Polasek, 1985; (2) TPA, 1991; (3) DuPart, 1991.

solution strength: In general, the corrosivity of aqueous amine solutions is highest for the primary amines and lowest for the tertiary amines. Because of differences in solution corrosivity, the higher order amines tend to be used at higher concentrations, the exception being DGA. This results in more moles of amine per gallon of circulating solution as seen by: amine steangth 15 wt% MEA 30 wt% DEA 40 wt% DIPA 50 wt% MDEA 60 wt% DGA

lbmoles/gal 0.021 0.024 0.025 0.036 0.049

The rich acid-gas loadings tend to be somewhat higher too. The net result of these two factors is that tertiary amines generally require less circulation for a given amount of acid-gas absorption thus saving pumping cost, regeneration cost, and capital cost (smaller equipment). SOLVENT CHARACTERISTICS

3.3

JULY 1994

Table 3.1.1: Physical Properties of Amines

'.

Secondary Amh>.~s

Primary Amlnes

Tertiary Amlnes

monoethanolamine

diglycolamine

diethanolamine

diisopropanolamine

methyldiethanolamine

MEA

DGA

DEA

DIPA

MDEA

Formula

HOC2H4NH2

HOC2H40C2H4NH2

(HOC2H4)2NH

(CH3CH(OH)CH2)2NH

(HOC2H4 )2NCH3

Mol. Wt.

61.1

105.1

105.1

133.2

119.2

339

430

516

480

477

Spec. Gravity, 60F

1.018

1.058

1.095

0.999

1.043

Specific Heat, Btu/lb-F

0.608

0.571

0.60

0.69

Thermal Cond., Btu/hr-ft2-F @ 77F

0.147

0.124

0.111

0.111

0.0906

Viscosity, cP .77F

18.9

26

352@86F

870@86F

173

Surf. Tension, dyne/cm • 77F

49.9

58.6

102.9

101.5

100.5

Heat of Reaction, Btullb acid gas, H2S

-550

-674

-511

-526

-522

-825

-850

-653

-703

-600

15-25

40-60

25- 35

20-40

45 - 55

0.50

0.50

0.45 - 0.50

Solvent Short Name

b.p, F

CO2 wt.% Range

0.60

. Loadings, m/m Rich, H2S or Total

0.40

0.50

Rich, CO2

0.30 - 0.35

0.30 - 0.40

0.35 - 0.40

0.35 - 0.40

0.40 - 0.45

Lean, Total

0.10-0.15

0.08 - 0.10

0.05 - 0.07

0.04 - 0.06

0.004 - 0.010

0.47

0.94

1.45

Cost, $lIb (99% truckloads, TX 4/94)

0.46

0.90

source: Dow Alkanolamines Handbook; Gas Conditioning and Processing, Vol. 4, R.N. Maddox, Campbell Petroleum Series; and HYSIM.

Page 3.3a

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Hydrocarbon Solubility: The greater the number of alkyl groups (-CH?-, -CH3 , etc.) and the fewer the number of hydroxyl groups (-OH) present on an amine molecule, the greater will be the hydrocarbon solubility in the amine solution and the greater the solubility of the amine in a liquid hydrocarbon stream. Hydroxyl groups suppress hydrocarbon solubility while increasing water solubility and reducing vapor pressure due to hydrogen bonding. Based on this group-contribution argument, the expected trend in hydrocarbon solubility (highest to lowest) is: DGA > DIPA > MDEA > DEA, MEA. Keep in mind that hydrocarbon solubility is also a strong function of amine strength. Higher amine concentrations give rise to higher hydrocarbon solubilities.

H2S Selectivity: As stated above, tertiary amines are unable to form carbamates with CO2 • CO2 is only absorbed via the relatively slow acid-base reaction pathway. This slower CO2 reaction rate with tertiary amines allows them to slip more CO2 and absorb a higher proportion of H2S than primary and secondary amines. Selectivity is improved by lower temperatures and short contact times. The higher the temperature the faster the CO2 reaction rate becomes. Use of short contact times (shallow weirs, fewer trays) limits the time available for CO2 reaction. Keep in mind that the reaction rate for H,S is instantaneous, and absorption i~ limited by mass-tr~nsfer rates. CO2 absorption is generally limited by reaction rates. Hindered amines also show good HS selectivity. Hindered secondary amines, such as DIPA, have bulky hydrocarbon groups which block easy access of CO~ to the nitrogen thus slowing carbamate formation and reduc~ng its stability. FLEXSORB, an expensive proprietary amine from Exxon, is a severely hindered amine which shows excellent selectivity in low pressure applications. Deep CO2 Removal: In order to remove CO. down to very low levels «100 ppmv) , MEA is the generic amine of choice since it provides the lowest partial pressure of acid gas for a given loading. The solvent vendors all have proprietary blended amines which offer deep removal and increased acid-gas capacity (scf/gal). These are often blends of MDEA and MEA or DEA. Activated MDEA, offered by BASF, uses piperazine as the "activator" for increasing cO2 absorption capacity. COS Removal: Primary and secondary amines are reactive to COS. The drawback is that they are also, to a certain extent, degraded by COS. For MEA, 20% of the absorbed COS undergoes an irreversible degradation reaction, and therefore MEA is not advised for high COS service. For DGA, the degradation products are substantially reversed at high temperature in the reclaimer. COS removal by DGA increases with increasing DGA temperature and SOLVENT CHARACTERISTICS

3.4

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

contact time. Removals as high as 75% or more can be achieved (Moore, 1985). DEA undergoes some minor degradation. DIPA has been reported to have severe, irreversible degradation with COS (Astarita, 1983), but others claim only slight degradation (Butwell, et al.,) which is probably the case. Shell offers a hybrid solvent (Sulfinol D) using DIPA for the purpose of enhanced COS removal. Use of long-contact-time polishing columns using hot, very lean amine have been recommended for COS removal. The goal here is to first remove H~S and CO2 which, being stronger acids, can displace absorbed COS. The higher temperature and longer contact times speed the reaction rate and absorption. Once COS is absorbed, a portion of it is hydrolyzed to H2S and CO2 • RSH Removal: DGA is the most effective of the common generic amines at methyl and ethyl mercaptan removal with reports of up to 65-75% (Texaco). This is mostly due to DGA's higher hydrocarbon solubility. Mercaptans are only slightly acidic, and reactive absorption into alkaline amine solutions is poor. But due to the hydrocarbon chain on the mercaptan molecule, they are more readily absorbed by physical solubility. The other amines only offer partial mercaptan removal. For absorption by MEA and DEA, 40% to 55% removal of methylmercaptan, 20% to 25% removal of ethylmercaptan, and 0% to 10% removal of propylmercaptan have been reported (Butwell, et al.,). Hybrid solvents, because of their physical solvent component (sulfolane in the case of Shell's Sulfinol), are sometimes used for mercaptan removal. 3.3 Solution Quality

.

Poor solution quality will lead to a variety of problems: excessive solution losses due to foaming and amine degradation, excessive corrosion rates, equipment fouling and plugging, excessive filter changeouts, excessive circulation rates and regeneration duty, offspec performance resulting in shut-in production and possibly environmental permit exceedances. If poor solution quality is maintained in an amine plant, expect high operating and capital costs to result. Poor performance by the amine plant can also impact other unit operations adversely. Downstream compressors can be damaged by amine carryover. Claus sulfur-recovery unit catalyst can be harmed by excessive hydrocarbon in the acid gas. Hydrotreater catalyst life can be reduced over time by high H2S • The philosophy for designing and operating an·amine plant, or any plant for. that matter, is to solve the causes of problems not just treat the effects. For instance, if a unit begins to consistently foam, treat with antifoam injection to solve the immediate problem and then determine and correct the cause of the foam. In this chapter several problems associated with poor SOLVENT CHARACTERISTICS

3.5

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

amine-solution quality are described as to causes, consequences, and correction. By understanding the issues governing aminesolution quality, proper decisions can be made in plant operation which will minimize these problems. This understanding should also be used in the design of new plants or in the retrofit of existing plants in order to minimize some of the root causes of poor amine-solution quality. Contaminants: Amine solutions can become contaminated by a variety of chemicals. Most of these contaminants are harmful to ~he solution because they cause foaming, enhance amine degradation, or cause corrosion rates to increase. They should be prevented from entering the system if at all possible; and once in, should be managed at tolerable levels. These topics will be covered in subsequent sections. Table 3.3.1:

Common Amine Solution contaminants

treatment chemicals hydrocarbon particulates/scale oxygen carbon monoxide organic .acids ammonia salts

foaming foaming erosion, foaming degradation, corrosion degradation HSS, corrosion no harm corrosion

Ammonia is not harmful to amines; it is expelled in the stripper overhead (Kohl, 1985). However, sometimes ammonium salts can form in stripper overheads. (See "Amine Stripper" in section 2.4 and "General Corrosion" in section 4.1). Table 3.3.2:

Some Recommended Maximum contaminant Levels

Particulates Chlorides Hydrocarbon HSS Iron Degradation prod.

SOLVENT CHARACTERISTICS

200 mg/l 500 ppmw 0.1 wt% oil & Grease by freon extraction (Coastal) 10 wt% of total amine complexed. (see HSS section 3.5) 25 ppmw no spec.

3.6

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

3.4

Amine Degradation

Consequences: Amines can undergo both thermal and chemical degradation to create byproducts which may promote fouling, corrosion and foaming (Meisen, 1993). Corrosion occurs due to the acidic or chelating nature of some of the products (Chakma, 1986; TPA, 1991). Higher solution viscosities caused by degradation products may lead to pumping and heat exchanger problems (Meisen, 1993) as well as reduced mass-transfer efficiency. Higher circulation rates may be required in order to circulate the same quantity of active amine thus leading to increased erosion/corrosion and higher pumping and regeneration costs. Thermal degradation: The rate of thermal degradation increases with increasing amine concentrations and temperatures. In order to minimize thermal degradation, (Bacon, 1987) offers the following maximum guidelines: Bulk temperature Tube skin Temp. Heat flux

260°F 350°F 6,000 to 8,000 Btu/hr/ft2

A more recent paper by Dow recommends a maximum bulk amine temperature of 255°F and a heating medium with a maximum temperature of 300°F, (DuPart, 1991). Another source recommends keeping heat exchanger skin temperatures below 400 F to 450 F, preferably below 400 F (Simmons, 1991) Chemical degradation: This degradation mechanism is caused by a variety of contaminants, and different amines may be more or less susceptible to chemical degradation. Primary and secondary amines undergo chemical degradation in the presence of CO2 , COS, and CS 2 while tertiary amines do not. (Kohl, 1985). This degradation is accelerated by increasing CO2 , CS 2 ' and COS content, amine strength, and temperature (Dawodu, 1989; Meisen, 1993). COS irreversibly degrades MEA while the degradation product formed between DGA and COS can be thermally regenerated in the reclaimer, often standard equipment for DGA systems. Avoid use of MEA in high COS service. DEA undergoes some degradation by COS (Meisen, 1993). Exxon, in a discussion the 1991 Lawrence Reid Conference, mentioned that CO will react with amines to form formates, especially at high temperatures and pH. All amines are subject to oxidative degradation but some are more susceptible than others. Oxidative degradation products include carboxylic acids, which form heat-stable salts (HSS) with amine and ammonia (Bradley, 1987: Pauley, 1988). Tests at CRTC showed the following resistance to oxidative degradation: MDEA > MEA > DEA (Manning, 1988; Robb, 1990): these test trends were confirmed SOLVENT CHARACTERISTICS

3.7

JULY 1994

"-,

-

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

by Dow (DuPart, 1991). CRTC also showed that some of the formulated MDEA-based solvents are more susceptible than generic MDEA. Oxygen can also react with H2S to form sulfur species which can contribute to corrosion as well as react with the amine to form HSS (Kohl, 1985). It is very important to exclude oxygen from amine systems by inert blanketing amine storage vessels and eliminating leaks in vacuum vapor-recovery systems. HSS are covered in more detail in section 3.5. Degradation products and analysis: Individual degradation products, other than HSS, can be determined by gas chromatography and gas chromatographY/mass spectroscopy, although this requires a specialized lab which has developed calibration standards for the various degradation products. Total degradation products can be determined by performing a Kjeldahl total-nitrogen analysis and a total amine analysis. A comparison of total nitrogen with amine nitrogen will give an indication of the degree of degradation of the amine. Any ammonia absorbed from the feed gas and not stripped out of solution will provide some error in this analysis. A correction for thiocyanate is necessary if it is present as a HSS.

SOLVENT CHARACTERISTICS

3.8

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Some Common Amine Deqradation Products: (Meisen, 1993)

OZD HEI HEED BHEEU BHEETU HEOD BHEP THEED BHEED HEI BHEI HMPO EG HMP DEP HEP

product

source

oxazolidone hydroxyethyl imidazolidone hydroxyethyl ethylenediamine diethanolurea bis(hydroxyethyl)ethoxy urea bis(hydroxyethyl)ethoxy thiourea (both reversed in reclaimers) N(hydroxyethyl)oxazolidone (reversed to DEA by NaOH) bis(hydroxyethyl)piperzine Tri (hydroxyethyl) ethylenediamine bis (hydroxyethyl) ethylenediamine hydroxyethyl imidazolidone bis(hydroxyethyl)imidazolidone (hydroxymethylpropyl)oxazolidone ethyleneqlycol hydroxymethylpiperazine Diethanolpeperazine N(hydroxyethyl) piperazine

MEA-C02 MEA-COS DGA-C02,COS DGA-COS,CS 2 DEA-C02

DEA-COS DIPA-C02 MDEA

Removal: High-boiling degradation products are removed by distilling the amine overhead (see section 3.10 Amine Reclamation). COS-induced degradation of DGA is reversible at high temperatures and reclaimers are standard equipment on DGA systems (Kohl, 1985; Moore, 1985, Meisen, 1993). Caustic addition has been reported to reverse some DEA degradation products such as HEOD (Meisen, 1993). The jury is still out on how effective activated carbon is in removing degradation products. Some say that it is not effective and that the carbon quickly becomes saturated (Meisen, 1993). Others claim that some degradation products are removed by activated carbon filtration. Effective removal most likely requires distillation or purging.

SOLVENT CHARACTERISTICS

3.9

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

3.S Heat-Stable Salts Definition: In aqueous amine systems heat-stable salts (HSS) are the reaction products of organic and inorganic acids such as formic, thiocyanic, and thiosulfuric and the alkanolamine. Because these salt formation reactions are not reversed in the higher-temperature amine regenerator, they are called heat stable. Table 3.5.1 lists some of the common HSS-forming acids found in amine systems and their chemistry. Sources: Heat-stable salts and their precursors enter the amine system in a variety of ways. Often the acids are carried into the system in the inlet gas. Upstream processes such as cokers and FCC's produce organic and inorganic acids as byproducts. If these acids are not first removed from the gas, they will pass to the amine unit where they will react and form HSS. Oxygen, if present in the feed gas, will contribute to amine degradation which can lead to the formation of formic as well as other acids (Bradley, 1987). Oxygen can react with H2S to form thiosulfuric acid via elemental sulfur (Kohl, 1985). If there is one single step that will contribute most to maintaining a healthy amine solution it would be adequate feed gas pretreatment by such means as water washing, filter separators, coalescing filters, and oxygen exclusion. Water washing the inlet gas will remove organic acids formed in cracker units. Consequences: HSS are detrimental to the operation of the amine plant for several reasons. First, high levels of HSS are associated with higher corrosion rates. Second, high HSS levels are associated with more frequent foaming incidents. Foaming tendency increases due to higher levels of corrosion-byproduct iron sulfide particles which will stabilize foams. It is also reported that high levels of organic acids which form HSS can polymerize to form long-chain organic acids which cause foaming. Third, HSS reduce the efficiency of the amine solution. Because the portion of the amine in solution is bound by salt anions is not available to react with acid gases such as H2S, higher amine circulation rates are necessary. Guidelines:

In general it is recommended that no more than 10 This is only a guideline as every amine plant will differ (different salts, • hydrodynamics, temperatures, acid-gas loadings, etc.). Certain HSS are worse than others, and recommended maximums for individual species are given below. It is best to keep good plant operating records on corrosion rates, HSS levels, amine strength, loadings, and circulation in order to determine when HSS reduction is necessary. wt% of the circulating amine be bound by HSS.

SOLVENT CHARACTERISTICS

3.10

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Maximum Recommended HSS Levels Total HSS

10 wt% of total amine*

Formate Acetate oxalate Glycolate Thiocyanate Thiosulfate

2000 ppmw in total solution 2000 ppmw in total solution 3000 ppmw in total solution

N/A 10,000 ppmw in total solution 10,000 ppmw in total solution

* This does not mean that 10X of the solution is HSS. It means, for example in the case of 100 lbs of 30 wtX DEA solution, that 3 lbs of DEA is bound by HSS and only 27 lbs of DEA is available to react with acid gases. If all of the bound amine were bound to formate, the concentration of formate in solution would be 13,000 ppmw or 1.3 wtX.

HSS Analysis: The determination of the different HSS-specie concentrations requires ion chromatography (IC). IC analysis can be provided by many of the solvent vendors. CRTC's analytical lab also provides IC (contact: Mr. Muigai Karigaca, CTN 242-3701). Potentiometric titrations and conductometric titrations do not provide speciation but can be used to determine total amine and bound amine. See the Monitoring Appendix for details. Removal Methods: There are several ways to remove HSS from amines: purge and makeup, vacuum and steam distillation, ion exchange, and electrodialysis. Purge and makeup may be the least expensive option for small systems. The main costs are the price of fresh amine and the disposal costs of the degraded amine. The other options are dealt with in more detail in the section 3.10 on reclaiming amines and in the HSS Best Practices Guide. As a temporary stopgap measure, caustic addition is sometimes used to reactivateamines. While caustic does not actually remove any salts, caustic, being a stronger base than the amine, frees up bound amine by substituting sodium for the amine portion (cation) of the salt. There are limits to how much caustic can be added; Union Carbide recommends a maximum of 1.5 wt%. Too much caustic can cause salt precipitation, especially sodium oxalate, and reduced amine performance. There are conflicting reports as to whether the sodium form of HSS formed by caustic addition are more or less corrosive than the amine form of HSS. MPR reports sodium-HSS to be as or more corrosive than the amineHSS (Mecum, 199~). Union Carbide disagrees. Chevron's· Pascagoula refinery has found that adding caustic to their DEA system re~ulted in a reduction in laboratory measured corrosion rates. The sodium-bound HSS still remain in the system and these must eventually be removed either by reclaiming or by purge and makeup. Guidance on caustic addition is provided in the HSS Best Practices Guide. SOLVENT CHARACTERISTICS

3.11

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

TABLE 3.5.1:

HEAT-STABLE SALTS/ACIDS

Reaction with amine: amine:

Am = RNH 2 ,

Heat-stable Salt Precursor Acid:

HSSH

HSSH +

Am



~NH,

or

~N

= RCOOH, HSCN, H2S20 3 , etc.

AmH+ + HSS·

Neutralization with caustic: NaOH +

~

+ HSS·

Am

+ Na+ + HSS· + H20

ACID

FORMULA

Ko1Wt

n))p C

pita l/plta 2 @ 2SC

Formic

HCOOH

46.03

100.7

3.75

Acetic

CH~COOH

60.05

117.9

4.75

Propanoic (propionic)

CH3CH2COOH

74.08

141. 0

4.87

Glycolic

HOCH,COOH

76.05

decomp.

3.83

n-Butanoic (n-butyric)

CH3C2H4COOH

88.12

163.5

4.81

Oxalic

HOOCCOOH

90.04

157

1.23/4.19

subl. Benzoic

CAHJ;COOH

122.13

249

4.19

Thiocyanic

HSCN

59.09

decomp.

-2

Thiosulfuric

H,S,O~

114.14

---

.6/1.74

Sulfuric

~SO.'.

98.08

338

-3/2

Hydrogen Sulfide

~S

34.

-60.4

7/12.9

CO2 Carbonic Acid

H2C03

62.

-78.5

6.3/10.3

ACID GASES

SOLVENT CHARACTERISTICS

as

3.12

CO~

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

3.6 Foaming

Indications: Foaming in amine systems can result in offspec treated gas as well as high losses of amine solvent. Foaming is first indicated by high and/or fluctuating pressure differential (delta P) across the scrubber trays or packing (flooding is also indicated by these signs). Severe foaming will be indicated by high carryover of amine to the absorber knockout drum, a drop in level· or bouncing liquid levels in the columns and flash drum, and erratic feed to the stripper (Stewart, 1991). Offspec gas will likely result. When the delta P, in feet of water, is greater than 40% of the height between the bottom tray and the top tray, the scrubber is probably foaming (Lieberman, 1987). Causes: Foaming can be caused by condensed or dissolved hydrocarbon in the amine, lube oils from gas compressors, treatment chemicals such as corrosion inhibitors or excess foam inhibitors, fine particulates, amine degradation ~roducts, organic acids of heat-stable salts, and detergents (Pauley, Dec 1989, July 1991). These contaminants reduce the surface tension of the amine solution or, in the case of fine particulates, help to stabilize foams. Poor operation of the flash drum will leave excessive amounts of hydrocarbon in the amine leading to foaming in the stripper and high hydrocarbon content to the SRU. Prevention: A properly designed and maintained inlet filter separator will do much to remove entrained liquids and particulates from the gas prior to its entering the absorber. For aerosols a coalescing filter is necessary. Maintain lean amine temperature at least 10°F to 15°F above the feed gas temperature to minimize condensation of hydrocarbons. This delta T may have to be higher if a significant portion of the feed gas . consists of acid gas as the dew point temperature increases as acid gas is absorbed. Full flow mechanical filtration of the circulating amine should be installed and properly maintained (see section 3.9 Filtration for more details). Beware that certain raw cotton or unwashed fabric elements may cause severe foaming when first placed in service due to oil or soap coatings. TPA recommends using virgin spun white cotton. Activated carbon beds should be installed and properly maintained on a slipstream of at least 10-20% of the circulating amine. Carbon fines, if not backwashed from the bed before being placed in service, can cause severe foaming. Mechanical filters should be placed both • upstream and downstream of the carbon bed (see section 3.9 Filtration). When any new equipment is installed, be sure to thoroughly wash all oils and detergents from the equipment prior to startup or severe foaming may occur. At least a 10-15 minute rich amine residence time in the flash drum is recommended to separate hydrocarbon from the circulating amine. As long as 30 minutes rich amine residence time in the flash drum has been SOLVENT CHARACTERISTICS

3.13

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

recommended for MDEA service (TPA, 1991). Vessel interface hydrocarbon skim taps, when installed, should be used at the first sign of a free hydrocarbon layer. Foam Inhibitors: Foam inhibitors or antifoams are sold by several vendors (Betz, Nalco, VWR, Coastal, Union Carbide). These consist of silica, silicone, high-boiling alcohol and polyglycol based chemicals. The vendor can help select an effective antifoam agent for your system. When foaming occurs, give the system a shot of antifoam, preferably just upstream of where the foaming is occurring. If foaming is a recurring problem, it becomes necessary to determine the cause. Keep in mind that adding too much of some antifoams, such as silicone, can actually make foaming worse. Furthermore, some antifoams such as the silicone-based ones are removed by the carbon filter and overdosing will lead to premature depletion of the carbon. Foam Test: A simple foam test should be done periodically to determine the foaming tendency and foam stability of the amine solution. It involves sparging air through an amine sample and measuring foam height (tendency) during air flow and foam collapse-time (stability) after stopping the air- flow. If the lean amine shows low foaming tendency and stability while the rich solution foams badly, poor inlet separation or insufficient delta T is indicated. If the amine solution foams equally bad on either side of the carbon filter, the carbon is spent and needs to be replaced (Pauley, July 1991). Use a foam test to select an effective antifoam chemical. 3.7

Losses

In an excellent paper by Dow Chemical Co., five routes of amine loss are identified: vaporization, solubility, mechanical, degradation, and entrainment (stewart, 1991). The paper offers a systematic approach to identifying the source of the losses and reducing the losses. First, total amine loss per MMscf of treated gas should be estimated from data on past amine purchases and gas throughput. Also, keep track of amine losses by monitoring tank and vessel levels. Next, identify the primary routes of amine loss for your plant. Then control those losses in the order of their magnitude. Generally, the ranking of losses from highest to . lowest in a gas plant is mechanical, entrainment, vaporization, degradation. When a liquid treater shares the amine with a gas absorber,-the ranking is mechanical, entrainment (in liquid), solubility, entrainment (in vapor), vaporization, degradation (stewart, 1991). Be warned that as the loss rate is reduced, the purge rate of contaminant loss is also reduced. Expect an increase in contaminant levels, and monitor and control these SOLVENT CHARACTERISTICS

3.14

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

contaminants during the amine-Ioss-reduction process by adequate mechanical and carbon filtration. Vaporization Losses: Vaporization losses increase with increasing top-stage temperature, increasing amine strength, and decreasing pressure. The Dow paper includes graphs for estimating vaporization losses for MEA, DEA, and MDEA. For a typical fuel-gas absorber and flash drum, the estimated vaporization losses in the overhead streams would be: Vaporization Loss Estimates (stewart, 1991):

Pressure, psia Temperature, of

Absorber 100 120°F

Flash Drum 50 140°F

Amine Loss. lb Amine/MMscf: 15 wt% MEA 30 wt% DEA 50 wt% MDEA

3.5 0.028 0.63

12 0.19 2.9

If the pressure were 1000 psia, the vaporization losses would be about one tenth of these values. Vaporization losses from the stripper are ·relatively small due to condensed-water reflux containing only 1 to 5% amine and to low acid-gas flows. Vaporization losses can be reduced by lowering the temperature of the lean amine while still maintaining the 10 to 15°F differential above the feed gas temperature. Installing waterwash trays above the lean amine inlet is also very effective. water wash trays on the flash tank vapor outlet may also be advisable. Solubility Losses: Solubility losses occur in amine treating of liquid hydrocarbon streams such as LPG. These losses increase with increasing temperature, decreasing pressure, and increasing amine concentration. Because temperature and pressure are maintained within narrow limits on an LPG treater, reducing amine concentration is the primary solubility-loss control adjustment. The Dow paper provides graphs of MEA, DEA, and MDEA solubility in propane and butane at 77°F and 300 psia. These graphs show the benefit of reducing amine concentration. Reduction in amine . concentration can't always be done when the amine is shared by a gas treater. Water washing the treated LPG stream, as with gas streams, is often used to recover dissolved amine. This is especially necessary if DGA is used in a liquid treater due to its high solubility in hydrocarbons.

SOLVENT CHARACTERISTICS

3.15

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Solubility of Amines in Liquid Propane and Butane (Stewart, 1991) (77Op and 300 psia) Solubility in Propane (ppmw)

Solubility in Butane (ppmw)

10 15

~% MEA ~% ~A

160 265

120 190

20 30

~% ~%

DEA DEA

75 130

50 80

40 50

~%

MDEA MDEA

160 300

95 180

~%

Entrainment in Vapor: This can occur through either a liquid-ingas dispersion (mist or aerosol) or a gas-in-liquid dispersion (foam). Foaming and its control is covered in section 3.6. Heavy mist entrainment is indicated by an overloaded treated-gas knockout vessel: and for aerosols, buildup of amine in low spots and in equipment downstream of the knockout. Causes of entrainment are: -

undersized tower diameter for gas flow operation of tower below design flow operating at or above flooding plugged or damaged trays undersized or damaged amine distributor damaged mist eliminator pad damaged knockout or undersized vessel

Installation of mist pads at the top of absorbers and knockout vessels, either the wire-mesh or vane type, can help control mist entrainment. The knockout vessel should be sized for surge flows not average flows. If gas flows change, check that the vessel and mist pad are still adequate. Entrainment in Liquid: Formation of very small droplets of amine solution within a liquid treater can lead to high losses when the drops are too small to disengage from the liquid hydrocarbon. For this reason liquid treaters are designed for low flows and shear in order.to prevent the formation of small droplets and emulsions. Loss of amine by this route is indicated by the presence of amine in downstream filters and low spots in the hydrocarbon stream. Check that the treater is operating within the Chevron-recommended design parameters for distributor orifice velocities and superficial velocities eLi and Wuopio, 1992). Damaged or plugged distributors may be at fault. Provide a SOLVENT CHARACTERISTICS

3.16

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

gravity separator with enough residence time and low enough velocity to disengage a 100 micron amine droplet. Coalescing filters downstream of the separator will remove the smaller droplets. A water wash does much to recover entrained amine. Estimating Entrainment Losses: Close the knockout vessel dump valve and measure liquid level vs. time to estimate the carryover caught by the knockout vessel. Portable gas-testing equipment can measure entrainment that passes beyond the knockout. A coalescing-filter vendor such as Porous Media or ACS may be able to provide this service. Taking a measured slipstream of gas through a water wash, titrating the water for amine, and then correcting for amine dissolved in the gas (vaporization loss) will provide an estimate of liquid amine entrained in the gas. Degradation Losses: Dow recommends estimating the rate of amine degradation and HSS complexation by doing a rough species balance on HSS and amine degradation products. Assume that the system is in steady state. In other words, the rate of degradation is equal to the rate of degradation product/HSS purge by physical amine losses. Then, by their example, if the amine solution contains 2 wt% degradation products and HSS while the amine solution loss rate is one pound per hour, the active amine degradation ~ate is 0.02 lb/hr. If this rate is high, determine the causes (chemical or thermal degradation, organic acids in feed'gas, etc.) and correct them. Mechanical Losses: Dow writes that this is typically the largest source of amine loss characterized by leaks, drips, and purge streams. Sources are·: -

pipe flange/gasket connection leaks pump seal flushes and leaks pressure gauge and sample purge lines frequent filter changeouts filter cartridge elements overhead fan-cooler tube leaks water-cooler tube leaks leaky amine dump valve

Mechanical losses are estimated as the difference between the estimate for total amine losses and the estimated losses from vaporization, entrainment, solubility, and degradation. • Individual mechanical losses are determined by plant inspection and operating-procedure review. Control these losses by repairing. leaks and routing purge and flush streams to the amine sump tank. Flush the filters with condensate prior to changeout. Before reintroducing amine from the sump back to the main system, the amine should be filtered and the sump should always be under nitrogen blanket. SOLVENT CHARACTERISTICS

3.17

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Amine-Loss Guidelines: The average amine loss from a survey of West Texas gas plants using MEA, DEA, and MDEA was 3 lb/MMscf of treated gas. Because these were mostly high-pressure gas plants, the vaporization losses were a minor component of the total loss rate. For low-pressure refinery amine plants with water-wash trays, the 3 lb/MMscf rate is achievable and losses in the range of 1 to 2 lb/MMscf should be the goal. If water-wash trays are not installed, add the estimated vaporization loss to the 1 to 2 lb/MMscf rate, and set that as a target to remain under. The 1991 MDEA User's Conference recommended a MDEA-loss goal of 2 to 4 lb/MMscf of treated gas. Actual losses were usually 8 - 10 lb/MMscf and sometimes much higher (TPA, 1991). CUSA Products uses a benchmark loss rate of 7-10 lb/MMscf. 3.8

Makeup water

Use high-quality condensate as makeup water to amine systems. Dow's recommended water quality specifications are (Bacon, 1987; DuPart, 1991): Total Hardness Total Dissolved Solids (TDS) Sodium . Potassium Chlorides Iron

(maximums) 3 gr/gal 100 ppm 3 ppm 3 ppm 2 ppm 10 ppm

Periodically check the water balance to determine if leaks are occurring. Declining amine strength may indicate either a water cooler is leaking, if the water pressure is higher than the amine pressure, or a regenerator reboiler tube leak. High TDS in the cooling water and high TDS in the amine may also indicate a cooling water leak (Lieberman, 1987). 3.9

:Filtration

Filtration, mechanical and carbon, is necessary to remove contaminates which promote foaming, corrosion, and erosion. Mechanical filtration removes particulates while carbon "filtration" removes dissolved contaminants. Proper installation . and maintenance. is important. Mechanical Filters Mechanical filtration on 100% of the amine circulation is recommended to remove suspended particulates which can increase erosion, corrosion, foaming, and equipment plugging. Many SOLVENT CHARACTERISTICS

3.18

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

experts recommend filtration on the rich amine just downstream of the flash drum as this will do the most to protect the stripper from particulates picked up by the absorber (DuPart, 1991; TPA, 1991, Veldam, 1994). Rich amine filtration can be done safely if adequate precautions are taken. Before opening the filter, a lean amine wash, condensate wash, nitrogen purge should be done followed by analyzing the vapor space to ensure that H~S levels are below 10 ppmv. Before placing the filter back onl1ne, air should be purged from the housing. Chevron's general practice is with lean-side filtration due to safety concerns. A 5 or 10 micron "absolute" particle-size cutoff rating is recommended on the filter elements. Mechanical filters come in a variety of configurations: cartridge, bag or sock, and automatic backflush. The first three types use disposable elements of various designs and materials. Some are expensive but offer high capacity, dimensional stability under pressure, and ease of replacement. Beware of treated cotton or fabric elements as these may contain surfactants which will cause foaming upon startup. Follow the manufacturer's recommendations for determining time to changeout. Generally this is determined by pressure differential across the filter. Look for filter elements or cartridges which have high removal efficiency and capacity, are quick to change out, and easy to dispose. Generally this means fewer elements will minimize labor and disposal costs. The automatic backflush designs are initially quite expensive, but they save in filter replacement and disposal costs. At a set pressure differential, these units are backflushed with clean amine into a particle settling tank. After settling, the amine is pumped through a conventional cartridge filter and back into the system. Vendors: There are many filter vendors. short list; no recommendations are made.

SOLVENT CHARACTERISTICS

3.19

Table 3.9.1 contains a"

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Table 3.9.1:

Filtration Vendors

1. Cartridge, sock and bag filters are sold by: CUNO Process Filtration, Inc., Meriden, CT 800-243-6894

Facet Enterprises, Inc. Tulsa, OK 918-939-5451

Filterite Corp. Timonium, MD 301-252-0800

Pall Corp., East Hills, NY 800-645-6532

Rosedale Products, Inc., Ann Arbor, MI 800-821-5373

3-M Corp. st. Paul, MN 800-648-3550

2. Automatic-backflush filters are sold by: Vacco Industries EI Monte, CA 818-443-7121

Ronnigen-Petter Portage, MI 616-323-1313

Coastal Chemical Company Houston, TX 713-999-6182

3. Inlet Filter/Separators, Coalescing Filters: ACS Industries Houston, TX 800-231-0077

Burgess Manning Dallas, TX 214-631-1410

otto York Co., Inc Los Alamitos, CA 213-594-0984

Systems, Inc. Houston, TX

~orta-Test

713-771-8961

Porous Media, Inc. st. Paul, MN 612-653-2000 SOLVENT CHARACTERISTICS

3.20

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Carbon Filters Carbon filtration is installed to remove dissolved hydrocarbon and possibly some amine degradation products from the circulating amine by adsorption (Simmons, 1991). It does not remove heatstable salts but may remove HSS precursors (Bright, 1987; TPA, 1992). Carbon beds are often very effective at removing corrosion and foam inhibitors. Carbon filtration on a minimum of 10-20% slipstream is recommended. A general rule of thumb is to filter as large a slipstream as you can afford. Carbon beds should be placed on a cool, lean amine slipstream to prevent acid-gas binding of the bed, for improved filtration efficiency, and for safety reasons {Bacon, 1987; Calgon; Pauley, July 1991). The carbon bed should be protected upstream by a mechanical filter as carbon beds will also remove particulates which would shorten the life of the bed. A mechanical filter downstream of the carbon bed is necessary to remove any carbon fines which can cause foaming. Carbon bed should be provided with 2 to 4 gpm flow per square foot of crossectional bed area, (TPA, 1991; Calgon, 1983; Pauley, July 1991). Flow should be top to bottom and recommended residence times vary from 10 to 30 minutes (Calgon, 1983; Bright, 1987). Lignite carbon, having a mesh size of 8 x 30 or 4 x 10, is reported to have superior performance to wood-based, bituminous or sub-bituminous carbon (TPA, 1991). Determine time for changeout by inlet and outlet amine analysis (foaming tendency/stability, color, and hydrocarbon content) not by pressure differential. The carbon may become spent well before a noticeable pressure differential is seen. High pressure differential may indicate improper installation of the carbon or bridging/clumping of the carbon bed. Spent carbon is generally returned to the vendor for regeneration and resale. 3.10 Reclaiminq

The subject of reclaiming degraded and contaminated amines is covered in detail in the HSS Best practices Guide. This guide describes and gives guidelines for choosing the best reclaiming option for a particular plant and amine solution. Proper choice will depend on system volume, amine type, and nature and concentration of the contaminants. The following options are available and so~rces of these services are given in Table 3.10.1. Distillation: Distillation will remove both HSS and high-boiling degradation products and contaminants, and particulates. caustic is added to first neutralize the HSS. MEA and DGA systems often have thermal reclaimers installed. These are basically small SOLVENT CHARACTERISTICS

3.21

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

atmospheric distillation units. MEA reclaimer bottoms temperature is typicallY around 280°F, and with steam sparging DGA reclaimers maintain a bottoms temperature of 360 to 380°F (Kohl, 1985). DEA and MDEA require vacuum distillation in order to lower the reboiler temperature below the thermal degradation temperature for these amines. Distillation does not remove all degradation products. For instance BHEP is not removed from DEA by vacuum distillation (Meisen, 1993). Because distillation can remove more contaminants than just HSS, if the amine solution contains a significant portion of degradation products as well as HSS, then reclaiming by distillation might be favored. Some solvent reclaiming companies (Canadian Chemical Reclaimers and Industrial waste Processors) bring a mobile distillation unit to your site, process a solvent slipstream for a fee, return the regenerated amine to the system, and leave the water and bottoms sludge for the site to dispose (Millard, 1993). Others, such as Romic, truck the amine to their own plant and then return the reclaimed amine. Romic charges for transportation, water and waste disposal, and then sells back the clean amine. As recently learned at the Richmond Refinery through experience with Romic, reclaiming amines by vacuum distillation occasionally may not work for cleaning up amine solutions to the desired quality, possibly due to the presence of unidentified contaminates. Reclaiming service companies should be willing to run bench-scale tests on samples of dirty amine. Also, detailed laboratory analyses for HSS and other possible contaminants should be run by Chevron or the service company before and after reclaiming to determine the effectiveness of the cleanup. Steam Stripping: In this process performed at essentially atmospheric pressure, a large recycle stream of steam is used to strip the amine overhead while maintaining a bottoms temperature below the thermal degradation temperature of the amine. Currently, this service is offered by Coastal Chemical at their Abbeyville, LA site. Sometimes Coastal will swap previously reclaimed amine for an amine plant's spent amine. Ion Exchange: This HSS-removal process, performed onsite, involves passing a slipstream of lean amine through a series of ion-exchange beds to pullout cations such as Na+ and the typical HSS anions. Charges are based on lbmoles of ions removed. Unstripped H2S counts as an anion (HS·), so it is important to have the amine as lean as possible. The beds are periodically regenerated with acid and caustic. The waste stream is an alkaline solution of sodium salts which can generally be processed by the effluent-treatment pond. Organic amine SOLVENT CHARACTERISTICS

3.22

JU~Y

1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

degradation products are not removed by ion exchange. In addition to charges based on the number of pound moles of salts removed, there are charges for mobilization and delays not caused by the vendor (MPR). The site incurs costs for regeneration chemicals, tank and truck rental, site preparation and supervision, and waste handling. Electrodialysis: This is a membrane-based HSS-removal process called UCARSEP offered by Union Carbide. It does not remove organic degradation products. With this process an electric field drives HSS anions through a membrane in order to remove them from the amine solution. An aqueous salt stream is the waste product .

.

SOLVENT CHARACTERISTICS

3.23

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Table 3.10.1:

SOURCES OF RECLAIMING SERVICES

Ion-Exchange Processes • MPR Services 4600 Park Road, suite 300 Charlotte, North Carolina Contact: Mr. Shade Mecum (704) 523-8282

26209

Vacuum Distillation • Romic Chemical, Company 2081 Bay Road E. Palo Alto, California 94303 Contact: Mr. Ron Tressen (415) 324-1638, Ext. 525 • Industrial Waste Processing P.o. Box 1360 Lyman, Wyoming 82937 Contact: Mr. Chuck Simmons (307) 786-4914 • Canadian Chemical Reclaimers 610 Prairie Meadows Close Bound Brooks, AB T1R OC9 Canada Contact: Mr. Todd Beasley (403) 362-6229, Ext. 2005 Steam Stripping • Coastal Chemical Company, Inc. 363 North Sam Houston Parkway E., suite 380 Houston, Texas 77060 Contact: Mr. Ray Veldman (713) 999-6182 Electrodialysis • Union Carbide Corp. Gas Treating customer support Center 335 Pennbright Dr., Suite 120 Houston, TX 77090-5909 (800) 822-7765 SOLVENT CHARACTERISTICS

3.24

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

REFERENCES

Abry, R.G.F. and M.S. Dupart, "Amine Plant Troubleshooting and Optimization: A Practical Operating Guide," presented at the Lawrence Reid Gas Conditioning Conference, Norman, OK, March 1-3, 1993. Astarita, G, D.W. Savage, and A. Bisio, Gas Treating with Chemical Solvents, John Wiley & Sons, New York, 1983. Bacon, T. R., "Amine Solution Quality Control Through Design, Operation, and correction," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March, 1987 • . Bacon, T. R., "Monitoring the Efficiency of Amine Treating Plants," presented at the Lawrence Reid Gas Conditioning conference, Norman, OK, March, 1989. Ballard, D. and S. A. von Phul, "Cut Filtration Costs by 80%," Chemical Eng. Prog., May 1991. Bright, R. and D. A. Leister, "Gas Treaters Need Clean Amines," Hydrocarbon Processing, Dec. 1987. Bradley, V. V. and S. P. oostwouder, . "Solvent Changes Improve Amine Treating Operations," presented at the Lawrence Reid Gas Conditioning Conference, Norman, OK, March, 1987. Butwell, K. F., "Fundamentals of Gas Sweetening," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March, 1983. Butwell, K.F., D.J. Kubek, and P.W. Sigmund, "Primary Versus Secondary Amines - Characteristics in Gas Conditioning," publication unknown, Union Carbide Corp. Calgon Corp. Technical Bulletin 23-61b, 1983. Chakma, A and A Meisen, "Corrosivity of DEA solutions and their Degradation Products," Ind. Eng. Chem Prod. Res. Dev., Vol 25, No.4, 1986. Dawodu, 0 and A. Meisen, "Amine Degradation by Carbonyl Sulfide . and Carbon Disulfide," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March, 1989. Dawodu, 0., Meisen, A., Beasely, T, "Reclamation of Spent Amine Solutions," presented at the AIChE Spring National Meeting, Houston, Texas, March 28-April 1, 1993. SOLVENT CHARACTERISTICS

3.25

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

DuPart, M.S., T.R. Bacon, and D.J. Edwards, "Understanding and Preventing corrosion in Alkanolamine Gas Treating Plants," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March, 1991. Keaton, M. M. and M. J. Bourke, "Activated Carbon System Cuts Foaming and Amine Losses," Hydrocarbon Processing, August 1983. Kohl, A and F. Riesenfeld, Gas Purification, 4th ed., Gulf Publishing Co. 1985. Li, G. and R. A. Wuopio, "Packed Liquid/Liquid Extraction Column Design Guide", CRTC report dated June 22, 1992. Manning, C, "Amine Degradation Study - 02/C02 Exposure Results," CRTC Report dated June 8, 1988. Mecum, S. M., et al., "Heat-Stable Salt Removal From Amines by the HSSX Process Using Ion Exchange," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March 2, 1992. Meisen, A. et al., "Reclamation of Spent Amine S'olutions," . presented at the AIChE Spring National Meeting, Houston, TX, March 28 - April 1, 1993. Millard, M. G., and T. Beasley, "contamination Consequences and Purification of Gas T.reating Chemicals Using Vacuum Distillation," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March 1-3, 1993. Moore, T.F., J.C. Dingman, and F. L. Johnson; "A Review of Current Dyglycolamine Agent Gas Treating Applications," in Acid and Sour Gas Treating Processes, S. Newman, editor, Gulf Publishing Co., 1985. Pauley, C. R., R. Hashemi, and S. Caothien, "Analysis of Foaming Mechanisms in Amine Plants," presented at the AIChE Summer National Meeting, Dever, CO, August 21 - 24, 1988. Pauley, C. R., R. Hashemi, and S. Caothien, "Ways to Control Amine unit Foaming Offered," oil & Gas Journal, Dec. 11, 1989. • Pauley, C. R., D. G. Langston, and F. C. Betts, "Redesigned Filters Solve Foaming, Amine-Loss Problems at·Louisianna Gas Plant," oil & Gas Journal, Feb. 4, 1991. Pauley; C. R., "Face the Facts About Amine Foaming," Chemical Engineering Progress, July 1991, p.33. SOLVENT CHARACTERISTICS

3.26

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Polasek, J. and J. Bullin; "Process Considerations in Selecting Amines," in Acid and Sour Gas Treating Processes, S. Newman, editor, Gulf Publishing Co., 1985. Robb, D, "Amine Degradation Study - 02/C02/H2S Exposure Results," CRTC Report dated Feb. 28, 1990. Simmons, C. v., "Reclaiming Used Amines and Glycols," presented at the Lawrence Reid Gas Conditioning Conference, Norman, Oklahoma, March 4-6, 1991. Stewart, E. J. and R. A. Lanning, "A Systematic Technical Approach to Reducing Amine Plant Solvent Losses," presented at the Lawrence Reid Gas Conditioning Conference, Norman, OK, March .4-6, 1991. TPA, Inc., 1991 MDEA Conference Proceedings, May 1991. Veldman, R; verbal from Coastal Chemical Co. Sales Director, 31 March 1991. von Puhl, S. A. and C. D. Houston, "Common Amine/Glycol System Problems and Solutions," Proceedings of the 72nd GPA Annual Convention.

SOLVENT CHARACTERISTICS

3.27

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

4.0 CORROSION CONTROL

This chapter focuses on controlling amine corrosion in refineries and large gas plants, where we design for long equipment lives. Materials recommendations and other corrosion control measures will not necessarily apply to small packaged units, which are not designed for 20 - 30 years of service. 4.1

Corrosion in Amine Treating Plants

General Corrosion The severity of corrosion in an acid gas removal plant strongly depends on the operating conditions. The primary variables that affect corrosion are temperature, heat stable salts, solution strength, and acid gas loading. Solution cleanliness and velocity are also important. The effect of these operating conditions on corrosion is discussed in detail in section 4.2. To a lesser extent, corrosion depends on the type of amine used in the process. Chevron uses three types of amines for acid gas removal: MDEA (methyldiethanolamine), MEA (monoethanolamine) and DEA (diethanolamine). Regardless of the amine type, corrosion often takes the form of a pitting or localized attack, especially in turbulent areas. Degradation of the amine increases its corrosivity. Figure 4.1 shows potentially corrosive areas of an amine plant. A section of the plant that characteristically corrodes is the hot regenerator bottoms system. Attack may occur in the reboiler, reboiler return line, lower portion of the regenerator, hot amine piping, and rich/lean amine exchangers. In CO 2 removal plants, carbonic acid corrosion can occur in regenerator overhead systems, especially in turbulent flow areas. Corrosion usually takes the form of very localized etching, pitting or gouging. Carbonic acid corrosion can be mitigated by adjusting process conditions, through use of the proper solvent formulation and/or alloy upgrades. Generally, the remedy for overhead condenser tube corrosion in cO2 removal plants is upgrading to T-304 stainless steel. If air coolers are used, inlet and outlet headers should also be stainless steel. Regenerator overhead systems in H2S removal plants are susceptible to corrosion when the nonvolatile· inhibitor (if used) and the alkaline amine are not carried overhead. Regenerator overhead corrosion has increased with increasing use of high nitrogen crudes because cracking or hydrotreating these crudes produces cyanide and ammonia. Both are absorbed by aqueous amines and concentrated in the regenerator overhead as ammonium CORROSION CONTROL

4.1

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

bisulfide (NH4HS) and, often, excess ammonia. Alloy materials may be required to avoid corrosion in the top of the regenerator. In the overhead systems of plants processing hydrocracker, coker, or FCC gases, experience indicates that stainless steels (Types 304 and 316) corrode at about the same rate as carbon steel. Corrosion control measures in these plants include use of ammonium polysulfide to convert cyanides to harmless thiocyanates, reflux bleed streams to minimize buildup of NH4HS in reflux loops, and titanium condenser tubes. The reflux bleed stream (see Figure 4.1) allows removal of NH3 and control of NH4HS that would otherwise concentrate in the overhead system. Ideally, NH4HS should be limited to a maximum of 2% to 3%. This is often not possible, but reducing NH4HS to even 5% to 10% is desirable. The reflux bleed piping also allows purging of any hydrocarbon trapped in the overhead system. Another alternative for control of NH4HS is to remove ammonia from the gas before it enters the amine system. This can be accomplished by washing the gas at a point of high turbulence such as the entrance to a cooler. cracking of Carbon Steel Equipment Stress-Corrosion cracking Amine solutions can cause stress-corrosion cracking of nonstressrelieved carbon steel. Generally, MEA will crack steel under milder conditions (e.g. lower temperatures) than OEA or MOEA. The industry has reported cases of MEA cracking down to ambient temperatures and OEA cracking down to 140°F. MOEA is considered to be similar to DEA with respect to stress-corrosion cracking and the existing database is not yet sufficiently developed to discriminate these two amines. Carbon steel in amine service is most likely to crack in areas of the plant operating at the highest temperatures. stress corrosion can occur both rapidly and extensively at regenerator bottoms temperatures (240°F - 280°F), but becomes less serious as the temperature decreases. Water-washing equipment prior to shutdown steam-outs prevents stress-corrosion cracking of nonstress-relieved equipment • operating at low temperatures during service. A water-wash with distilled water or steam condensate will remove residual amines, which can· crack nonstress-relieved equipment when heated during steam-out. Residual amines cracked a nonstress-relieved MEA absorber column during a Chevron refinery shutdown in 1974. The most reliable way to avoid stress corrosion cracking in amine CORROSION CONTROL

4.2

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

service is to stress-relieve welds. Refer to Figure 3700-4 in the Corrosion Prevention Manual for our current stress relief guidelines for new construction. We recommend stress relief of all new pressure vessels in amine service, regardless of operating temperature. piping in amine service should be stress-relieved if it operates above 100°F. For socket and seal welds in MEA service, use a flanged bonnet valve instead of a welded valve, to allow removal of the valve during stress-relief. In DEA and MDEA service, socket and seal welds 1-1/2 inches and smaller do not require stress relief. Table 4.1 gives inspection guidelines for existing plants where original stress relief was not as extensive. From a technical viewpoint, we do not consider it necessary to inspect DEA and MDEA vessels operating below 150°F, unless more than 50 ppm H2S are present. In that case, refer to guidelines for wet H2S cracking. For vessels previously in MEA service, inspect once as an MEA vessel, regardless of its present service. Subsequently inspect the vessel according to guidelines for its current service. When repairing stress-relieved piping or equipment in hot amine service, it is necessary to stress-relieve repair welds to avoid cracking. Vessels should be stress-relieved by ASME Code approved practices (e.g., a full circumferential band of heat, not localized on one side only). wet

H~S

cracking and Hydrogen Blistering

Wet H2S cracking includes two distinct forms of cracking: 1) 2)

sulfide stress cracking, which affects hard welds on carbon steel columns, vessels, exchangers, and piping; and SOHIC, (stress oriented hydrogen induced cracking), which is a form of hydrogen blistering.

cracking and blistering are possible if steel is exposed to H2S and liquid water, and typically occur when the water contains more than 50 ppm dissolved H2S. Wet HaS cracking is caused by the diffusion of hydrogen atoms into the steel as the material corrodes. For more information on the wet H2S cracking mechanism, refer to Section 300 of the Corrosion Prevention . Manual. For new vessels, use HIC-resistant steel and postweld heat treat if the previous vessel had a history of cracking or blistering or was located in a section of the plant with such a history. Limit the hardness of the weld metal to 200 BHN maximum to further reduce the risk of sulfide cracking. Before fabrication, inspect CORROSION CONTROL

4.3

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

steel plate material using UT thickness gaging to detect large laminations. After postweld heat treatment, inspect internal welds with wet fluorescent magnetic particle testing. This initial weld inspection will detect small fabrication defects, which could later be mistaken for wet H2S cracks. Because wet H2S cracking depends on the process environment, certain pieces of equipment in an amine plant are much more likely to crack than others. As part of the CUSA Refining Wet H2S Technical Development Program, the CRTC Materials and Equipment Unit collected wet H2S cracking data from Chevron refineries. The 1993 survey data below indicate which pieces of equipment are most susceptible to wet H2S cracking: Equipment

% Cracked

Rich/Lean Amine Exchanger

~

H2S Absorber

between 40 and 60%

Amine Regenerator Reboiler

between 40 and 60%

Amine Regenerator OVhd. Condenser

between 40 and 60%

Rich Amine Flash Drum

between 20 and 40%

Amine Regenerator Reflux Drum

between 20 and 40%

NH3 Scrubber

between 20 and 40%

Acid Gas Knock-Out Drum

between 20 and 40%

Sour Gas Knock-Out Drum

< 20%

Amine Cooler

< 20%

60%

For details on these inspection results, contact the CRTC Materials and Equipment Unit. Hydrogen blisters can form i"n several areas of H2S removal plants. Most blisters develop in the regenerator overhead system. Cyanides in the overhead system from FCC offgas promote blistering by destroying the protective iron sulfide film on the • steel surfaces •. Blistering has also been detected in both the upper and lower section of ammonia scrubbers, which are used in amine plants in newer units. In very highly loaded MEA plants, hydrogen blisters can form in the bottom of absorbers. Under these conditions, blistering has been reported in the absence of cyanide and ammonia. CORROSION CONTROL

4.4

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

To control cyanides, ammonium polysulfide is sometimes injected into the overhead system of the cracking unit (i.e. FCC or hydrocracker) upstream of the amine plant. Most amine plants do not use ammonium polysulfide injection, except as a temporary measure. Typically, a plant would consider using polysulfide if corrosion rates were high and a spot FeCl3 test detected cyanides. (For details on the FeCl3 test procedure, consult CRTC Materials and Equipment Engineering). The FeCl3 test is a qualitative test for cyanides. The most reliable quantitative test for cyanides is ion chromatography. We generally recommend a nominal polysulfide injection rate of five to ten times the stoichiometric amount needed to react with cyanides in the process. Polysulfide rates can be optimized by monitoring hydrogen activity using hydrogen probes. stress-corrosion crackinq of stainless steel Equipment

Austenitic stainless steels (300 series) are susceptible to two types of stress-corrosion cracking in amine services: chloride cracking and polythionic cracking. Chloride Cracking

stainless steel tubes have chloride cracked in amine plant regenerator reboilers, rich-lean exchangers, and MEA reclaimers. Chlorides can be introduced with feed, produced water, make-up water, or caustic soda or soda ash added to the reclaimer. To reduce the risk of chloride cracking, make-up water should contain less than 50 ppm chlorides. Note that process requirements dictate a more stringent specification of 2 ppm. (See section 3.8.) Polythionic Cracking

.

Polythionic cracking is a form of intergranular stress corrosion cracking, which affects sensitized stainless steels. Polythionic acids have cracked stainless steels in H~S removal plants. For further discussions of polythionic crack1ng, refer to section 3400 and section 300 of the Corrosion Prevention Manual. While we would not expect polythionic cracking in CO2 removal plants, sensitized stainless steels in these plants have cracked from other forms of intergranular cracking • To minimize the risk of cracking of sensitized stainless steels, we recommend the following practices for both H2S and CO2 removal plants. Use only low carbon or stabilized stainless grades (Types 304L, 316L, 321, or 347) where welding is required or for u-tubes that require stress relief. Review stress relief procedures to assure that they do not sensitize equipment. Use CORROSION CONTROL

4.5

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

electric resistance stress relief methods for exchanger u-tubes. Soda ash wash sensitized stainless steel equipment using a low chloride soda ash, such as natural soda ash or a rayon or mercury cell grade of caustic soda. 4.2

Influence of Design and operating Variables

Design and operating variables greatly influence corrosion in acid gas removal plants. Changes in operating variables that increase plant throughput tend to increase corrosion. This section summarizes the influence of a number of these variables. primary operating Variables . Corrosion strongly depends on the following four operating variables: temperature, heat stable salts, solution strength, and acid gas loading. The effect of these variables is discussed below. Temperature Corrosion is a strong function of temperature, with increasing temperature increasing corrosion. The highest temperature and, therefore, worst corrosion is usually found in the regenerator bottoms system. The high alkalinity of the amine minimizes corrosion until reaching temperatures in excess of about 250°F. Above 250°F, carbon steel corrosion is significant and special alloys and/or inhibitors are required. This corrosion is probably related to impurities and degradation products in the amine, such as heat stable salts and other acid compounds. In MEA reclaimers, tube metal temperatures above 300°F - 325°F will degrade the amine and corrode the tube material, even if it is stainless steel. Operating and design conditions must avoid creating hot tube metal surfaces. Heat Stable Salts The total amine concentration in a solution is the sum of the free amine and the amine tied up as heat stable salts. Organic acids, sometimes formed in refinery processing plants or as a • result of oxygen. contamination, can cause serious heat stable salt problems. Heat stable salts include oxalates, sulfates, thiosulfates, acetates, formates, and thiocyanates. (For more details see section 3.5.)

CORROSION CONTROL

4.6

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Solution Strength Another important factor affecting corrosion is amine solution strength. Industry guidelines and company experience indicate that the upper limit for MEA solution strength is about 20 wt.% MEA in aqueous solution. Concentrations above this limit require increased regeneration temperatures, which tend to degrade the amine and increase corrosion. The upper limit for DEA solution strength is somewhat higher (25 to 35 wt.%), while MDEA can be used up to 50 wt.%. Acid Gas Loading A fourth primary operating variable is acid gas loading, expressed as moles of acid gas per mole of amine. Acid gas loading is related to acid gas feed rate and solution circulation rates that are built into a plant design. Sizing a plant too small or operating a plant above design limits will accelerate corrosion. The maximum acid gas loading varies depending on the type of amine used. For MEA plants, acid gas (i.e. H2S and CO2 ) total loadings above 0.4 moles acid gas per mole MEA cause significant corrosion of .carbon steel equipment. If H,S levels are very low, the steel is not protected well by a sulfiQe film, and corrosion can occur above 0.3 moles acid gas per mole MEA. The limits for H2S/DEA plants are somewhat higher at about 0.35 to 0.5 moles H2S per mole DEA. Control of amine solution strengths and acid gas loadings are important corrosion control measures. Performing routine chemical analyses is good operating practice. If plants must be operated in excess of design capacity, it is better from a corrosion viewpoint to operate with slightly higher solution strengths and moderate loadings, rather than with normal solution strength and high loadings. Secondary operatinq Variables

•

From a corrosion standpoint, solution cleanliness and velocity are secondary operating variables. They affect corrosion rates in amine plants, but to a lesser extent than temperature, heat stable salts, solution strength, or acid gas loading. However, high solids content in the amine can lead to erosion and corrosion problems. Solution Cleanliness contamination or degradation of amine solutions can lead to serious corrosion and foaming problems. Contaminants can be CORROSION CONTROL

4.7

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

oxygen, dissolved hydrocarbons, liquid hydrocarbons, and solids. controlling solution contamination is necessary for long, trouble-free solution life. velocity/Turbulence

High flow velocities or turbulence can cause localized erosion-corrosion in acid gas removal plants. For this reason, piping design for carbon steel is limited to a maximum of 6 fps fluid velocity. At turbulent areas in hot solution piping, long radius bends (if possible) or stainless steel should be used. Special care is needed at points of solution entry into vessels, reboilers, and exchangers. Erosion-corrosion and cavitation are common problems with pumps in amine plants. Lean amine pumps and rich amine pressure letdown valves often suffer severe erosion-corrosion. T-304 stainless steel, often hardfaced with Stellite, is usually required to solve these problems. Pump' cavitation also leads to accelerated corrosion. Calculation of NPSH requirements should allow for the effect of dissolved gases, which is sometimes overlooked. Installing the lean amine pump after the rich/lean exchanger often solves this cavitation problem. Longer piping and equipment lives can be obtained by selecting the proper point to reduce the pressure of the amine solution. Desorption of acid gases and dissolved hydrocarbons, which usually occurs when the pressure of the rich solution is significantly lowered, can corrode control valves and adjacent downstream piping. The absorber or flash drum pressure should be maintained through heat exchangers to minimize flashing of acid gases. 4.3

Use of Alloy Bquipment

Equipment in amine plants is normally carbon steel (See Figure 4.1), with the exception of the applications discussed below. In these cases, major refinery gas plants and selected producing locations use stainless steel for high reliability. Valves and pipinq

Alloys are used for two valve applications and several sections • of piping, which,are subject to erosion-corrosion. Stellite, hardfaced Type 304 stainless steel is used for' the absorber bottom control valve and the pressure letdown valve to the regenerator. Type 304L stainless steel is used for the following sections of piping:

CORROSION CONTROL

4.8

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

• Rich amine piping from absorber bottom control valve to accumulator Rich amine piping from pressure letdown valve to regenerator Regenerator overhead reflux return piping • Hot lean piping from regenerator to rich/lean exchanger • Hot lean piping to reclaimer and return (MEA only) • Hot lean piping to reboiler and return Lean Amine PUmp

This pump is usually T-304 stainless steel, but can be carbon steel if potential cavitation problems are avoided. See Section 4.2 on velocity and turbulence effects. Reqenerator

The regenerator is clad with T-304 stainless steel in two areas: • Above the feed tray where acidic corrosion is possible Below the bottom tray where hot amine corrosion can occur Excbanqers

T-304L stainless steel is typically used in three amine plant exchangers: the rich/lean exchanger, the regenerator overhead acid gas cooler, and the reboiler. In MEA plants, T-304L stainless is also used for reclaimer tubes to provide resistance to hot amine corrosion. Below are brief discussions on the use of stainless steel in the first two services. Reboiler corrosion is discussed separately. The hot lean amine side of the rich/lean exchanger is generally Type 304L stainless steel, althouqh some gas plants can use carbon steel successfully. The cold rich side is carbon steel. 70-30 Cu-Ni has been used in H2S-free MEA/C02 plants where carbon steel was not adequate. Plants using oxidative inhibitors (e.g. Amine Guard) should use Type 304L, rather than 70-30 CU-Ni, because oxidative inhibitors will pit the copper-nickel. The tubes in the regenerator overhead acid gas cooler are usually Type 304L stainless steel. If this' is an air-cooled eXChanger, Type 304L is used for the inlet and outlet headers. Titanium tubes are sometimes used in refinery H2S removal plants to resist cyanide- and ammonia-induced corrosion. If titanium tubes are used, we recommend grade 2 (commercially pure· titanium) tubes with the same material for the carcass and grade 2 or grade 12 for the tubesheet. Avoiding galvanic couples reduces the risk of titanium hydriding.

CORROSION CONTROL

4.9

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

Reboi1er

Reboiler tube corrosion can be a serious operating problem in acid gas removal plants. Corrosion is usually attributable to high localized temperatures and to inadequate stripping in the regenerator, which allows acid gas to be stripped in the reboiler. Corrosion can occur under baffles when high pressure steam (lS0 psi or greater) or hot synthesis gas is used for a heating medium. Poor shellside flow in baffle crevices can create high tube temperature zones, which increase corrosion of stainless steel. stress-relieved stainless steel reboiler tubes (Types 304L, 321) are usually used in Chevron H2S and CO2 removal plants. Monel is often used in MEA/COz plants when there are no sulfur compounds present. In these plants, Monel has proved to be somewhat superior to stainless steel in resisting high temperature reboiler corrosion. However, Monel will pit if used in plants with H2S or in plants using oxidative inhibitors, such as Amine Guard. Titanium shows promise in severe services where Monel and stainless steel have had short (less than S year) service lives because of corrosion. Company experience with titanium grade 2 reboiler tubes is limited to two reboilers in HS plants at EI Segundo, in service since 1973 and 1975. Ti{anium reboiler tubes have been known to hydride, and so require careful handling during shutdowns. Hydriding does not affect tube corrosion resistance. Although often uneconomical in new plants where stainless steel can be used, the design alternative to expensive tube materials is to' lower the steam pressure in order to avoid high skin temperatures and high heat flux rates. Low pressure steam at so psi is usually recommended, with inlet temperatures monitored to avoid superheat. Mechanical design considerations, such as tube pattern and bundle geometry, are important factors in reboiler corrosion. Refer to section 3741 of the Corrosion Prevention Manual for discussions on reboiler design. 4.4 Corrosion Inhibitors

For many years, both CO2 and H~S removal plants were inhibited with organic, water-soluble f~lming amines (e.g. Kontol K-12 and Betz WS-S8). Filming amines prevented sludge deposits, but their success as inhibitors has been mixed. Betz WS-S8 is currently used at the Carter Creek Gas Plant. The plant has over eight years of experience with this inhibitor. To date, hydrogen CORROSION CONTROL

4.10

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

blistering has not occurred while injecting WS-58 and coupon corrosion rates have generally been less than 10 mpy. However, at times, coupons in the rich stream through the rich/lean exchangers have corroded at rates as high as 26 mpy. DEA plants at Port Arthur and Richmond have had some success with oxygen scavengers/metal passivators, such as Nalco 5173. Port Arthur's 841 and 842 amine plants, along with the AVU 144 amine plant (now out of service), have successfully used Nalco 5173 to scavenge oxygen, which degraded the amine. A Richmond DEA plant has used 5173 since 1990 to solve an iron sulfide fouling problem. Although pump problems prevented continuous 5173 injection, the inhibitor appeared to stabilize the formation of heat stable salts when it was injected consistently over a six month period. Adding the correct dosage continuously into a circulating solvent or overhead system is critical to an inhibitor's success. If the chemical is underfed, a passivating inhibitor can accelerate corrosion. Underfeeding Nalco 5173 contributed to sulfide cracking and corrosion problems at the carter Creek Gas Plant. After injecting 5173 for about a year, severe cracking had occurred in the bottom of the DEA regenerator. Additionally, severe pitting was found in the hottest rich amine exchanger, and steel coupons in a rich amine line had hydrogen blistered. COz removal plants (usually MEA) sometimes employ oxidative inhibitors, such as Union Carbide's Amine Guard. These inhibitors contain metals (e.g. vanadium, arsenic, antimony), which promote stable oxide films on carbon and stainless steel. If H2S is present, oxidative inhibitors are not effective because the formation of a sulfide film will compete with formation of the oxide. Oxidative inhibitors tend to increase corrosion of Monel and 70-30 Cu-Ni. The use of oxidative inhibitors is declining due to restrictions on their disposal. An alternative to inhibited MEA is MDEA, which can be used at higher concentrations and does not require inhibition. Oxidative inhibitors should not be used in MDEA plants because they tend to increase corrosion. 4.5 •

Corrosion Xonitorinq

An inhibitor program will not be successful unless corrosion

rates in the system are continuously monitored. Both retractable corrosion. coupons and corrosometer probes are used for this purpose but coupons are preferred because field experience indicates that retractable coupons give more reliable data under both turbulent and laminar flow conditions. Also, coupons can be visually examined for pitting. Corrosometers offer the advantage CORROSION CONTROL

4.11

JULY 1994

AMINE TREATING BEST OPERATING PRACTICES RESOURCE GUIDE

of continuous data collection, without the need for removing and replacing coupons. The location of probes or specimens should be chosen with care, particularly if corrosion in the plant is highly localized. New plants should have probe connections consisting of 1-1/2 inch full port gate valves installed in critical locations such as reboiler outlet vapor lines and the rich amine piping between the rich/lean exchanger and the regenerator. Probes may not be satisfactory if corrosion occurs primarily by pitting or if the fluid velocities and turbulence at the test location are sufficient to cause the probe element to fail by fatigue. If the best test location is a highly turbulent area such as the reboiler outlet line, better results will be obtained with retractable corrosion specimens. Retractable specimens are described in section 400 of the Corrosion Prevention Manual. Coupons normally are removed at two-to-four-week intervals for evaluation. Coupon data should be supplemented with inspection data to confirm findings. Monitoring the solution's iron content in CO2 plants, or the filter change frequency in H2S plants, can also provide valuable information on relative corrosion rates.

CORROSION CONTROL

4.12

JULY 1994

Figure 4.1 Materials for Amine Gas Treating Plants

caRRaS ~ ON I

i

PIJR[F[EC GAS

,f AC:UMULnTORI

I

I I

i

I I I

i

I

ABS.:lRSEil

I

, I

I

n -, I

SOUR GIIS

,= n., T:Ri

I 7~04

', . ..

-' .0 (..... .;

t-:¥ /1. . ,..------..-----.

§~ ~

..

I

~ U ii :x~;~~~ O;c;,y [r Ii ~RESOtl.ER~~~~: !'fO 1~~M~.o.21 I m TJ041..' : - n OKAY ,:- S~, I.E.~N ~ ~ : MONEL OOE: Nor I T

c:... " .. ....__ ,.aiZ •••••• _____ .! •• ,

_;._w~

i

;.~5:

:i

.."ir .. • ...... " i~ :~

~.

ff---· _["~::1

~~"~~=-.,

r,-::;

'_.,

Hor AM[NE CORROSiON. sec

I I

"C;;:;K

j

_~ ~

, C I _Cl.l ~AX. ~ :GC ~PH CI-

t

!

i~ ,t. :~ i~Oql.. :~ :t..-·_-·.;:....._-·-..··:11 " ....,;"')""',."",;;,»;;,,»)....), NOTE!:

rl04L

!-!.2S

RICH-LEAH EXCHANGER

C:C;~ERAl.

I I

~~_*NHHNH',,2,,;,";;;;m'!! ~ Jh .....j •• '~!Si i~

,1

'-c = r-c"s

I

I

"

r=::i rco t C::,LI. y crt:::- - ~OE:-: .--~"

-

- ALL CS £xc~~r SHACEO AREAS - Si-IAOEO a ALLOT. AS ~IOrE::J - i~04/r304L HEAT ~~CHANC[RS • iUBES. nuaE:HE:~:, BAF~:: IruaE!-~E~O~S :~ A!~ C:CL~~SI iO AYOIO SENSiTiZAiiON. ONL'!' £:50 psig on reboiler.

A.3

If solution appears brownish, check thio-sulfate content and operation of amine storage tank blankets.

A.3 Oxygen entering the storage tanks will react with the sulfides in the amine solution to form thiosulfates and impart brownish color.

B.Solids.

B.

See Problem/Remedy 2.C.

c.

C.

Liquid hydrocarbon.

See Problem/Remedy 2.B.

A.Pressure control valve 100% open.

A.

Increase pressure set point slightly.

B.Poorly tuned pressure controllers

B.

Retune.

C.Liquid carry-over from reflux drum.

C.

Check reflux drum level. System may be foaming or flooding. See Problems 3.C and 3.D.

C.Liquid carry-over in line could affect gas flow through pressure control valve.

6. Reflux Drum OVerhead Gas Develops High Back Pressure

A.Flow limits in downstream.

A.

Take steps to address downstream problems and reduce gas plant feed rates.

A.High reflux drum pressure may activate emergency backup treating systems.

7. Amine Carry-OVer from Reflux Drum

A.Foaming.

A.

See Problem 3.C.

B.Floodinq.

B.

See Problem 3.D.

5. Poor Regenerator Pressure Control

4

A.Do not raise regenerator overhead pressure above 20 psig, if possible, since this adversely affects H2S stripping.

TROUBLESHOOTING AMINE UNITS

Problem

Possible Cause

Remedies

Page 5 of 7

!

Remarks

8. Steam Rate Too Low to Reboiler

A.Steam temperature is too low to provide adequate reboiling; or condensate system is backing up.

A.

Increase steams ide pressure by adjusting set point. When pressure must be increased to above 50 psig, reboilers may be fouled and need cleaning.

9. Poor Control of Lean Amine Cooler OUtlet Temperature

A.Amine cooler bypass is 100% open but amine is still too cool

A.

Pinch back on lean amine cooler outlet valve.

lO.Amine Strength Less Than or Greater Than Target Value

A.Incorrect make-up water or steam rate to regenerator.

A.

Adjust make-up rate to compensate.

11.Low Lean Amine Storage Tank Level

A.High levels in process vessels.

A.

Adjust levels and recheck lean amine storage tank.

A. Check to see if losses are within guidelines.

B.Low solution inventory.

B.

Make up additional solution

B.Check for leaks, open drain valve, etc.

A.Low levels in process vessels.

A.

Adjust levels and recheck lean amine storage tank.

12.High Lean Amine Storage Tank Level 13.High Pressure Drop Across Amine Charcoal Bed or Filter Media

A.Excess feed rate to media.

I A.

Open media bypass slightly.

A.Maintain design flow rate through media. If design flow rate and pressure drop cannot be maintained it is time to change the media.

B.Partially plugged media.

I B.

B.Media may plug with solids or wax.

A.

Backwash media with hot water or replace. Alternatively, open top and steam downwards. Try tuning controllers to provide smoother flows and allow more fluctuations in regenerator bottoms level.

A.Poor backwashing.

A.

Increase backwash time.

B.High solids loadings.

B.

Check filter solids removal efficiency.

C.Wax buildup on elements.

C.

Remove elements and steam clean manually.

14.Fluctuating Filter Feed Rates A.Fluctuating control valve position.

1S.Frequent Filter Backwashing

A.Do not exceed 50 psig steam pressure. This results in high reboiler tube temperatures and increased amine degradation.

5

TROUBLESHOOTING AMINE UNITS

Problem 16.High Corrosion Rates in Amine Loop

Possible Cause

Remedies

Remarks

A.Solids level too high.

A.

Improve filter operation.

A.Solids have erosive effect which also accelerates corrosion rates. Solids levels should normally be 1020 ppmw or less.

B.Amine strength too high.

B.

Add make-up water to inventory. Adjust steam makeup rate to regenerator.

B-E:Corrosion rate is increased by high amine strength, high H2S loading, and high concentrations of heat-stable salts. Also, chloride stress cracking may occur if chloride levels exceed about 500 ppm.

C.High acid gas content in rich amine.

C.

Increase amine circulation rate.

D.High level of heat stable I D. salts. I E.

E.High chloride level.

17.Hydrate Formation Hydrate crystals Plug Instrument Leads

Page 6 of 7

Bleed off some amine for· disposal. Make-up with fresh amine. Bleed off some amine for disposal.

F.Generally corrosive amine I F. despite good operation.

Inject corrosion inhibitor into amine system. Consider replacing amine solution.

A.Instrument leads around an inlet filter/separator too cold.

Check steam tracing.

A.

,..

,"

I'·

". ;1

I

6

TROUBLESHOOTING AMINE UNITS

Page 7 of 7

'. Problem lS.Excessive Acid Gas Released in Flash Drum

Possible Cause A.Rich loading in rich amine is too high.

Remedies A.

Increase amine circulation rate to the absorber.

Remarks A.Vent gas H2S content may exceed specification (excess sulfur might show up further downstream in fuel gas or flue gas). Routine analysis of the flash gas would reveal this. Increased amine circulation rate will lower rich loading but increase regeneration energy use.

19.High Hydrocarbon content in Acid Gas Product

B.

Raise Flash Drum pressure (See 19.A) •

B.Raising the Flash Drum pre~sure also reduces the amount of hydrocarbon vaporization, thereby increasing the hydrocarbon content of the acid gas to the SRU.

A.High pressure in Flash Drum.

A.

Pressure should typically be 150 psig or less.

A.High pressure reduces flashing of absorber hydrocarbon. Any hydrocarbon remaining in the rich amine will end up in the acid gas product the SRU.

B.Circulation rate is too high.

B.

Review design vs. operating conditions for Flash drum.

B.High circulation rate reduces residence time in flash drum and can cause hydrocarbon carry-under.

C.Foaming in the Absorber.

C.

See 2.A-D.

C.Absorber foaming can cause hydrocarbon entrainment into the rich amine.

D.High hydrocarbon content in rich amine from absorber.,

D.

See 2.B.

D.Absorber foaming, hydrocarbon condensation in the absorber and poor level control can cause entrainment in the amine.

7

BEST PRACTICE FOR HYDROCARBON AND PARTICULATE REMOVAL FROM AMINE SYSTEMS Introduction Poor solvent quality is the most common cause of operating problems within amine units. The three major contaminants which have a significant detrimental impact on solvent performance are heat stable salts (HSS), hydrocarbons (free and dissolved) and particulates. Heat stable salts increase corrosion rates and reduce the amount of amine available for acid gas pick-up. Both hydrocarbons and particulates increase foaming which has been identified as the most frequent cause of off spec gas and high amine losses in Chevron facilities. High particulate levels are also responsible for increased corrosion rates in some amine units. A separate best practice exists for HSS control. A best practice for hydrocarbon and particulate control has been developed on the basis of a survey of 21 upstream and downstream Chevron facilities, input from some vendors and a literature search. Some non-Chevron industry operators were invited but declined to participate. A summary and consolidation of the survey results is attached as an appendix. The number of incidents of off spec gas per volume of gas processed or per volume of amine circulated has been used as rough qualitative indicator of performance in comparing practices. Due to wide variations in process feed quality and conditions each unit should be considered somewhat unique and it is inappropriate to prescribe a single set of best practices for all facilities. This is illustrated by the differences between upstream and downstream facilities. The former usually have cleaner feed gas but also have much tighter sweet gas specifications and so are more sensitive to amine contamination. Thus what is considered "best practice" for an upstream facility may be quite different from a downstream facility "best practice" where problems and constraints differ. In light of this, the best practice is presented as a three level approach where effectiveness, stringency and cost increases from level I through to level 3. It is the responsibility of the unit engineer to determine which level constitutes best practice for a given facility. If adherence to level I practices do not adequately address operating problems then levels 2 or 3 should be considered. Each level is considered additive to the preceding so that adherence to a specific practice level assumes compliance with the preceding levels of practice. The best practice is broken down into three elements or components; free or entrained hydrocarbon control / removal which deals with inlet gas scrubbing and hydrocarbon skimming; dissolved hydrocarbon / organics removal which deals with activated carbon systems; and particulate removal which addresses mechanical filtration. There are three levels of best practice for each component. Which level of practice constitutes "best" at a given facility may vary for each component and specific practices within the component. A unit may require only level 1 practices with respect to hydrocarbon removal but level 3 practices for particulate handling. The three elements of the best practice are interdependent and must not be considered alone. For example, by improving free or dissolved hydrocarbon removal from amine, foaming tendencies are reduced and so it may be possible to tolerate higher particulate levels without any detrimental impact on performance. The specific recommended practices for each component are discussed below and summarized in a table along with the rationale for the recommendations and symptoms to look for in diagnosing a problem.

Component 1 - Free and Entrained Hydrocarbon Removal

•

Amine contamination with free hydrocarbon is a frequent cause of foaming in the treater and the absorber and it's symptoms are described in the summary table. Sources offree hydrocarbon include entrainment or slugging of process liquids (or lube oil) with the feed gas and condensation in the gas absorber. Condensation in the treater is controlled by maintaining the lean amine temperature at least 10-15 fO above the gas temperature (see Amine Treating Best Operating Pra~tices Resource Guide). Strategies to control free hydrocarbons in the amine should focus on prevention (i.e. adequate inlet knockout facilities) but also need to address removal (skimming) since some contamination is inevitable. In some cases upgrading of the skimming facilities may be more economic than upgrading inlet knockout equipment.

Level 1 Practice Minimum recommended hydrocarbon control/removal facilities for Chevron amine units consist of: •

gas inlet knockout drum with automatic level control, demister and high level alarm; this may simply be part of the plant inlet separation train (upstream facilities) or part a dedicated vessel in the amine unit

•

manual hydrocarbon skimming system on flash drum consisting of sight glass, nozzle and valve (pump may be required if flash drum operates at low pressure)

These are the minimum facilities reported in the survey that appear to be performing adequately. Sizing of the inlet knockout drum with respect to liquid slug handling is critical to the overall performance of the amine unit. Both gravity and centrifugal (PortaTest) separators are used successfully. Adequate skimming facilities are also critical to good unit performance. Of the 21 units surveyed, 6 do not have or use skimming systems and of these 5 are in the lowest third of performance as measured by incidents of off spec gas per volume of gas throughput or amine circulated. The flash tank/drum is the most appropriate location for skimming in that it permits removal of the free hydrocarbon upstream of the regenerator. Some vendors use multiple nozzles at various levels in the vessel to simplify skimming (avoid having to raise and lower liquid levels). Vendors recommend a residence time of at least 20 - 40 minutes to permit hydrocarbon separation. The richer the inlet gas (or the more entrained liquid) the longer the required residence time. Free hydrocarbon in samples of rich amine downstream of the flash drum are indicative of inadequate separation due to limited residence time, insufficient skimming or poor flow patterns. Temperature and pressure should be as high and low as possible respectively to promote hydrocarbon separation and vaporization.

Level 2 Practice If the level I practice is inadequate to control the free hydrocarbon content of the amine, determine the source of the hydrocarbon. If entrainment is a significant source consider use of coalesor filter / separator on the inlet gas if the inlet knockout drum cannot be modified to remove the entrained liquid. Typically coalesor filters / separators are used when droplet size is < 3 11. If liquid volumes are small and there is little slugging coalesor filter / separators may be used in place of a conventional inlet knockout drum. In most cases however vendors recommend use of the coalesor unit downstream of the knockout drum. If the source of the hydrocarbon is due to periodic carry over from the inlet knockout, and both upgrading of this vessel or modifying upstream operations are impractical, then consider use of multiple skimming locations. This permits removal of hydrocarbons that may get by the flash drum and concentrate elsewhere in the system. Survey results indicate that such designs can be beneficial to overall performance; of the top seven performers five had mUltiple skimming locations. Recommended skimming locations are listed in the summary table. In general, the closer to the treater the better (i.e. catch the hydrocarbon before it gets too far).

Level 3 Practice If level 2 practices do not control free hydrocarbons focus efforts on eliminating the source. If this is not possible use of automated skimming system using bucket and weir internals should be considered. This will permit continuous hydrocarbon removal. Chevron has not had any experience with such systems however vendors indicate that these systems have proven effective in commercial operations. Typical designs are presented in the Chevron Pressure Vessel Design Manual, Figure 900-14 or Lieberman "Troubleshooting Natural Gas Processing" Figure 12-

4.

Component 2 - Dissolved Hydrocarbon I Organics Removal (Activated Carbon Systems) Similar to free hydrocarbon, dissolved hydrocarbon or organics can cause foaming with the associated operational problems as summarized in the table. In addition the dissolved material may be organic acid precursors of heat stable salts (HSS) which in tum contribute to corrosion and declining amine unit performance. Sources of these material include process liquids, corrosion inhibitors, antifoam chemicals (if in excess), other process / treatment chemicals (well treatment, demulsifier etc.), detergents used during shutdowns and to treat cotton filter material. Detection is more difficult due to the small quantities present. Other than eliminating the source, activated carbon is the common method of removing these materials.

Levell Practices The minimum recommended practice is no carbon system. Many amine units operate acceptably without it. Of the 21 units surveyed 6 either did not have or use a carbon system and there was no apparent impact on unit performance. Many of these units did report however that they had used carbon on a temporary basis to clean up their amine. Of note is that essentially all the upstream facilities (gas plants) have carbon systems although it is out of service at one of the plants. This likely reflects a greater need for carbon in upstream units due to more stringent sweet gas specifications and the impact of field operations. While no carbon may be acceptable for some existing facilities it should not be assumed for new designs, particularly upstream gas plants, since more likely than not carbon will be required.

Level 2 Practices The level 2 practice consists of some form of activated carbon treatment on the lean amine stream. There are a variety of activated carbon systems in use (cartridge, mixed with filter precoat, beds), most of which are reported to be performing adequately and so no specific types are recommended unless there are operational problems (see level 3 practices). The recommended location is after the particulate filters preferably downstream of the coolers and charge pump. These are the optimal conditions (low temperature and high pressure) in the circuit for adsorption. Dow Chemical noted that for most amine systems a temperature of 120 - 150 OF is recommended to avoid viscosity problems in the carbon system. Other recommended practices are to avoid steam regeneration of carbon on small to mid-size carbon systems, to monitor either color or corrosion inhibitor residuals to determine when changeout is required and to follow carbon suppliers procedures for changeout. In several cases steam regeneration was reported to have resulted in a release of carbon fines into the amine. In most cases the savings realized through regeneration do not justify the risk of amine contamination. With respect to carbon change out some operators reported dP across the unit as the basis of changeout, however this is only an indicator of solids accumulating on the carbon or amount of fines accumulation and carbon may become saturated long before any significant change in dP is observed. Other operators report that change out is simply every 1-2 years and is not based on amine or unit performance monitoring. Again, it is likely that the carbon will be saturated before change out occurs. Lastly carbon changeout procedures must be emphasized since performance is very sensitive to loading procedures. Depending upon the type of carbon system vendor procedures should include some or all of the following; 12 - 24 hour water presoak, loading in slurry form and back washing to eliminate carbon fines.

Level 3 Practices Level 3 practices consist of a consolidation of vendor design practices for the three common type of carbon systems. These are tabulated below and should be viewed as guidelines against which existing operations can be compared and new facilities can be designed. Of the facilities surveyed graded beds were the most common. These are generally recommended over cartridge or deep bed units. Cartridge units have a shorter life and so are more prone to saturation prior to change out. Deep beds combine particulate filtration with carbon treatment and as result use softer carbon due to it's lower density. This, in conjunction with higher velocities tends to result in a significant number of carbon fines being generated and released into the amine if downstream filtration is not used. Furthermore coal based carbon is recommended over wood based material since it has a higher adsorption capacity and a broader distribution of micro pore sizes as well as being harder. Parallel beds should be used so that one bed is available for service when the other is being changed out. A maximum bed life of six months is recommended. Lastly, particulate filtration downstream of the carbon unit is recommended to prevent contamination of the amine with carbon fines (see Particulate Filtration).

Carbon System Design Guidelines Carbon Mesh Carbon Density (lb/ff) Type Of Carbon Empty Vessel Residence Time (min.) Superficial Amine Velocity (gpm/ft2) Bed Life (months) Amine Slipstream Size (% total flow)

Cartridge 10 x 22 30 Carbon based 1O!.t in size except carbon fines and FeS which are 1-3 !.t and < I !.t respectively. In all cases source control/elimination should be considered before upgrading filtration facilities.

Level 1 Practices As outlined in the summary table level 1 practices consist of particulate filtration on a 25 - 50% slipstream. Although a few units surveyed reported a smaller slipstream it is notable that some of these units are also experiencing operating problems due to particulate contamination. Vendors recommend a maximum TSS loading of 150 - 200 ppm however this should be adjusted on the basis the particle characterization. Upstream gas plants which often experience high FeS (small particles) levels typically target a significantly lower TSS level. A 25 !.t nominal rating is recommended. This will actually pass particles up to 40 - 50 !.t so is consistent with the maximum reported values. A variety of filter types were reported in the survey and there are no clear recommendations in the literature. Acceptable types include sock, cartridge, bag and leaf. Backwashable systems have only had minimal success. Selection of a specific type will depend upon rates, required size, filter life and cost. In general bag and sock units should be considered for bulk removal of larger (> 5 !.t) particles at high rates and cartridge units used for smaller flow rates « 500 gpm) and smaller particles. Theoretically rich amine filtration should be more effective than lean amine filtration since it permits removal of particles before they can "hang up" in the regenerator, surge tank etc. Survey data does not support this however; plants which filter rich amine do not appear to have better performance than those that filter lean amine. Although this may be a reflection of other factors it does indicate that there is no clear justification for the increased risk associated with rich filtration. • If the primary particle source is entrainment in the inlet gas and droplet size is 0.5 - 3 !.t an inlet filter separator should be considered.

Level 2 Practices Level 2 practices are similar to level 1 except full lean flow filtration is recommended to permit more rapid particle removal rates. A particle characterization (size distribution and composition) should be completed to permit adequate filter sizing and TSS targeting as well as identifying the source for control/elimination. Initial sizing of25 !.t absolute and target loading of 30 ppm are based on data from the upstream gas plants. Level 3 Practices Level 3 practice consists of a dual filtration system. A bulk filter (either sock or bag) upstream of the carbon units removes the majority of the larger particles. These must be sized to protect the carbon units from plugging with particles. A smaller unit, typically a cartridge filter although others can be used, filters on the slip stream coming out , of the carbon unit. The slip s~eam filter should be sized to remove any entrained carbon particles, typically> 5 !.t. This design permits removal of the smaller particles without the high capital and operating cost of small micron full flow filtration

SUMMARY TABLE OF BEST PRACTICE FOR HYDROCARBON AND PARTICULATE CONTROL / REMOVAL IN AMINE SYSTEMS (see text for more detail)

Level 2

Levell Best Practice Component Free Hydrocarbon Control I Remo\"al

Symptoms Of A Problem Any or all of the followmg. symptoms may be indicating. thai the e)(isling free hydrocarbon removal practices are inadequate and should be upgraded:

• foaming as indicated by high .lP across columns (> than 40% of height between top and bottom tray (in feel of water)), offspec sweet gas or e:-::cessive amine losses (> 3 IbsIMMSCF) • erratic liquid le\'els in vessels or column sumps • visible hydrocarbon level in absorber sump" flash drum or reeenerator reflux accumulalOr with frequent sk·imming required • visible hydrocarbon layer on amine sample • amine carryover to SRU or in sweet gas

Dissolved Hydrocarbon I Organics Removal (Carbon Systems)

Any or all of the following symptoms may be indicating that the existing dissolved hydrocarbon I organic removal practices are inadequate and should be upgraded: • foaming as described above • odor of hydrocarbon on rich amine sample but no visible layer • high rate ofHSS fonnation from organic acid precUl'Sors as indicated by high corrosion rates (> 10 mpy for carbon steel & 5 mpy for SS) and I or translucent black amine (FeS particles from corrosion)

Recommended Practice

Rationale

• gas inlet knockout drum with automatic level control. demisler and high level alarm: this may simply be pan of the plant inlet separation train (upstream facilities) or part a dedicated vessel in the amine unit

• some type of liquid hydrocarbon removal upstream of the treater is essential to minimize foaming in the treater and a simple knockout drum is the most COSI effective method of doing this • all facilities surveyed had some form of inlet lcrtockout, either as pan of an plant inlet separation train or a vessel dedicated to the amine unit • some amount of hydrocarbon contamination is inevitable for most facilities so a skimming system is necessary to remove the hydrocarbon once it is in the amine • 5 out of 21 facilities surveyed had no skimming facilities on the flash drum and all these were in the lowest third of plant perfonnance as measured by incidents off spec: gas per either gas throughput or amine circulation rate • the rich amine flash drum is the most appropriate location for skimming since it is upstream of the regenerator and can be designed with sufficient residence time 10 pennit hydrocarbon sepanttion

• use coalesor filler I separator on inlet (after knockout drum) ifenlrainmenl from inlet knockout is a problem

• 5 of 21 facilities surveyed do not have or use a carbon system and of these 4 are in the top third of performance as measured by incidents off spec gas per either gas throughput or amine circulation rate • although no carbon may be acceptable for some facilities this is not recommended for new designs since il is more likely than not that earbon will be required

• activated carbon system on lean amine downstream of mechanical filtration, lean amine coolers and after charge pump

• manual hydrocarbon skimming. system on flash drum consisting. of sight glass. nozzle and valve (pump may be required if flash drum operates low pressure)

• no activated carbon system

Any or aJl of the following symptoms may be indicating that the existing particulate control I removal practices arc inadequate and should be upgraded: • foaming as described above • translucent to opaque amine samples (green color may indicate finely divided FeS « I "'), black color may indicate larger FeS panicles or carbon fines) • sedimentation in amine samples • high corrosion rates (> 10 mpy for caroon steel and > 3 mpy for stainless steel) • plugging of instrumentation taps

• paniculate filtration on a minimum 2550% slip lean amine stream

• maximum TSS of 150 - 200 ppm • maximum 25", nominal rating

• changed out on basis of high .1P • use inlet fiher sepanttor if most panicles arc entrained with inlel gas and particle size is 0.5 -3"

• particulate filtration is aJways required doe 10 corrosion generation of particles • lean fihrarion preferred for safety reasons and there is no clear evidence that rich filtration improves performance • minimum slip stream recommended in lilenttwe, most surveyed facilities had slip streams of 50 - 100% • TSS level recommended by chemical vendors • maximum reported size thaI appears to be doing an adequate job and also vendor recommendation • .1P is measure of effective filter life

• pennits removai of particles before they reach lreater

(Recommended practices are in addition to Levels I and 2) Recommended Practice Rationale

• coalesor filter I separator can remove entrained liquid and paniculales which are nOI eliminated by the knockout drum (i.e. < 3 J.l) • recommended in literature and is standard design for many vendors (TPA. Pritchard,

• use a bucket and weir system for hydrocarbon skimminl! in the flash drum with automatic level control (see Chevron Pressure Vessel Manual Figure 900~14 or Lieberman ""Troubleshooting NaMal Gas Processing"" Figure i2-4 for typical design)

• ensures that hydrocarbons are continuously removed

• size cari>on system for a minimum of a 10· 2Q1'10 slipstream flow

• less than 10..20% slipstream flow is ineffective in maintaining low dissolved hydrocarbon levels in most amine systems

etc.)

• use multiple skimming locations; pOlential locations (in order of preference) are flash drum" absorber sump, regenerator reflux accumulator. regenerator sump, and amine surge lank

• multiple locations maximize the opponunity for hydrocarbon removal • out of 21 facilities surveyed 6 used multiple skimming locations and 5 of these facilities were in the top third performers as measured by incidents ofT spec gas per either gas throughput or amine circulation

",'e

• carbon treatment of rich amine nor recommended due 10 higher likelihood of saturation by free hydrocarbon and reduction adsorption due to acid gas breakout • place dovmSlrcam of mechanical filters to avoid plugging carbon system with solids • high pressure and low tempel'llture (120 150 oF) inCRases adsorption

• stearn regeneration not recommended

• facilities Ihat have used steam regeneration reported problems with carbon fines in

• monitor amine color or corrosion inhibitor residuaJs to determine when changcom required ~ do not use .1P or only change out when convenient • follow carbon suppliers loading procedures including water soak., slurry loading and backwashing: to remove carbon fines • paniculatc filtration on full flow lean amine

• some units monitor.1P or only changcout once every 1-2 years and do not determine if carbon is spent

system

Particulate Control I Removal

Level 3

(Recommended practices are in addition to Levell) Recommended Practice Rationale

• TSS target and filter rating detennined by particle characterization; estimated levels < 30 ppm for TSS and < 25 J.I absolute for filter size

•

beds preferred to cartridge units where possible

Carbell

• with the exception of "deep bed" systems coaIlmed c.aroon prefmed over wood based carl>on • additional mechanical filtration downstream of carbon system with < 5 f.l absolute I'llting (see paniculare removal)

• cartridge unit have shorter life, requiring more frequent change:out and thus less likelihood oftJeing changed out when required • coal based carbon has bigher adsorption capacity. broader distribution of micro pore sizes and is harder than wood based carbon • several facilities with no filtration downsttcam of caJbon unit reponed problems with caJbon. fines in amine

• caJbon perfonnance is very sensitive to loading procedures • full flow lean filtration is already recommended in "Amine Treating Best Operating Practices" and is commonly used in Chevron facilities • determination of appropriate TSS targets and filter raring requires particle characterization (see notes) • TSS targets of 30 ppm and filter rating of 25 J.I absolute were typic:a1 of upstream gas plants which have more stringent requirements

• dual filtration system with full flow filtration on lean lor rich) upstream of earbon units and slip stre:llTl filtration downstream of carbon unit; slip stream rate determined by carbon treatment requirements • csrimale 25 f.l and 5 ",.absolute filter raring on fuUliow and slip stream filters rcspecri"ely (again depends on particle c:baraderization) • TSS larJ;:et < 30 ppm

• duaJ filtration recommended by vendors; full flow filler achieves bulk removal, slip stream filtration removes fiDes· this arrangement minimizes capital costs

APPENDIX SURVEY DATA

Survey Data Overview A. Upstream Facilities: CCR - Kaybob South, Bigoray, West Pembina, Medicine Lodge, Mitsue CUSA - Carter Creek Warren - Sandhills #193, Leedey#217, Sulphur Springs (Como), Monohan (Wickett), Sanders, Canadian

TI~e

Of Amine Plant

Number Of Plants

DEA MDEA UCARSOL MEA Total

Volume Of Gas Treated (MMSCFD}

5 2

1

597 70 34 146

12

847

I

Total Amine Circulation (GPM} 9290 45 85 1190 10610

3 non-associated gas plants 9 solution gas plants

B. Downstream Facilities: CUSA Products - Richmond #5 Pascagoula (all plants combined on one survey form) EI Paso Areas 2 & 5 EI Segundo Plants 2,4,&5 Salt Lake City Hawaii

TI~e

Of Amine Plant

Number Of Plants

DEA MDEA MEA Total

Volume Of Gas Treated (MMSCFD)

5 2

125 29 27 181

£ 9

Total Amine Circulation (GPM) 7200 285 320

7805

C. What Constitutes Good Performance: Use number of incidents of off spec gas per volume gas throughput or per volume amine circulated as guide. Note that for upstream facilities off spec gas generally means> 4 ppm whereas for downstream facilities off spec gas means - > 50 ppm U~stream

Total Gas (MMSCFD) Average Gas (MMSCFD) Total Amine (GPM) Average Amine (GPM) Total Incidents Per Year Average Incidents Per Year Incidents Per E4 MMSCF Incidents Per E8 Gallons

847 70 10610 884

174 14.5 5.6 3.1

Downstream 181

20 7800 870 64 7 9.7 1.7

Operational/Design Issue

SUMMARY OF K.t. V SURVEY DATA Upstream Facilities - Observation

Downstream Facilities - Observations

•

Free Hydrocarbon Removal (skimming I inlet scrubbing)

• of the plants with the four highest incident rates all are solution gas plants, however the majority of the plants are" solution gas plants • of the 4 worst upstream performers 2 do not have skimming systems and one has a system which is rarely used • of the remaining 8 plants all have skimming systems except for two, one of which processes dry gas • some plants have skimming systems in multiple locations and these are generally better perfonners • most common location for skimming system is on flash drum but also have systems on contactor, regenerator reflux drum, and surge tank • all, systems are manually controlled • all plants have inlet separators or knockout scrubbers • 2 out of 12 plants have inlet coalescors as well as inlet separators • one plant has recently ( I year ago) taken coalesor filter out of service with no noticeable impact

• all plants have skimming systems, most commonly on flash drum but also occurs on regenerator, contactor and surge tank • 3 plants have skim systems on multiple locations • no clear correlation between skim systems and performance • all systems are manually controlled • all plants have knockout scrubbers • no plants have inlet coalescors

•

Entrained Dissolved Hydrocarbon Removal (carbon)

• all plants have carbon systems although one is out of service; 7 out of 12 are beds, 2 are cartridge systems arid one is combined with particulate filtration • 10 out of 12 carbon systems are located on lean amine downstream of particulate filters, the two units located on the rich side do not report any apparent advantages and in fact are two of the four plants which have incidents rates> 15 per year • all carbon treatment is on slip streams ranging from 5 to 30% of total flow, average - 20% • excluding one plant the minimum frequency of carbon changeout is semi-annual, many changeout more frequently on basis of problems or amine quality, one plant changes out every two years with no reported problems • only lout of 12 facilities uses steam regeneration; others have used it but report that is had minimal value and could upset the bed • 3 of 12 plants have additional filtration downstream of carbon beds • 3 plants report foaming problems due to carbon fines occasionally breaking out of beds

• 2 plants have inlet water wash systems • out of9 plants only 2 have permanent carbon systems in operation, one plant has taken it's system out of service, 3 plants have used / are using temporary carbon systems on as needed basis, 3 plants have no carbon systems at all • where carbon systems (permanent & temporary) are in place slip stream rates range from I to 25% offull flow with an average of -12% • minimum frequency of carbon changeout is annual • where carbon systems (permanent & temporary) are in place, 80% have both upstream and downstream filtration

•

Particulate Removal (filtration)

• all plants have cartridge filters on lean amine although one plant no longer uses the filter • 5 out of9 plants filter full flow, the remaining plants filter slipstreams ranging from 10 to 50%, averaging -20% • micron rating of filters ranges from 3 to 40 microns with an average of20 microns • plants without carbon tend to have higher micron ratings • only two plants monitor TSS routinely and target 6" ISkimming&:'

Ie.

,carbon Skimming

Swgc':":~;rber, Absorber Surge tank

Manual Manual Manual

6/11/96

Amine Filtration & Hydrocarbon Removal Best Practice - Survey Data Summary Sheet 3 - Hydrocarbon Removal - Activated Carbon & Feed Pretreatment ~Ior

N.... or r.dllf:\·

""".... or

T,'..., orl:nI.

enhon l:1II1

Siuor Clnon

e ..... Ml'If

a.lrer (L8)

su...

F~'

at

10

Crtmi_ for

o.annoul

ChaAac:doul with puticul.1e filler

CombilKd "ith KI"bob South

........... l!...,-n_'

n- T.. e.rhoa l 'IBI

Chanl!ftlQt

Filtninll!

DP Ii. Imine uolir.-

10 boldin, pits A then buried

5CCpllniculllcfillerin No -

Lean· jusl before: retunllnllo

Bi

carbon bed

0111\

WcslPr:mbi ...

McdicineLodllc

nrbonbcd

luction

carbon bed Lean. after cooler

"

10

30

100

10

.00

Monthh' E"cl'\' 3 dl\"s

DP

No

HaunIoID fllCilin'

-.cd 10 . ,••

partinl.lc tillcn

"*aor fillet hal

upsllam _ nothinl

mno\-cd il "idl ..

downslrcam

irnpKl

,·.ute disposa

uartel'h'

partKulllcfililm up3tn:am II:

IlIleI"",

do\\'nsuam

coaiaot'tiller

follcm-.l ~.

c.nbir..aI

"

.....

,antidc

MibllC

Sutdhilb =19.1

SulehurSorin s

partic.Jltc (iI~ upstn:ua.lIOlkin.

Rich-bcmftftflash a:. re en.

10

lank

Caniuel' bulk Lean· before amine ~pe Ill!fiC Le.n-inldle

I - 2 rnonlhs

1350

·h.IO.6lC10 B:'I[ 10 scmi·.,.nWLI

foamin.

No

cliff_ .. iaJ.t scpaDM' A.

N.

downstream

upstream.,.,tiltcr (25micronJ. «m'ftltrDam lOCk (5 Upon r_inr

No

Wuhabun

d.aih··~lor

",~ron)

InI01~1On

DP

"

None

U~n

No

No

aofilnaboft

"

I.'"

6:dO

_i-Innual

_ilofl.MiftC q .... ir,.· monilGrin,

~2S •• stJamsoct filter

No

............

(dm\lntlnachcd

BIIt\·on silC

Inldba.scRibber

--

No

Jb\'chorizoaIaI

,..... ~ fn.lo(

,lUll (i. . . .,o\. . . _ _lLD\·at..!

OI:~um:nc.or

........mi .. lOCt fillc,. upsuam or c:hucoaJ. CMIlfC

opcRItilll ptObkrns. bail

Saund~nPfanl

LcaIHlo\\lIItream \'crll~al \'C!L'lC1 ICln sock fill~n

CAe 150. H(7S GPM)

6SOO

~~~

olke C\.~.

or..mftCqualir,.· monuonnl. ~olo,

GAGS

IUnu

!'Cll1I

fillcn"lwnDp~7

No

i ..lcmaIlCl'IIIbbcr. lOp of IU eo.trKloi to ~lIccl CWf!o'O''CI',

I"rf1I..aIco _ _

nah ,·ascI.

On lanlille

KOCH-LlQ .~"drucarbon Imu'le s.ixcrinlinarorliq

trabnl.

KinllDOl coUaor lilter. Uailp

RKh·lncrnub c.-Jiu Planl

~arbon

beds and bal!

fill~r

\·.ria G-100

1700

IUO

_i· .. nul

O«:lIfftIICcof opc,.lInl robkms

-

...._ o f

dU.c: ..... lin (an.

No

hilhc:orrosi~

CartcrCrect

Lan· before sU'le urbon beds link

7000

6:oc 10

_i'lnnWlI

iMibilor l'Oidlllll

Icmpo,wr

,......

..... CO . . . . . . . .,.. ,topped

lalllGrelcecnboR faeilin'

,,_tl~··T3rS..

abtorbance. lurbidin'

~S

Pesn.llull'llI

IllS '1IIbi

tcrnpol1l~' loCIfI - do,,'ftSlRun clrbonbcds ofplnic:ulltc fillCI'I

noC:lrbon

IS· OIII~ when ncCIXd

10000

N.

upIolRl ....ltdbq

lihers dowmnan.

facililiesonh' -...rKe

none Lcan.II\crrich

Coa~ filler

~.""dJe fillcn

foamillior

Richmond

upslrelm partieullte

No

N.

N.

N.

lupslRlm ".rticYiaIe No

N.

_.,,1w:a Innual

No

EIPuoAreal

.......

None· ....nl 1~!IIpOfII~

FJ Sc ulld..

~"

No

basiS

"....,,,'Dh. poI~'HIpfMc

ICnbbcr. ialel

F.I Sc:IIUndn

EI Selunda

~l

=~

N.~

Carboll bedslem"",.. r;. L.c.n - downstream IKI/IIIC::! of rich lean 11I5talled c:occhanllen

'"

2000

8~.lO

Innual

_.r

kftoctOlddntM

No

InJcltnoctOUll

No

Upsll'CMl ~rt;culalC.

amine

RelumlDCaI.OII

""cd:"',

'I''''

~a.rbon

Upsl_malll ~rtlf;;u.I.lcfih~r:

Sail Lakc{;ln

Lan • dol\'ftSU'eam Carbon beds of .mine coolc'

dO\\ns~

160