Gas Treating or sweetening are both terms used to describe the various processes for removal of certain contaminants, primarily hydrogen sulfide (H2S) and carbon dioxide (CO2), from natural gas or hydrocarbon liquids. CO2 and H2S are also termed “acid gases” because when absorbed in water, they form an acidic solution. Other reasons to remove these contaminates include toxicity, corrosiveness, freezing problems and control of the overall heating value of the natural gas.

In addition to H2S and CO2, the sulfur acids, carbonyl sulfide (CS2), carbon disulfide (COS) and the mercaptan family (RSH), when present in sufficient quantities, are also candidates for removal with specific amines.

Typical Gas Pipeline Specifications:

H2S	0.25 grain/100 scf or 4 ppm
CO2	2-3 mol% (5% inerts)
CS2, COS, RSH	20 grains/100 scf

Natural Gas Liquid (NGL) Specifications:

H2S, Sulfurs	Pass Copper Strip, ASTM D-2420
CO2	varies – 0.35 LVP of Ethane, content 1000 ppm or less, dependent on application

Types of Alkanolamines and Physical Solvents

The removal of acid gases by the amine process is accomplished by a chemical reaction. Physical solvents (Selexol, Sulfinol, Propylene Carbonate) remove acid gases by straight absorption or a combination of absorption and chemical reaction. Amine can be categorized on a chemical basis as being primary (MEA, DGA), secondary (DEA, DIPA) and tertiary (MDEA, TEA) depending on the number of substitutions onto a central Nitrogen element. Modern solvents include formulated MDEA (Ucarsol, Gas Spec) and hindered amines (FLEXSORB). This chemical structure influences each amine’s properties as a treating solvent and therefore, lend themselves to different applications. The following is a list of conditions or considerations, which must be defined when selecting a treating solvent.

1. Operating pressure and temperature
2. Amount of acid gases and quantity removed, selectivity, treated gas specifications
3. Disposal of acid gases (sulfur recovery, incineration, etc.)
4. Contaminants in the inlet gas (oxygen, RSH and other sulfur species, free liquids, gas “richness”, etc)
5. Environment (spill reporting, allowable ambient S02 emission, etc)
6. Customer preference (capital and operating costs, fuel efficiency, chemical costs, etc.)

PHYSICAL vs CHEMICAL SOLVENTS		COMPARISON OF MEA AND DEA
	PHYSICAL SOLVENTS		MEA (DGA)
A.	High acid gas partial pressure only (lots of acid gas)	A.	High Capacity per gallon
B.	Bulk removal-high overhead specification	B.	Stronger base: operate at low pressure
C.	May require refrigeration	C.	Complete COS, CS2 removal
D.	Large contactors – many trays	D.	May be reclaimed
E.	Proprietary solvents	E.	Most heat required to regenerate
	CHEMICAL SOLVENTS		DEA (DIPA)
A.	All acid gas partial pressure ranges	A.	Lower reaction heat duty
B.	Lower overhead specification (pipeline specs)	B.	Lower vaporization heat duty
C.	Low solvent losses	C.	Less corrosive
D.	Low hydrocarbon solubilities	D.	Minimal degradation losses to COS, CS2

General Equipment Description

Q. B. Johnson Manufacturing, Inc. designs and builds gas and liquid treating/sweetening plants from 3 gpm to 300 gpm, with component pieces as large as required. The following is a brief description of the major equipment necessary for successful treater operation:

A. INLET SEPARATION:
Most often, amine unit operating problems can be traced to contaminates brought in with the gas from the pipeline. Pipeline contaminants can be in the form of “down-hole” corrosion inhibitors or other “treating” chemicals, liquid slugs caused by pipeline volume surges or line pigging, well “workover” fluids sent to the pipeline and compressor lubricating oils. Two-phase separators are satisfactory only for known liquid volumes and not “pigging surges” or aerosols. An “absolute rated” Coalescer is highly recommended for the removal of fine liquid particles.

B. OUTLET SEPARATION:
The function of the outlet separator is to remove the entrained liquid amine carried over with the gas from the contactor/absorber. The liquid carryover is normally not very severe except during heavy foaming or upset. Depending on the cost of solvent, it may be worthwhile to install a liquid coalescer on the amine contactor outlet to recover valuable solvent. A slug catcher or properly sized outlet separator should be installed in front of the outlet coalescer, which cannot handle large liquid volumes. Other methods to capture amine losses are water wash systems and/or outlet gas coolers.

C. CONTACTOR or ABSORBER:
The contactor is typically designed with 20 float valve trays (or an equivalent amount of packing for smaller vessels) and a 4” or 8” thick mist pad in the top. Tray spacing should be sufficient for liquid foam disengaging space. Also, adequate disengaging must be provided at the top of the tower (Q. B. Johnson recommends a 4-foot minimum). Selective solvent typically have multiple feed points on the contactor to allow slippage of some acid gas, usually CO2.

D. FLASH TANK:
The flash tank is used to “degas” the rich amine coming from the high pressure contactor. Flash tanks should be provided with skimming nozzles at locations around the normal liquid operating level to allow removing liquid hydrocarbon build up or be built for 3-phase operation. A good rule of thumb for hydrocarbon vapor pickup is 2 scf/gal and typical residence time is between 5 and 30 minutes.

QBJ recommends the flash tank amine level control valve be located downstream of the rich/lean exchanger as close to the still column inlet as possible in order to ensure that breakout acid gases enter the column rather than the piping, filter or exchanger.

E. AMINE EXCHANGER:
The rich/lean exchanger is a heat conservation device where hot lean solvent preheats cooler rich solvent. Shell-and-tube, plate-frame and double-pipe exchanger are typical choices for exchanger; stainless tubes are preferred on the rich solvent. Temperature of the rich outlet should be approximately 200°F and lean down to 160°F to maximize heat recovery. Pressure drop on the cold side should be kept at 5 psid or less, and depending upon whether booster pumps are in the design, hot side pressure drop should kept at or below 2 psid. Strainers should be considered on both sides of the exchanger to keep solids out of the exchanger.

F. AMINE COOLER, REFLUX CONDENSER:
The amine cooler is an air-cooled, forced draft with automatic louvers for temperature control. Cold climate service may require air-recirculation and/or preheat media on fans/coils. Condenser tubes should be made of stainless steel, as this is a wet, acid gas environment and sloped to the outlet side.

G. AMINE STILL:
Again, depending upon the solvent type, this is normally a 20-tray or equivalent packed tower. Physical solvents can require less trays. Trays are normally on 24” spacing, liquid and jet floods in the 65-75% range with a 75% foam factor. It is highly recommended that trays and possibly even vessel in the upper third, be stainless steel due to the corrosivity of the environment.

H. REFLUX ACCUMULATOR:
This vessel separates the reflux water and water-saturated acid gases. The water is pumped back to the still and the acid gases are directed to a vent, incinerator or sulfur recovery unit. Most reflux accumulators have a 4” to 8” thick mist pad.

I. SOLVENT REBOILER:
This is either a direct-fired firetube type, cabin heater, indirect hot oil or steam heated unit. Typically heat flux rate should be kept in the 7500 to 10,000 Btu/hr/ft2 range to assure no surface burning of the solvent. This exchanger provides the steam necessary to heat and strip the solvent back to a “lean” condition.

J. PUMPS:
The reflux and booster pumps are normally centrifugal, inline or horizontal pumps. Seal systems are an important consideration on the reflux pumps when treating H2S gases, as seal failure will result in H2S emissions. The main circulation pump choice depends upon contactor operating pressure and solvent flow rates. Positive displacement pumps should be considered for 250 gpm and below, and high discharge pressures; centrifugals are considered for low head cases and large volume, high head cases. These pumps should be designed for amine service and have non-lubricated packing/system seal with ceramic or hard coated fluid parts.

K. FILTRATION: MECHANICAL AND CARBON ABSORPTION:
These units are the second line of defense (only slightly less important than good inlet gas cleanup) against plant foaming and related upsets.

1. MECHANICAL FILTERS: Solids help stabilize foam and can cause aerosol formation in the contactor. The filtration should be staged down to a 10 micron ABSOLUTE rated element or below.
2. CARBON ADSORPTION: Carbon filters are used to remove heavy hydrocarbons, other liquid contaminants and dissolved solids. Carbon should be 8 X 30 mesh granular activated (with larger pores), minimum ash content (silicone, metals, etc.) and moisture content. Contact time with the amine solution should be 20 minutes with superficial velocity in the 2 to 10 gpm/ft2 range. When using a carbon filter, it is highly recommended to have a downstream mechanical filter to remove carbon fines, which will occur due to various reasons.

L. RECLAIMERS:
MEA and DGA systems, as well as Sulfinol systems, are normally installed with reclaimers to maintain solvent quality by reducing corrosion, foaming and degradation of the solvent. Reclaimer’s vaporize “good” solvent, leaving behind solids, sludge, HSAS and decompositions products.

M. LIQUID PHASE TREATERS:
A liquid phase amine treater is similar to gas phase treating once the amine enters the regeneration systems. Inlet liquid filtration is very important. Liquid/liquid contacting can be accomplished by packed towers, static mixers or other mass transfer devices. An outlet settling tank with a 10 to 30 minute NGL retention is typical and liquid/liquid coalescers may also be required on the outlet NGL stream to extract liquid amines.

The treating or sweetening process is also used in the Shell’s SCOT tail gas cleanup unit (TGTU) and other wet scrubbing processes behind SRU’s. In addition, it is used to clean up landfill gases, remove CO2 from air in glass manufacturing, clean air in some breathing air conditioning operations and many other industrial processes.

Q. B. Johnson Manufacturing, Inc. can engineer, design and manufacture treaters for any application. We have successfully provided treaters for natural gas field installations, refinery off gas sweetening applications, liquified ethane CO2 treating, raw NGL treating and others. If you have an application requiring H2S, CO2 or any of the sulfur acids removal, please contact Q. B. Johnson Manufacturing, Inc.

Click the link to inquire about our Amine Units