Acid Gas Removal (Part 3: Amine Treating Unit)

Finishing post about Acid Gas Removal, here is an explanation about the most common process that is used to remove acid gas in LNG plant: Amine Treating Unit (ATU).

Amine Treating Unit uses chemical solvents to remove the acid gas. MEA (Monoethanol Amine) and DEA (Diethanol Amine) are solvents that commonly used in ATU. But currently, DEA is more commonly used as chemical solvents because of reasons below, compare with MEA:

- DEA is weaker base, it reduces the corrosion problem

- DEA has lower vapor loss due to low vapor pressure

- DEA requires less heat for regeneration

- DEA does not require reclaimer to remove contaminants

Below is typical gas sweetening by chemical reaction:

1. Amine Absorber/Contactor

Amine absorber has counter-current flow between sour gas and solvents. The tower can be designed as tray column or packed column. Tray column has larger diameter, usually has 20-24 actual tray. For preliminary design, a tray spacing 24 in and a minimum diameter capable of separating 150-200 micron droplets can be assumed. Packed column has smaller diameter and size of tower must be obtained from manufacturer's published literature.

Commonly, amine absorber include an integral gas scrubber section in the bottom of tower to remove entrained water and hydrocarbon liquids from the gas to protect the amine solution from contamination. This scrubber has same diameter as the tower. Alternatively, a separate scrubber vessel (inlet separator) can be provided so that the tower height can be decreased. This vessel is designed in accordance with two phase separator design.

Outlet separator is required while using MEA as solvents, to help reducing MEA losses in the overhead sweet gas. DEA does not require this outlet separator.

2. Flash Drum

The rich amine solution from the absorber is flashed to a separator to remove any hydrocarbons and small percentage of acid gas. Some liquid hydrocarbon may begin to collect in separator, hence need provision to remove liquid hydrocarbon. Typically flash tank is designed for 2-3 minutes retention time for the amine solution while operating half full.

3. Amine Reboiler

The reboiler provides the heat input to amine stripper, which reverses chemical reaction and drives off acid gas. Amine reboiler may be either a kettle reboiler or an indirect fired heater. The higher reboiler duty, the higher condenser duty, the higher reflux ration, and thus the lower number of trays required and vice versa. For design, reboiler temperature in stripper operating at 10 psig can be assumed 245 F for 20% MEA and 250 F for 35% DEA.

4. Amine Stripper

Amine stripper use heat and steam to reverse the chemical reactions with CO2 and H2S. The steam acts as a stripping gas to remove the CO2 and H2S from the liquid solution and to carry these gases to the overhad. The tower can be trayed or packed with packing normally used for small diameter columns.

The typical stripper consists of a tower operationg at 10-20 psig with 20 trays, a reboiler, and an overhead condenser. The rich amine feed is entering the third or fourth tray from the top. The lean amine is removed at the bottom of stripper and acid gas is removed from the top.

For most field gas units, it is not necessary to specify stripper size. Vendors have standard design amine circulation packages for a given amine circulation rate, acid-gas loading, and reboiler.

5. Overhead Condenser and Reflux Accumulator

Amine-stripper overhead condenser is typically air-cooled, fin-fan exchangers. Their duty can be determined as required to cool the overhead gases and condense the overhead steam to water. The inlet temperature can be found using the partial pressure of the overhead steam by using steam tables. The cooler outlet temperature is typically 130-145 F, depending on the ambient temperature.

The reflux accumulator is a separator used to separate the acid gases from the condensed water. The water is accumulated and pumped back to the top of stripper as reflux. With the vapor and liquid rates known, the accumulator can be sized for two phase separator.

6. Rich/Lean Amine Exchanger

Rich/lean amine exchanger is usually shell-and-tube exchanger with the corrosive rich amine flowing through the tubes. The purpose of these exchanger is to reduce the reboiler duty by recovering some of the sensible heat from the lean amine.

For design, an approach temperature of about 30 F provides economic design balancing the cost of the rich/lean exchanger and the reboiler. The reboiler duties recommended above assume a 30 F approach.

7. Amine Cooler

The amine cooler is typically air-cooled, fin-fan cooler, which lowers the lean amine temperature before it enters the absorber. The lean amine entering the absorber should be approximately 10 F warmer than the sour gas entering the absorber. Lower amine temperature may cause the gas to cool in the absorber and thus condense the hydrocarbon liquid. Higher temperature would increase the amine vapor pressure and thus increase amine losses to the gas. The duty for the cooler can be calculated from the lean-amine flow rate, the lean-amine temperature leaving the rich/lean exchanger and the sour-gas inlet temperature. Solvent tank is required to contain lean amine.

8. Amine Solution Purification

For MEA, reclaimer is required to removed contaminants due to reaction of MEA with COS and CO2, to form heat-stable salt. Reclaimer is a kettle-type reboiler operating on a small side stream of lean solution. The temperature in the reclaimer is maintained such that the water and MEA boil to the overhead and are piped back to the stripper. The heat-stable salt remain in reclaimer until the reclaimer is full. Then the reclaimer is shut-in and dumped to waste disposal. The impurities are removed but the MEA bonded to the salt is also lost.

DEA system is not requiring reclaimer because the reaction with COS and CS2 are reversed in the stripper. The small amount of degradation products from CO2 can be removed by a carbon filter on a side stream of lean solution.

9. Material of Construction

For DEA: stress-relieved carbon steel
For MEA: corrosion-resistant metals (304 SS)

Reference:
1. DMAN-TPE-ENGPRO-008 Acid Gas Treating Design Manual 

2. GPSA Section 21: Hydrocarbon Treating

Acid Gas Removal (Part 2: Iron Sponge)

Below is explanation about Iron Sponge:

• Use chemical reaction: 2 Fe2O3 (ferric oxide) + 6 H2S ---> 2 Fe2S3 + 6 H2O
• Applied to gas with low H2S concentration (300 ppm). Carbon dioxide is not removed by this process Operating at low to moderate pressure (50-500 psig) 
• Temperature below 110 F 
• Need alkaline water with pH level 8-10. Injection of caustic soda with water into inlet gas stream is needed if the water is not sufficient 
• Ferric oxide is impregnated on wood chips to produce large surface area. Common grades based on iron oxide content are: 6.5, 9.0, 15.0, 20 lb iron oxide/bushel 
• Gas scrubber or filter separator on upstream of iron sponge unit is needed to minimize amount of hydrocarbon liquids condense to bed. Hydrocarbon liquids can coat iron sponge and inhibiting the reaction. The scrubber operates at lower temperature or higher pressure than iron sponge unit, to prevent possibility hydrocarbon liquids condensing in iron sponge unit. 
• Normally operated in batch mode without regeneration due to difficulty of controlling regeneration step, the eventual coating of the bed with elemental sulfur, the low cost of iron material, and the possibility of hydrocarbon liquids coating the bed. 
• The spent bed is removed from the unit and trucked to disposal site. It is replaced with a new bed and the unit put back in service.

Amine Treating Unit will be explained in next post :)

Reference:
DMAN-TPE-ENGPRO-008 Acid Gas Treating Design Manual

Acid Gas Removal (Part 1)

Continuing the explanation about LNG, I will try to summary each of LNG process steps from reference I read. First is about Acid Gas Removal.

Acid gas such as CO2, H2S, and other sulfur compounds like mercaptant are need to be removed because they cause corrosion and reduce heating value (sales value) of the gas. Typically, gas sales contracts will permit up to 2-3% CO2 and 1/4 grain per 100 standard cubic feet/scf (approximately 4 ppm) H2S.

Below are explanation about some acid gas removal processes.

1. Solid Bed Absorption

Using a fixed bed of solid to remove acid gases through chemical reaction or ionic bonding and hold acid gases in the bed. After the bed is saturated with acid gases, the vessel is out of service and the bed is regenerated or replace. Thus, some spare capacity must be provided. Three commonly used processes under this category are:

- Iron Sponge
- Molecular Sieve
- Zinc Oxide

2. Chemical Solvents

Chemical solvent processes use an aqueous solution of a weak base to chemically react with and absorb the acid gas in the natural gas stream. The absorption occurs as a result of driving force of the partial pressure from the gas to liquid. The reaction involved are reversible by changing the system temperature and pressure, or both. Therefore, the aqueous base solution can be regenerated and thus circulated in a continue cycle. The majorities of chemical solvent processes use either an amine or carbonate solution which are:
- MEA (Monoethanol Amine)
- DEA (Diethanol Amine)
- DGA (Diglycol Amine)
- DIPA (Diisopropanol Amine)
- K2CO3 (Potassium Carbonate)
- Proprietary Carbonate (K2CO3 with activator or catalyst)

3. Physical Solvents

This process is based on solubility of H2S and/or CO2 within the solvent. Solubility is depends on partial pressure and temperature. Higher acid gas partial pressure and lower temperature increase the solubility H2S and CO2 in the solvent.

Most physical solvent processes are proprietary and are licensed by the company that developed the process such as:
- Fluor Solvent
- Sulfinol (Shell)
- Selexol (Allied Chemical Company)
- Rectisol (The German Lurgy Company and Linde A. G.)

4. Direct Conversion H2S to Sulfur

The release of H2S to atmosphere may be limited by environmental regulations. Usually acid gas is routed to incinerator or flare. Or otherwise, H2S can be oxidized to produce elemental sulfur by chemical reaction. These processes are licensed and involve specialized catalyst and/or solvents. Some of the processes are:
- Clause
- LOCAT
- Stretford (British Gas Corporation)
- IFP (Institute Francais du Petrole)

5. Distillation

The Ryan- Holmes distillation process uses cryogenic distillation to remove acid gases from a gas stream. This process is applied to remove CO2 for LPG separation or where it is desired to produce CO2 at high pressure for reservoir injection.

6. Gas Permeation

This process is based on the mass transfer principles of gas diffusion through a permeable membrane. The driving force for the separation is differential pressure. Membrane system can effectively remove CO2 and water but not H2S. The side of membrane that is rich in CO2 is normally operated of 10 to 20% of the feed pressure. Membrane are a relatively new technology. They are attractive economic alternative for treating CO2 from small streams (up to 10 MMscfd).

The most common process that is used are Iron Sponge and Amine Treating Unit. They will be explained in 2 next post :)

Reference:
DMAN-TPE-ENGPRO-008 Acid Gas Treating Design Manual

LNG (Liquefied Natural Gas)

In the new office, I am assigned in one of Indonesia LNG Project located at Papua which is BP LNG Tangguh. Even though the project has not been started yet, I have to start learn about it because I never do LNG project before.

Below is the simple brief explanation about LNG, result of me reading some references in this one week :)

LNG is liquefied natural gas, used as fuel that cleaner than oil fuel. Natural gas is processed and liquefied to be liquid. Why must it change to liquid? Because gas distribution using pipeline is restricted by distance. Many gas sources are located far from users. To reach far users, LNG is sent by tanker. Beside that, gas volume in liquid phase is 600 times less than gas volume in vapor state. So liquid phase can reduce space for LNG distribution.

Liquefaction is a cryogenic system, due to natural gas cooling to below boiling point which is about -160 degree Celcius. LNG is stored at atmospheric pressure in a tank that has double wall and insulated to prevent boil off gas. Before sent to customer, LNG is reheated so can back to vapor phase.

Process steps to change natural gas to LNG are:

1. Acid Gas Removal, to remove acid components such as Carbon Dioxide and Sulfur that corrosive to the material and will also freeze while liquefaction process. Usually, Amine Treating Unit is used to remove this acid component.

2. Dehydration, to remove water that also corrosive and freeze while liquefaction process. Usually, industry uses molecular sieve to remove water.

3. Mercury Removal, to remove mercury component that can damage alumunium material. Usually aluminium is used as cryogenic heat exchanger material. To remove mercury, a bed that sulfur impregnated, carbon activated, and non-regenerative is used in industry.

4. Heavier components removal, to prevent solidification of this component by using condensation and distillation process.

5. Liquefaction, to cool gas to below its boiling points by using heat exchanger. Usually use propane and mixed refrigerants (N2, CH4, C2H6, and C3H8) as cooling medium. Refrigeration cycle is used in this liquefaction process.

6. N2 rejection, to remove N2 component from LNG because N2 is still in gas phase at the natural gas boiling point (not change to liquid phase).

7. Storage in LNG tanks and loading to tanker.

Below is a simple diagram of LNG Process:

 

Finally, a post about my job as a process engineer hehe..

I hope you are not feeling dizzy and this post still gives you information :)

References:
1. LNG Handout Slide by Aday Wakhid Nurhidayat & Irfa Nauli - Tripatra
2. DMAN-TPE-ENGPRO-006 LNG Plant Manual
3.  Project Description: LNG Plant by Arrow LNG Plant