AMINE PLANT TRAINING SESSION
March 11, 2010
Course Outline • • • • • • • • • •
Overview
JV
Sweetening Methods Process Flow Diagram / Specifications General Operating and Design Considerations Equipment Metallurgy Cost Considerations Acid Gas Handling Amine Workbook Acid Gas Handling - Membranes
JM
OVERVIEW
Gas Treating Overview To Flare, Reinjection, Sulfur Recovery Acid Gas (H2S, CO2) Sweetening (amine, mol sieve) Sour, Wet Gas
Dry Lean Gas Sweet Gas
Dehydration (mol sieve, glycol)
H2O
Recycle Gas
LP Separation
Dry Rich Gas
HC Liquid
Production
HC Liquid Stabilization / Fractionation
Compression HP Separation
Sour H2O
To Disposal, Reinjection, Treatment
Residue Gas Compression
Spec Gas To Pipeline
HC Liquid Recovery (DPC, TE)
HC Liquids
NGL / Stabilized Condensate
To Pipeline or Storage
Pipeline Product Specifications Sales Gas
Water
7 lb / MMSCF (US) 4 lb / MMSCF (Canada / Europe)
HC Dewpoint
15 – 32 F
H2S
< 4 ppmv (¼ grain H2S / 100 SCF)
CO2
< 2 mol%
CO2 / N2
< 2mol%
NGL
C3+
< 2 mol% C1/C2
Stabilized Condensate
C5/C6+
RVP 13.5 psia TVP 13.0 psia
SWEETENING METHODS
Sweetening - Terminology H2S
Hydrogen Sulfide
Gas Impurity
COS
Carbonyl Sulfide
Gas Impurity
CS2
Carbon Disulfide
Gas Impurity
CH3SH, C2H5SH
Mercaptans
Gas Impurity
EG
Ethylene Glycol
Dehydration
TEG
Triethylene Glycol
Dehydration
MEA
Monoethanolamine
Sweetening
DEA
Diethanolamine
Sweetening
MDEA
Monodiethanolamine
Sweetening
DGA
Diglycolamine
Sweetening
Sweetening - Methods Chemical Absorption
Amines
Most widely used
Potassium Carbonate Physical Absorption
Selexol, Methanol
For high H2S and CO2 concentrations
Solid Bed - Regenerative
Molecular Sieve
Limited to H2S Removal
Non-Regenerative
Iron Sponge (Iron Oxide)
For low conc. (<3000 ppm) Disposal problems, pyrophoric
Zinc Oxide
Expensive
SulfaTreat (“refined” Iron Sponge)
Expensive , Non-hazardous waste Difficult Handling, Exothermic in Air
NaOH
Product is NaSH
Direct Conversion
Conversion of H2S directly to elemental S
Membranes
Bulk CO2 Removal
Extractive Distillation / Cryogenics
Bulk CO2 Removal
Absorption Processes Mixed or Hybrid
Chemical
NaOH
DEA
Flexsorb
MEA
Physical
Water
Rectisol (Methanol)
DGA
Sulfinol
Selexol
Activated MDEA
Selective MDEA
(add DEA)
(proprietary additives)
Amines MEA
10 – 20 wt%
Reacts rapidly with H2S and CO2 (non-selective) Largest carrying capacity (lowest circulations rate) Chemically stable (minimum solution degradation)
DEA
25 – 35 wt%
Similar to MEA Reacts with COS and CS2 Removes H2S and CO2 (non-selective)
DGA
40 – 70 wt%
Proprietary designs
MDEA
30 – 50 wt%
Tertiary Amine Proprietary designs Reacts with H2S in presence of CO2 (selective)
Sulfinol D or M (Shell)
Proprietary Mixture of sulfolane, water and either DIPA (D) or MDEA (M)
Flexsorb HP, PS, SE, SE+ (ExxonMobil)
Proprietary mixture of hindered amines
MDEA Selectivity
Selectivity is improved by:
• • •
Colder Temperatures Lower Pressures Higher Ratios of CO2 to H2S
Selectivity is achieved by:
• •
Kinetic effects due to more rapid absorption of H2S compared to CO2 (i.e. more rapid pickup of H2S). Contact time is limited. Equilibrium effects due to more favorable equilibrium solubility of H2S compared to CO2
PFD & SPECIFICATIONS
Process Flow Diagram
Design Parameters GAS FEED SPECIFICATIONS
• •
Gas Flow Rate Gas Composition
• • •
H2S, COS, CS2 CO2
Contaminants (heavy hydrocarbons, lube oils)
PRODUCT SPECIFICATIONS
• •
H2S, COS, CS2 CO2
ACID GAS HANDLING CONSIDERATIONS PROCESS HEATING CONSIDERATIONS
Estimation of MDEA Circulation Rate 0.206 x MM x (H2S + CO2) x MWT GPM = ML x WT
GPM
= circulation rate, GPM
MM
= gas flow, MMSCFD
H2S
= mol% H2S to be removed
CO2
= mol% CO2 to be removed
MWT
= molecular weight of MDEA = 119.9
ML
= mol loading, moles acid gas / mol amine
WT
= amine solution, weight percent
Estimation of MDEA Circulation Rate 0.206 x MM x (H2S + CO2) x MWT GPM =
0.206 x 44 x (0.012 + (5.0 – 2.0)) x 119.9 =
ML x WT =
0.30 x 50
218 GPM
GPM
=
circulation rate, GPM
MM
=
gas flow, MMSCFD
H2S
=
mol% H2S to be removed
CO2
=
mol% CO2 to be removed (inlet 5% – outlet 2%)
3.0%
MWT
=
molecular weight of MDEA
119.9
ML
=
mol loading, moles acid gas / mol amine
0.30
WT
=
amine solution, weight percent
50
44 120 ppm = 0.012%
GENERAL OPERATING AND DESIGN CONSIDERATONS
General Operating Problems
•
Corrosion
• • • • •
Amines are corrosion inhibitors generally Acid gases make amine solutions corrosive by lowering pH Most severe corrosion occurs at high temp (lean/rich exchanger, regenerator and reboiler) Stress corrosion cracking prevalent (stress relieving alleviates) Material selection (SS vs CS)
General Operating Problems
•
Solution Degradation
• • • •
Amine solutions will slowly oxidize when exposed to air. Products are corrosive. Minimized by gas blanketing amine storage MEA / DGA react with COS to form insoluble salt (reclaiming to recover amine) Some degradation products can not be regenerated
General Operating Problems •
Foaming
• •
Increases amine losses and can upset entire absorber Causes:
• • • • •
Suspended solids, Oil – lube, charcoal particles from filters Liquid hydrocarbons Amine degradation products Corrosion inhibitors Too much anti-foam
General Operating Problems
•
Reclaiming
• • • • •
Batch operation Distill the water and amine leaving behind entrained solids, dissolved salts and degradation products that cause foaming and corrosion problems Operates on 3% or less of the solution circulation rate Sludge will accumulate below tubes Not required on DEA and MDEA
General Operating Problems •
Filtration
• • • • • • • •
Extremely important Removes iron sulfide Filtration to 1 micron level Full Stream filter used to remove particles to 10-25 micron Sidestream (20% of circulation rate) activated charcoal filter to 1 micron Activated carbon filter also removes hydrocarbons, some degradation products, and reaction products Full stream filter downstream of charcoal filter
Inhibitors
• •
Foam Inhibitor Corrosion Inhibitor
General Design Considerations
•
Inlet Gas Scrubbing
• • • •
Extremely important Minimizes foaming, corrosion, and reboiler tube burn-out issues Removal of liquid hydrocarbons and entrained solids Removal of upstream corrosion inhibitors and lube oil carryover
General Design Considerations
•
Amine Losses
• • •
Gas Cooler and Scrubber downstream of contactor Minimizes amine in dehydration unit
Lean/Rich Amine Exchanger
•
Without a flash drum, LCV should be located downstream of R/L exchanger to minimize breakout of acid gases to minimize corrosion
General Design Considerations •
Amine Regeneration
• • • • • • • • • • •
Most likely spot for troubles and corrosion Highest temperatures Acid gases are broken down Best regeneration occurs at higher pressure but this increases reboiler temperature / duty Increased temp leads to excess corrosion and chemical degradation Temp usually 230 – 240 F. Max temp 260 F. Pressure typically 25 psia max. Heating in reboiler: hot oil, direct fired, steam Direct-fired reboiler difficult to control and minimize “hot spots” Direct fired fired up to 100GPM design Two or more reboiler inlets to improve natural circulation of liquid Two or more reboiler outlets to reduce stagnant pockets of acid gases
General Design Considerations
•
Piping Design
• • •
Low velocity allows a film on pipe wall to act as a corrosion inhibitor High velocity causes erosion Recommendations:
• • • •
Maintain liquid velocity below 6 ft/s in all piping Avoid screwed fittings, if practical Use welded fittings with long radius elbows; avoid tees when possible Avoid the use of dissimilar metals to avoid bimetallic corrosion
EQUIPMENT
Inlet Coalescer Scrubber • • •
•
Major cost item due to high pressure Highly recommended to prevent operational and corrosion problems Sizing
• •
Gas Flow Rate and Operating Pressure Typical Sizes:
• •
50 MMSCFD & 700 psig
48” OD x 84” S/S
100 MMSCFD & 700 psig
72” ID x 120” S/S
Options
• • •
Separator with mesh pad Porous Media coalescer Peco filter separator
Contactor
• •
Major cost item due to high pressure and size Sizing
• • • •
Diameter: Gas Flow Rate and Operating Pressure Height: Amine Circulation Rate Height: 20 trays typ., 2 - 3 min amine residence time in bottom section Typical Sizes:
• •
50 MMSCFD & 700 psig
48” ID x 660” S/S
100 MMSCFD & 700 psig
72” ID x 768” S/S
Gas Cooler
• • • • •
Major cost item due to high pressure Aerial cooler Gas/gas exchanger used to cross exchange with amine plant inlet if inlet temperature is low May not be required – depends on contactor outlet temperature Sizing
•
Gas Flow Rate and Operating Pressure
Sweet Gas Scrubber / Filter Coalescer • • •
Major cost item due to high pressure Recommended to minimize amine losses and contamination of dehydration unit Sizing
• •
Gas Flow Rate and Operating Pressure Typical Sizes:
• • •
50 MMSCFD & 700 psig
48” OD
100 MMSCFD & 700 psig
72” OD
200 MMSCFD & 700 psig
30” ID x 118” S/S (filter coalescer)
Amine Flash Drum
• •
Intermediate cost item due to medium pressure Sizing
• • •
Amine circulation rate Sized based on residence time. Typically 5 to 10 mins. Typical Sizes:
• •
200 GPM
72” ID x 192” S/S
650 GPM
120” ID x 360” S/S
Lean/Rich Exchanger
• • •
Intermediate cost item due to medium pressure Plate and frame exchanger OR S/T exchanger Sizing
• •
Amine circulation rate Typical Sizes:
• • •
50 GPM
2 MMBTU/HR
200 GPM
7.2 MMBTU/HR
650 GPM
15.5 MMBTU/HR
Amine Regenerator • • •
Also known as Amine Stripper or Amine Still Low pressure (< 25 psia) - Intermediate cost item due to size and trays Sizing
• • • • •
Diameter: Amine circulation rate / Acid gas loading Diameter: typically 6” – 12” smaller than contactor Height: Amine Circulation Rate Height: 20 trays typ., 2 - 3 min amine residence time in bottom section Typical Sizes:
• •
Top Section
200 GPM
36” ID x 768” S/S
650 GPM
48” ID x 252” S/S
Bottom Section
84” ID x 612” S/S
Regenerator Reflux Condenser • • • •
Low pressure (< 25 psia) - Low cost item Air Cooler Condensing water from acid gas stream Sizing
• •
Amine circulation rate / Acid gas loading Duty:
• • •
50 GPM
1 MMBTU/HR
200 GPM
2.6 MMBTU/HR
650 GPM
17.6 MMBTU/HR
Reflux Accumulator
• • •
Low pressure (< 25 psia) - Low cost item Separates condensed water from acid gas stream Sizing
• • •
Amine circulation rate / Acid gas loading Sizing Basis: 5 - 10 min residence time Typical Sizes:
• •
200 GPM
24” ID x 84” S/S
650 GPM
48” ID x 120” S/S
Reflux Pump
• • • •
Low pressure (< 25 psia) - Low cost item Centrifugal Recycle water from reflux accumulator to still Sizing
• •
Amine circulation rate / Acid gas loading Typical Sizes:
• •
200 GPM
3 - 5 HP
650 GPM
5 HP
Regenerator Reboiler • • • •
Low pressure (< 25 psia) - Intermediate cost item Thermosyphon or BKU Kettle-type Reboiler Steam, Direct-fired, Electric, Hot Oil Sizing
• • •
Amine circulation rate / Acid gas loading Estimation: Duty, MMBTU/HR = 1200 x GPM x 60 / 1,000,000 Typical Sizes:
• • •
50 GPM
3.6 MMBTU/HR
200 GPM
14.4 MMBTU/HR
650 GPM
46.8 MMBTU/HR
Amine Booster Pump • • • • •
Low pressure (< 25 psia) - Low cost item Charges lean amine to high pressure Amine Circulation Pumps Feed directly from surge section of reboiler / regenerator OR downstream of lean/rich exchanger Trade-off: NPSHr vs. lower design temperature Sizing
• • •
Sizing: Amine circulation rate Nominal 50 psi differential Typical Sizes:
• •
200 GPM
15 HP
650 GPM
50 HP
Lean Amine Cooler • • • •
Low operating pressure (50 psig) High cost item Cools lean amine from lean/rich exchanger upstream of high pressure Amine Circulation Pumps Sizing
• •
Sizing: Amine circulation rate Typical Sizes:
• •
200 GPM
6.3 MMBTU/HR
650 GPM
28 MMBTU/HR
Amine Particulate Filters and Amine Charcoal Filter • • • •
Low operating pressure (50 psig) - Lower cost item Sized for full flow or 10-20% slipstream Filters in series: Particulate – Charcoal - Particulate Sizing
• •
Amine circulation rate Typical Sizes:
• •
Particulate Filter
Charcoal Filter
200 GPM
18” OD x 56” OAH
42” OD x 49” S/S
650 GPM
36” OD x 60” S/S
84” OD x 264” S/S
Amine Circulation Pump • • • • •
Also known as Charge Pump High cost item High pressure pump sending lean amine to contactor Multi-stage centrifugal OR positive displacement pump Sizing
• •
Amine circulation rate and Maximum Contactor Pressure Typical Sizes:
• • •
50 GPM
50 HP
200 GPM
200 HP
650 GPM
500 HP
METALLURGY
METALLURGY •
Guidelines per API RP 945: Avoiding Environment Cracking in Amine Plants
• •
Reduce fluid velocity to < 6 ft/sec in rich amine carbon steel piping Stainless steel in certain locations
•
Areas of high acid gas loading, flashing vapor
• • • •
Contactor LCV to Regenerator Top section of Regenerator Reflux condenser and piping
Temperatures about 230F
•
Reboiler tubes
METALLURGY
•
Guidelines per API RP 945: Avoiding Environment Cracking in Amine Plants
•
For MDEA: PWHT for all carbon steel equipment, including piping, at operating temperatures exceeding 180F
• • •
Lower section of Regenerator Reboiler shell Reboiler inlet / outlet piping
COST CONSIDERATONS
Equipment Cost Example 200 GPM / 55 MMSCFD Equipment Cost Inlet Filter Coalescer Contactor Gas Cooler Sweet Gas Scrubber Flash Drum Lean / Rich Exchanger Regenerator Reflux Cooler Reflux Accumulator Reflux Pump (2) Reboiler Amine Booster Pump (2) Lean Amine Cooler Amine Circulation Pump (2) Particulate Filter (2) Charcoal Filter Hot Oil Heater Pkg
111,000 271,000
% of Total
$ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $
88,000 52,000 10,000 171,000 35,000 18,500 14,000 65,000 23,000 62,000 130,000 20,000 30,000 335,000
7.7% 18.9% 0.0% 6.1% 3.6% 0.7% 11.9% 2.4% 1.3% 1.0% 4.5% 1.6% 4.3% 9.1% 1.4% 2.1% 23.3%
$
1,435,500
100.0%
‐
LOW SPEC vs HIGH SPEC EQUIPMENT
LOW SPEC
HIGH SPEC
Inlet Coalescer
Peco Filter Separator
Porous Media Filter/Coalescer
Scrubber with Mesh Pad Contactor & Stripper
Koch Glitsch Minivalve trays
Koch Glitsch FLEXITRAY T-valve Trays
Filters
Std Cartridge Filters
3M Cartridge filters / housing Porous Media filters
Filters
Size for 10-20% Slipstream
Size for full flow
Lean Amine Flow Control
Manual Valve
Flow Control Valve
Reboiler
CS bundle
SS bundle
Reflux Condenser
CS tubes / header
SS tubes / header
Vessels / Shells
No corrosion allowance
1/8” CA
LOW SPEC vs HIGH SPEC EQUIPMENT
LOW SPEC
Piping & Valves CS • Contactor LCV to Still Column • Still Column to Condenser • Reflux Vessel to Reflux Pumps to Still Column • Top 8 tray section of Still Column
HIGH SPEC
SS – Contactor LCV to Still Column
ACID GAS HANDLING
Acid Gas Handling •
Incineration
• • • • •
Flare Incinerator / Thermal Oxidizer with Waste Heat Recovery Unit Regenerative Thermal Oxidizer
Sulfur Recovery Plant Reinjection or Disposal
• •
Compression Pumping
AMINE WORKBOOK
ACID GAS HANDLING with MEMBRANES
MEMBRANES – How They Work • • •
Bulk Removal of CO2 and H2S These comments apply to Cellulose Acetate based membrane materials (Cynara and their usual competitors) Works on DIFFERENCE in Partial Pressures on FEED and PERMEATE sides of the membranes
• • •
Suppose Feed = 500 PSIA and 50% CO2. This = 250 PSIA Partial Pressure of CO2 Suppose PERMEATE = 50 PSIA. Assuming high CO2%, CO2 partial pressure on Permeate side may be about 45 PSIA The difference between 250 PSIA and 45 PSIA of CO2 partial pressure drives the CO2 across the membranes.
MEMBRANES • • • • • • • •
Typical CO2 membranes are applied with CO2 in Feed =15% and above They work better at higher CO2% and higher Pressure in Feed Gas Typically limited to about 400 PSIA CO2 Partial Pressure in feed Typically limited to about 750 PSI differential pressure (Feed-Perm) Typically limited to about 1200 PSI feed pressure. 700 PSI more common Usually applied in moderate feed temperatures of +30 to +120 Deg F Lower Feed Partial Pressures result in lower CO2% in Permeate Gas. This can result in HC loss to permeate gas. Membranes can be staged to reduce this HC loss, but needs more compression
MEMBRANES
• • •
Membranes applied in EOR projects usually have high CO2 Feed content. 35% to >90% is typical. In this application, it is common to have about 10% CO2 in final outlet HC gas. Downstream DPC/NGL plants have Amine systems for the remaining10% CO2 in their feed. Common for EOR membrane plants to have permeate gas at 100 PSIA up to over 200 PSIA and to be 96%+ CO2 content. This usually needs compression to some high reinjection pressure (1500# or more).
MEMBRANES • • • • • • •
Membranes applied in pipeline sales gas applications are typically less than 10% CO2 feed. Outlet HC gas meet P/L Specs, usually CO2% = 2 to 3% Note that 10% down to 2% is still a “bulk” removal. Permeate Gas is lower CO2 content than EOR; typically 35 to 65% CO2. Frequently this gas is compressed and permeated again to purify flared permeate gas and recovers HC’s (mostly methane) for lease fuel. Usually NOT applied to meet an H2S spec. Usually NOT applied to make a water content spec.
MEMBRANES • • •
Membranes need significant pretreatment to protect membranes for long service life. With proper pretreatment and operations, membranes can have up to a ten-year service life but 3 to 6 years is more common service life. Contaminants which may be harmful are:
• • • •
Liquid Water (water VAPOR is OK) Some heavy HC’s (benzene family in particular) Paraffin in solid form Dirt, scale, etc.
MEMBRANES •
OPERATING conditions which may be harmful
• • • • • • •
Condensing liquid water (can happen on permeate side, too) Solid sulfur dropout in permeate side (possible if oxygen in feed) Too Cold with too high feed CO2 partial pressures (softens membrane material) Too Hot or high feed-to-perm dP (hastens membrane decline in capacity) Reverse pressure on permeate side (shut down & control issues cause this) Heavy HC’s in feed gas (inadequate P/T) Note that C5 and lighter condensate is generally not a problem for hollow fiber form. Spiral-wound form (ex. - Grace) has issues disengaging the condensates.
MEMBRANES
•
Typical Pretreatment Applied:
• • • •
Inlet Filter/Sep Dehydrate to insure no liquid water and to allow carbon steel materials (dry desiccant dehydration is common in large plants) Dew Point to reduce C5+ to about 25-35 Deg F at feed pressure Reheat to about 70 to 100 Deg F
MEMBRANES •
WHERE DOES ENERFLEX FIT INTO THESE PROJECTS?
• •
•
COMPRESSION on inlet gas, permeate products, inter-stage of membranes, final HC products. (i.e. – for K-M at SACROC, Whiting, etc.) Membranes almost always need compression. PRETREATMENT equipment. We can package all of it. (Typically an engineering firm designs this. Cameron/NATCO/Cynara tries to furnish this themselves. Other membrane companies will claim less pretreatment needed than for Cynara – with dubious results! When pretreatment is for other than Cynara membranes we would have a better chance at packaging the P/T.) DOWNSTREAM processing for NGL/DPC, Amines, dry Dehys, cold gas plants
BACKUP SLIDES
