📑 Table of Contents (Tap to view sections)
Executive Summary & Engineering Scope
Raw natural gas extracted from reservoir formations is rarely fit for pipeline transmission or cryogenic liquefaction. It routinely contains acidic contaminants—principally carbon dioxide ($\text{CO}_2$) and hydrogen sulfide ($\text{H}_2\text{S}$)—along with trace sulfur species (mercaptans $\text{R-SH}$, carbonyl sulfide $\text{COS}$, and carbon disulfide $\text{CS}_2$).
Raw Wellhead Gas ---> [ Acid Gas Removal Unit (AGRU) ] ---> Sweet Gas to Dehydration & Sales
|
v
Acid Gas Overhead (H2S, CO2) ---> To Claus SRU or AGI
Leaving acid gases unmitigated induces severe operational failures: 1. Corrosive Degradation: Free water plus $\text{CO}_2$ forms carbonic acid ($\text{H}_2\text{CO}_3$), causing rapid sweet corrosion and pitting in carbon steel pipelines. Free water plus $\text{H}_2\text{S}$ triggers sour corrosion, hydrogen-induced cracking (HIC), and sulfide stress corrosion cracking (SSCC) per NACE MR0175 / ISO 15156. 2. Cryogenic Freeze-Out: In liquefied natural gas (LNG) cold boxes operating down to $-162\text{ }^\circ\text{C}$, $\text{CO}_2$ precipitates as solid dry ice at concentrations above $50\text{ ppmv}$, plugging brazed aluminum plate-fin heat exchangers (BAHX). 3. Calorific & Pipeline Tariff Non-Compliance: $\text{CO}_2$ acts as an inert diluent that depresses the gross heating value (GHV) and Wobbe Index. Pipeline tariffs mandate $\le 2.0\text{--}3.0\text{ mol}\% \text{ CO}_2$ and $\le 4\text{ ppmv H}_2\text{S}$ ($0.25\text{ grains}/100\text{ SCF}$).
Choosing the wrong Acid Gas Removal Unit (AGRU) technology can inflate plant capital expenditure by tens of millions of dollars, double parasitic plant steam demand, or cause continuous hydrocarbon losses into the acid gas flare. This guide provides a rigorous multi-criteria decision framework to evaluate Chemical Amine Solvents, Physical Solvents, Hybrid Solvents, Polymeric Membranes, and Cryogenic Fractionation.
1. Executive Screening Matrix & Rapid Selection Flowchart
The optimal sweetening technology is primarily dictated by two fundamental thermodynamic variables: 1. Total Inlet System Pressure ($P$, $\text{bar}$ or $\text{psia}$) 2. Acid Gas Partial Pressure ($P_{\text{acid}} = P \times y_{\text{acid}}$, $\text{bar}$ or $\text{psia}$)
[ RAW SOUR GAS FEED ]
│
Is Acid Gas Partial Pressure P_acid > 3.5 bar (50 psia)?
┌───────┴───────┐
YES NO
│ │
Are Heavy Hydrocarbons (C3+) Low? │
┌──────────────┴──────────────┐│
YES NO
│ │
[ PHYSICAL SOLVENT ] [ CHEMICAL AMINE ]
(Selexol, Rectisol) (MDEA, aMDEA, DGA, MEA)
- Flash regeneration - Thermal reboiler regeneration
- Zero reboiler steam - Negligible heavy HC loss
- Low thermal duty - Treats down to < 4 ppm H2S
│ │
Is CO2 > 15% & footprint tight? │
(e.g., offshore FPSO / debottlenecking) │
└──────────────┬───────────────┘
│
┌───────────────┴───────────────┐
│ │
Does gas feed require Is inlet CO2 > 30% with
deep H2S removal (< 4 ppm)? bulk removal target only?
│ │
YES YES
│ │
[ SOLVENT HYBRID or AMINE ] [ POLYMERIC MEMBRANE ]
(aMDEA / Sulfinol) (Cellulose Acetate / Polyimide)
- Bulk CO2 roughing unit
- Membrane + Amine polishing
The Multi-Criteria Decision Matrix
| Dimension / Technology | Chemical Amine (Formulated aMDEA) | Primary/Secondary Amine (MEA / DEA) | Physical Solvent (Selexol / DEPG) | Cold Physical Solvent (Rectisol - MeOH) | Polymeric Membrane (Polyimide) | Cryogenic Distillation (Ryan-Holmes) |
|---|---|---|---|---|---|---|
| Optimal Feed Pressure | $15\text{--}100\text{ barg}$ | $10\text{--}70\text{ barg}$ | $35\text{--}120\text{ barg}$ | $30\text{--}90\text{ barg}$ | $30\text{--}100\text{ barg}$ | $40\text{--}80\text{ barg}$ |
| Acid Gas Partial Pressure | Low to Moderate ($< 5\text{ bar}$) | Very Low ($< 1.5\text{ bar}$) | High ($> 3.5\text{--}5.0\text{ bar}$) | High ($> 4.0\text{ bar}$) | High ($> 4.0\text{ bar}$) | Ultra-High ($> 10\text{ bar}$) |
| Achievable $\text{H}_2\text{S}$ Purity | $< 4\text{ ppmv}$ | $< 1\text{ ppmv}$ | $1\text{--}4\text{ ppmv}$ | $< 0.1\text{ ppmv}$ | $10\text{--}50\text{ ppmv}$ (poor) | $< 4\text{ ppmv}$ |
| Achievable $\text{CO}_2$ Purity | $< 50\text{ ppmv}$ (LNG spec) | $< 100\text{ ppmv}$ | $100\text{--}500\text{ ppmv}$ | $< 1\text{ ppmv}$ (Syngas) | $2.0\text{--}3.0\text{ mol}\%$ (Bulk) | $< 1.0\text{ mol}\%$ |
| Hydrocarbon Co-Absorption | Very Low ($< 0.5\%$) | Very Low ($< 0.2\%$) | Moderate to High (C3+ loss) | High (requires stripper) | Moderate (permeate slip) | None (liquids recovered) |
| Regeneration Energy Method | Thermal Reboiler (Steam) | High Thermal Reboiler | Pressure Flash (Pumps only) | Thermal + Refrigeration | None (Pressure driven) | Distillation Reboilers |
| Parasitic Thermal Duty | $3.0\text{--}4.5\text{ MJ/kg acid gas}$ | $5.5\text{--}7.5\text{ MJ/kg}$ | $\approx 0\text{ (Thermal reboiler free)}$ | $2.0\text{--}3.5\text{ MJ/kg}$ | Zero thermal | High reboiler duties |
| Relative Plant CAPEX | $1.0\times$ (Baseline) | $1.15\times$ (Corrosion alloy) | $1.25\times\text{--}1.40\times$ | $1.80\times\text{--}2.20\times$ | $0.65\times\text{--}0.85\times$ (No steam) | $1.75\times\text{--}2.10\times$ |
| Turndown Flexibility | Excellent ($30\%\text{--}110\%$) | Moderate ($50\%\text{--}100\%$) | Good ($40\%\text{--}100\%$) | Fair ($60\%\text{--}100\%$) | Outstanding ($10\%\text{--}100\%$) | Poor ($70\%\text{--}100\%$) |
| Footprint / Weight Ratio | Moderate | Moderate | High (large flash vessels) | Very Large (chillers + columns) | Ultra-Compact (Skid) | Large (fractionation train) |
2. Contaminant & Operating Boundary Envelopes
2.1 The Acid Gas Partial Pressure Rule
The fundamental equilibrium governing physical versus chemical absorption is described by Henry's Law vs. Chemical Equilibrium:
Solvent Acid Gas Loading (mol acid gas / mol solvent)
^
| / (Physical Solvents: Loading increases
| / linearly with Partial Pressure - Henry's Law)
| /
| ......----------/ <- Economic Crossover Point (3.5 - 5.0 bar)
| .----'
| / (Chemical Amines: Steep loading at low partial pressure,
|/ plateaus at stoichiometric chemical saturation)
+----------------------------------------------------> Acid Gas Partial Pressure (bar)
0 2 4 6
- At Low Acid Gas Partial Pressure ($P_{\text{acid}} < 2.0\text{ bar}$): Chemical amines (MDEA, DGA, MEA) dominate. The chemical reaction between the basic nitrogen group and the weak acid forms ionic salts, driving gas concentrations down to parts-per-million levels regardless of low total pressure.
- At High Acid Gas Partial Pressure ($P_{\text{acid}} > 4.0\text{ bar}$): Physical solvents (Selexol, Rectisol, Purisol) become far more economical. Because physical loading is directly proportional to partial pressure, high inlet pressure allows enormous volumes of $\text{CO}_2$ and $\text{H}_2\text{S}$ to dissolve into the solvent without requiring stoichiometric chemical reagent quantities.
2.2 Secondary Contaminant Interference
- Heavy Hydrocarbons ($\text{C}_3\text{--}\text{C}_7^+$): Physical solvents exhibit high solubility for aliphatic and aromatic hydrocarbons. If the raw gas is rich in pentanes, hexanes, or BTX, physical solvents absorb them co-currently, causing two critical failures:
- Loss of valuable liquid condensates into the low-pressure acid gas.
- Severe contamination of the Claus Sulfur Recovery Unit (SRU) feed, leading to catalyst coking and black sulfur.
- Carbonyl Sulfide ($\text{COS}$) and Carbon Disulfide ($\text{CS}_2$): Primary amines (MEA) react irreversibly with $\text{COS}$ and $\text{CS}_2$, causing permanent solvent degradation. Secondary amines (DEA) and tertiary amines (MDEA) do not degrade, but unpromoted MDEA cannot remove $\text{COS}$. Physical solvents (Selexol) and hybrid solvents (Sulfinol) remove $\text{COS}$ and mercaptans smoothly.
- Oxygen ($\text{O}_2$) Ingress: Common in landfill gas, coal bed methane (CBM), or vapor recovery headers. Oxygen oxidizes amines into heat-stable salts (HSS) and corrosive organic acids (formic, glycolic, oxalic), requiring caustic neutralization and thermal reclaiming.
3. Deep-Dive Process Technology Descriptions
3.1 Chemical Solvents (Akanolamines)
Chemical absorption relies on an acid-base neutralization reaction in an absorber column ($20\text{--}30$ valve/sieve trays or structured packing), followed by thermal stripping in a regenerator column using low-pressure steam ($3.0\text{--}4.5\text{ barg}$):
Rich Sour Gas ──> [ Absorber Column (30-80 bar) ] ──> Sweet Treated Gas
│ (Rich Amine)
v
[ Lean/Rich Heat Exchanger ]
│
v
[ Stripper Column (1.5-2 bar) ] <── [ Steam Reboiler (120-130°C) ]
│ (Lean Amine)
v
(Acid Gas Overhead to Claus Unit)
The Principal Commercial Amines:
- Monoethanolamine (MEA) - Primary Amine ($15\text{--}20\text{ wt}\%$):
- Reaction: Forms stable carbamate: $2\text{ RNH}_2 + \text{CO}_2 \rightleftharpoons \text{RNH}_3^+ + \text{RNHCOO}^-$.
- Pros: Very fast reaction kinetics; strips $\text{H}_2\text{S}$ and $\text{CO}_2$ down to trace levels at low contact pressures.
- Cons: Highest reboiler heat duty ($1,900\text{--}2,200\text{ kJ/kg solution}$); highly corrosive; limited to $0.35\text{--}0.40\text{ mol acid gas/mol amine}$ loading; degrades irreversibly with $\text{COS/CS}_2$.
- Diethanolamine (DEA) - Secondary Amine ($25\text{--}35\text{ wt}\%$):
- Pros: Lower corrosion rate than MEA; higher allowable loading ($0.45\text{--}0.50\text{ mol/mol}$); lower heat of reaction.
- Cons: Slower kinetics than MEA; cannot selectively remove $\text{H}_2\text{S}$ in the presence of $\text{CO}_2$.
- Methyldiethanolamine (MDEA) - Tertiary Amine ($40\text{--}50\text{ wt}\%$):
- Reaction: Cannot form a carbamate because it lacks an active hydrogen on the nitrogen atom. Must react through the slow bicarbonate pathway: Meanwhile, proton transfer with $\text{H}_2\text{S}$ is instantaneous:
- Selective Advantage: Allows $\text{CO}_2$ to slip through while capturing $\text{H}_2\text{S}$ to meet the $4\text{ ppmv}$ pipeline specification. This enriches the acid gas feeding the Claus SRU and slashes reboiler steam requirements by $40\text{--}60\%$!
- Formulated Activated MDEA (aMDEA / Piperazine Promoted):
- Incorporates an activator like Piperazine ($3\text{--}8\text{ wt}\%$) to accelerate $\text{CO}_2$ transfer. It is the undisputed industry gold standard for LNG feed pre-treatment, reliably meeting $< 50\text{ ppmv CO}_2$ and $< 4\text{ ppmv H}_2\text{S}$ at lowest energy consumption.
- Diglycolamine (DGA) ($50\text{--}65\text{ wt}\%$):
- High solvent strength allows high acid gas loading ($0.50\text{ mol/mol}$) in harsh, freezing Arctic climates due to low freezing points.
3.2 Physical Solvents
Physical solvents do not react chemically with acid gases; they dissolve them according to Henry's Law:
Solubility increases dramatically with decreasing temperature and increasing partial pressure.
The Principal Commercial Physical Solvents:
- Selexol (Dimethyl Ethers of Polyethylene Glycol - DEPG):
- Operating Window: Near-ambient temperatures ($-5\text{ }^\circ\text{C}$ to $+40\text{ }^\circ\text{C}$) at pressures $> 35\text{ barg}$.
- Regeneration Mechanism: Simply flashing solvent pressure down across successive flash drums (HP flash $\to$ MP flash $\to$ Vacuum stripper). Zero steam reboiler is required for bulk $\text{CO}_2$ removal!
- Selectivity: $\text{H}_2\text{S}$ is $9\times$ more soluble in Selexol than $\text{CO}_2$, enabling two-stage absorption: Stage 1 selectively captures $\text{H}_2\text{S}$ for the Claus unit, while Stage 2 captures bulk $\text{CO}_2$.
- Rectisol (Chilled Methanol at $-30\text{ }^\circ\text{C}$ to $-60\text{ }^\circ\text{C}$):
- Highly complex process licensed by Linde and Lurgi. Commonly used in coal/petcoke gasification synthesis gas.
- Can achieve extreme purities ($< 0.1\text{ ppmv total sulfur}$, $< 1\text{ ppmv CO}_2$). Requires expensive refrigeration systems and multi-column cryogenic metallurgy.
- Purisol (N-Methyl-2-Pyrrolidone - NMP):
- Excellent for high $\text{H}_2\text{S}/\text{CO}_2$ selectivity at moderate ambient temperatures.
3.3 Hybrid Solvents (Sulfinol)
Hybrid formulations combine the high loading capacity of physical solvents at elevated pressure with the deep sweetening capability of chemical amines at low partial pressures.
- Sulfinol-D: $40\text{ wt}\%$ Diisopropanolamine (DIPA) + $40\text{ wt}\%$ Sulfolane + $20\text{ wt}\%$ Water.
- Sulfinol-M: Formulated MDEA + Sulfolane + Water.
- Key Advantages:
- Achieves $< 4\text{ ppmv H}_2\text{S}$ and $< 50\text{ ppmv CO}_2$.
- Simultaneously removes organic sulfur ($\text{COS}$, mercaptans, and $\text{CS}_2$) which slip through pure aqueous MDEA.
- Resists foaming much better than pure chemical amines.
3.4 Polymeric Membrane Separation
Membranes separate acid gases via selective molecular permeation across non-porous polymeric hollow fibers (Cellulose Acetate or Polyimide):
High Pressure Feed Gas
[CO2, H2S, CH4] ──────> [ Hollow Fiber Membrane Module ] ───> Non-Permeate Sales Gas (Retentate)
│ (CH4 rich, High Pressure)
v
Permeate Stream (Low Pressure)
(Enriched in CO2, H2S, and lost CH4)
- Permeation Selectivity: $\text{CO}_2$ and $\text{H}_2\text{S}$ permeate through the polymer matrix $20\text{--}40\times$ faster than methane ($\text{CH}_4$).
- Best Application (Bulk Roughing): When raw gas contains $15\text{--}70\text{ mol}\% \text{ CO}_2$, membranes can strip $\text{CO}_2$ down to $5\text{--}10\text{ mol}\%$ with zero steam, zero chemicals, and a fraction of the weight of an amine plant.
- Membrane-Amine Hybrid Configurations: Offshore platforms and high-$\text{CO}_2$ fields frequently install a membrane roughing unit to reject $80\%$ of the bulk $\text{CO}_2$, followed by a compact amine polishing column to meet final pipeline specs ($2\%\text{ CO}_2$).
4. Utility, Consumables & Parasitic Power Intensities
Energy consumption represents over $70\%$ of the lifetime operating cost of an acid gas removal facility.
Specific Thermal Energy Consumption (MJ / kg acid gas removed)
^
8 | [ MEA: 6.5 - 7.5 MJ/kg ]
7 |
6 | [ DEA: 5.0 - 6.0 MJ/kg ]
5 |
4 | [ aMDEA: 3.2 - 4.2 MJ/kg ]
3 |
2 | [ Selexol: 0.5 - 1.2 MJ/kg (Thermal reboiler-free) ]
1 |
0 +------------------------------------------------------------> Technology
Energy & Consumable Comparison Table
| Parameter / Consumption Metric | MEA ($20\%$) | DEA ($30\%$) | aMDEA ($45\%$) | Selexol (Physical) | Membrane (Single-Stage) |
|---|---|---|---|---|---|
| Reboiler Heat Duty | $6.5\text{--}7.5\text{ MJ/kg}$ | $5.0\text{--}6.0\text{ MJ/kg}$ | $\mathbf{3.2\text{--}4.2\text{ MJ/kg}}$ | $\approx 0\text{ MJ/kg}$ | $\mathbf{0\text{ MJ/kg}}$ |
| Cooling Water Duty | Very High | High | Moderate | High (Chilling) | Negligible |
| Circulation Pumping Power | High ($0.35\text{ mol/mol}$) | Moderate ($0.45\text{ mol/mol}$) | Low ($\mathbf{0.65\text{ mol/mol}}$) | Moderate to High | Zero pumping |
| Hydrocarbon Methane Loss | $< 0.1\%$ | $< 0.1\%$ | $< 0.2\%$ | $1.5\text{--}3.0\%$ | $\mathbf{3.0\text{--}8.0\%}$ |
| Solvent Make-up / Replacement | High ($1.0\text{--}1.5\text{ kg/MMSCF}$) | Moderate ($0.5\text{ kg/MMSCF}$) | Low ($\mathbf{0.15\text{ kg/MMSCF}}$) | Very Low ($< 0.05\text{ kg}$) | Sorbent/Element 3–5 yr life |
5. CAPEX vs. OPEX Lifecycle Cost Modeling
To model the Levelized Cost of Treating ($\text{LCOT}$, $\$ / \text{MSCF}$ feed gas):
where $\text{CRF} = \frac{i(1+i)^n}{(1+i)^n - 1}$ is the capital recovery factor.
Levelized Cost of Treating ($/MSCF)
^
| / (Membranes: Low CAPEX, but hydrocarbon slip penalizes at high gas price)
| /
| / / (MEA/DEA: High Steam Opex penalizes economics)
| / /
| / / (aMDEA: Optimal balance of moderate CAPEX and low OPEX)
| / /.......----------------------------------------
| /
+----------------------------------------------------> Gas Feed Richness & Value ($/MMBtu)
- For Remote / Offshore Low-Footprint Applications: Membranes offer the lowest initial capital cost ($-35\%$ vs amine) and eliminate steam boilers, but methane loss to the permeate stream must be utilized as fuel gas or recompressed.
- For High-Volume Midstream Gas Plants ($> 100\text{ MMSCFD}$): Formulated aMDEA consistently delivers the lowest lifecycle levelized cost due to minimal hydrocarbon losses ($< 0.2\%$), low reboiler energy, and high solvent stability.
6. Operability, Turndown & Reliability Dynamics
6.1 Foaming Phenomena & Antifoam Management
Amine foaming is the single most frequent cause of unplanned sweetening plant outages: * Mechanisms: Hydrocarbon condensation inside the absorber, accumulation of finely divided iron sulfide ($\text{FeS}$) particles, amine degradation products, or upstream well treating surfactants. * Mitigations: Maintain lean amine temperature $5\text{ }^\circ\text{C}$ hotter than the inlet gas dew point to prevent hydrocarbon condensation. Install continuous $10\ \mu\text{m}$ mechanical cartridge filtration and $10\text{--}20\%$ side-stream activated carbon bed adsorption.
6.2 Corrosion Control & Metallurgy
- Rich Amine Lines: High velocities ($> 1.8\text{ m/s}$) strip the protective iron carbonate ($\text{FeCO}_3$) layer, causing severe erosion-corrosion. Piping must be upgraded to 316L Stainless Steel or Duplex Stainless Steel wherever acid gas loading exceeds $0.40\text{ mol/mol}$.
- Reboiler Bundles: Boiling rich amine releases hot corrosive $\text{CO}_2$ gas bubbles. Reboiler tube bundles should be specified in SS 316L or Alloy 825.
7. Environmental Footprint & Decarbonization Mandates
7.1 Emissions Regulations & BTX Routing
- Benzene, Toluene, Ethylbenzene, Xylene (BTX): Amine solvents (and particularly physical solvents) co-absorb BTX from the gas stream. When the solvent is regenerated, BTX flashes off into the acid gas overhead. If this stream feeds a Claus SRU, BTX fouls catalysts and discolors sulfur. If vented or burned, it creates hazardous air pollutant (HAP) violations.
- Carbon Capture and Storage (CCS) Readiness: Modern decarbonization mandates favor aMDEA and physical solvents because they generate a high-purity $\text{CO}_2$ stream ($> 98\text{ mol}\% \text{ CO}_2$ dry basis) from the regenerator, ideal for pipeline dehydration and deep geological sequestration without secondary purification.
8. Real-World Selection Case Study
Field Scenario: Deep Sour Gas Processing Facility
An operating company is designing a greenfield Central Gas Plant to process $150.0\text{ MMSCFD}$ ($177,000\text{ Nm}^3/\text{h}$) of rich sour gas.
Stream Parameters:
- Inlet Pressure ($P$): $65.0\text{ barg}$ ($957\text{ psia}$)
- Inlet Temperature ($T$): $35.0\text{ }^\circ\text{C}$ ($95\text{ }^\circ\text{F}$)
- Inlet $\text{CO}_2$: $8.5\text{ mol}\%$ (Partial Pressure $= 5.61\text{ bar} = 81.4\text{ psia}$)
- Inlet $\text{H}_2\text{S}$: $1.2\text{ mol}\%$ ($12,000\text{ ppmv}$, Partial Pressure $= 0.79\text{ bar}$)
- Heavy Hydrocarbons ($\text{C}_5^+$): $2.1\text{ mol}\%$ (Rich gas with high BTX)
- Target Sales Specifications: $\le 2.0\text{ mol}\% \text{ CO}_2$, $\le 4\text{ ppmv H}_2\text{S}$
Evaluation of Candidate Technologies:
[Candidate 1: Physical Solvent (Selexol)]
- Partial pressure (P_acid = 6.4 bar) is favorable for physical absorption.
- FATAL FLAW: Rich hydrocarbon gas contains 2.1% C5+ and heavy BTX.
- Selexol would co-absorb over 45% of the C5+ hydrocarbons and 80% of the BTX,
stripping valuable condensate and poisoning the downstream Claus SRU.
-> VERDICT: REJECTED due to heavy hydrocarbon co-absorption.
[Candidate 2: Single-Stage Polymeric Membrane]
- High feed pressure (65 barg) is suitable.
- FATAL FLAW: Membrane selectivity for H2S over CH4 is low (~15-20).
- While CO2 is removed, permeate retains significant H2S, and residue gas
cannot reliably achieve <= 4 ppmv H2S without severe methane slip (> 6%).
-> VERDICT: REJECTED as standalone unit.
[Candidate 3: Primary Amine (MEA)]
- Can achieve specs easily.
- FATAL FLAW: Massive acid gas throughput (14.5 MMSCFD acid gas) would require
an astronomical reboiler heat duty (> 45 MW thermal) and severe corrosion risks.
-> VERDICT: REJECTED due to excessive OPEX.
[Candidate 4: Formulated aMDEA (MDEA + Piperazine Promoter)]
- High solvent loading (0.55 mol acid gas / mol amine).
- Excellent H2S and CO2 simultaneous removal to <= 4 ppmv H2S and <= 1.5% CO2.
- Negligible heavy hydrocarbon co-absorption (< 0.2%).
- Reboiler heat duty minimized to ~22.5 MW (50% less than MEA).
-> VERDICT: SELECTED AS OPTIMAL TECHNOLOGY.
Final Process Design Architecture
The selected design utilizes an aMDEA sweetening unit ($45\text{ wt}\%$ MDEA, $5\text{ wt}\%$ Piperazine) operating at $65\text{ barg}$ with a structured packing contactor column, a stainless steel flash drum operating at $5.5\text{ barg}$ to disengage trace entrained methane, and a steam-stripped regenerator operating at $1.8\text{ barg}$. The acid gas overhead ($87.6\%\text{ CO}_2$, $12.4\%\text{ H}_2\text{S}$) routes to a Claus SRU with Tail Gas Treating.
9. Interactive Sizing & Simulation Callouts
To design and verify your acid gas treating system using ChemProCal's active engineering engines: * Size your amine circulation rate and reboiler duty: Use the Amine Gas Sweetening & AGRU Sizer. * Verify LNG cryogenic solubility margins: Screen for dry ice freezeout with the LNG Feed Gas Readiness Screener. * Size the downstream sulfur plant: Balance furnace air and catalyst beds with the Claus Sulfur Recovery Screener. * Model two-phase hydrocarbon dew point: Check phase envelopes with the Natural Gas Mixture Phase Envelope Explorer.
Amine Gas Sweetening & Acid Gas Removal Unit Sizer
Apply this methodology directly in the ChemProCal calculator.
Open Calculator →References
- GPSA Engineering Data Book, Section 21: Acid Gas Treating (14th Edition, Gas Processors Suppliers Association) - Standard [Link ↗]
- Kohl, A.L. and Nielsen, R.B. - Gas Purification (5th Edition, Gulf Publishing Company, Houston, TX,) - Book
- Kidnay, A.J., Parrish, W.R., McCartney, D.G. - Fundamentals of Natural Gas Processing (3rd Edition, CRC Press, 2019) - Book
- Maddox, R.N. and Morgan, D.J. - Gas Conditioning and Processing, Vol. 4: Gas Treating and Liquid Sweetening (Campbell Petroleum Series, 1998) - Book [Link ↗]
- ISO 13686: Natural gas - Quality designation (2nd Edition, International Organization for Standa) - Standard [Link ↗]
Apply Methodology in Amine Gas Sweetening & Acid Gas Removal Unit Sizer
Execute complete engineering simulations using the governing mathematical equations from this guide:
Apply the exact mathematical principles from this fundamental directly inside the official Amine Gas Sweetening & Acid Gas Removal Unit Sizer engine.