Natural Gas Sweetening Notes

Overview of Natural Gas Processing

• Natural gas is extracted from underground reservoirs, either as free gas or in association with crude oil.

• It primarily consists of methane ($CH_4$), with lesser amounts of other hydrocarbons (HCs).

• Impurities like hydrogen sulfide (H2S), Nitrogen (N2) and Carbon Dioxide (CO2) are common, along with water vapor.

• Key parameters for designing a gas field processing system:

  1. Estimated gas reserve (associated and free).

  2. Gas flow rate and composition.

  3. Market demand (local and export).

  4. Geographic location and shipping methods.

  5. Environmental factors.

  6. Risks and economics.

• Gas/oil reserve is often the most critical factor.

• Specific processing schemes depend on gas composition, source location, and available markets.

Objectives of Gas Field Processing

• Two main objectives:

  1. Removing impurities from the gas.

  2. Increasing liquid recovery beyond conventional gas processing.

• Under standard conditions for an ideal gas:

  • 1 g mole occupies 22.4 liters.

  • 1 kg mole occupies 22.4 $m^3$.

  • 1 lb mole occupies 359 $ft^3$.

Gas Sweetening Processes

• Natural gas contains impurities such as hydrogen sulfide(H2S), Carbon Dioxide (CO2), water vapour, mercaptans and heavy hydrocarbons, collectively known as "acid gases."

• Gas with H2S and other sulfur compouds is called sour gas. while with only CO2 is called as acid gas.

• Sweetening is crucial because:

  1. Health hazards: $H_2S$ is toxic; can cause breathing problems and death at high concentrations.

  2. Sales contracts: Strict pipeline specifications for sulfur content.

  3. Corrosion problems: CO2, partial pressure above 15 psia requires inhibitors or special metallurgy causes metal embrittlement.

• More than 30 processes exist; the most important are:

  1. Batch solid bed adsorption: Iron sponge, molecular sieve, zinc oxide for complete $H_2S$ removal at low concentrations. Suitable for small sulfur amounts and low gas flow rates.

  2. Reactive solvents: MEA, DEA, DGA, DIPA, hot potassium carbonate, and mixed solvents. Used for large amounts of H2S and CO2 solvents are regenerated.

  3. Physical solvents: Selexol, Rectisol, Purisol, and Fluor solvent. Used to remove $CO_2$ and are regenerated.

  4. Direct oxidation to sulfur: Stretford, Sulferox, LOCAT, and Claus. Eliminate $H_2S$ emissions.

  5. Membranes: Used for very high $CO_2$ concentrations. Examples: AVIR, Air Products, Cynara (Dow), DuPont, Grace, International Permeation, and Monsanto.

Selection of Sweetening Process

• Factors to consider:

  1. Type of impurities.

  2. Inlet and outlet acid gas concentrations.

  3. Gas flow rate, temperature, and pressure.

  4. Feasibility of sulfur recovery.

  5. Acid gas selectivity required.

  6. Presence of heavy aromatics.

  7. Well location.

  8. Environmental considerations.

  9. Relative economics.

Batch Processes

• Primarily remove H2S and CO2 presence is not a factor.

• Typically used for low-sulfur-content feeds.

• Include:

  1. Iron Sponge

  2. Zinc Oxide

  3. Molecular Sieves

Iron Sponge

• Fixed-bed chemical adsorption; widely used batch process.

• Applied to sour gases with low $H_2S$ concentrations (up to 300 ppm) at low to moderate pressures (50-500 psig).

• Does not remove $CO_2$.

• Inlet gas flows through a reactor with hydrated iron oxide and wood chips.

• The basic reaction is the formation of ferric sulfide:
  2Fe2O3 + 6H2S —> 2Fe2S3 + 6H2O (1)

• Requires alkalinity (pH 8-10) with controlled water injection.

• Regeneration by controlled oxidation:
  2Fe2S3 + 3O2 —> 2Fe2O3 + 3S2 (2)

• Sulfur can cake in the bed; slow oxygen introduction oxidizes it:
  S2 + 2O2 —> 2SO2 (3)

• The bed is changed after about 10 cycles due to iron oxide deactivation.

• Continuous operation involves continuously adding small amounts of air/oxygen to oxidize sulfur as it forms, saving labor costs.

Zinc Oxide

• Can be used instead of iron oxide for removing H2S$, COS,$CS2, and mercaptans.

• Better sorbent; exit $H_2S$ can be as low as 1 ppm at around 300°C.

• Reacts with H2S to form water and zinc sulfide: ZnO + H2S —>ZnS + H2O (4)

• Cannot be regenerated on-site.

• Decreasing in use due to regeneration issues and the difficulty of disposing of zinc sulfide (Zn is considered a heavy metal).

Molecular Sieves (MS)

• Crystalline sodium alumino silicates with large surface areas and narrow pore sizes.

• Highly localized polar charges act as adsorption sites for polar materials, even at low concentrations.

• Treated natural gas can achieve very low $H_2S$ concentrations (4 ppm).

• Commercial applications require at least two beds for continuous operation.

• Sulfur compounds are adsorbed on a cool, regenerated bed.

• The saturated bed is regenerated by passing preheated sweetened gas (400-600°F) for about 1.5 hours.

• As the bed temperature increases, adsorbed $H_2S$ is released into the regeneration gas stream.

• The sour effluent gas is flared off, losing about 1-2% of the treated gas.

• An amine unit can be added to recover this loss; $H_2S$ is then flared off from the amine unit's regenerator.

• If flaring is prohibited, $H_2S$ can be sent to a sulfur recovery unit.

Liquid-Phase Processes

• Commonly used for acid gas treatment.

• Chemical solvents (aqueous solutions) react reversibly with H2S and CO2 products are regenerated by temperature or pressure changes.

• Physical solvents selectively remove sulfur compounds and are regenerated at ambient temperature by pressure reduction.

• Combinations of physical and chemical solvents can be used.

Chemical Absorption: Amine Processes

• Aqueous solutions of alkanolamines are widely used for bulk removal of H2S and CO2

• Low operating costs and flexible solvent composition make this process popular.

• A liquid physical solvent can be added to improve selectivity.

• The acid gas is scrubbed to remove water and liquid hydrocarbons, then enters the bottom of an absorption tower (tray or packed).

• Regenerated amine (lean amine) enters at the top, contacting sour gas countercurrently.

• H2S and CO2 are absorbed into the amine phase, and sweet gas exits at the top.

• The exit amine solution (rich amine) is flashed, filtered, and fed to a stripper/regenerator to recover the amine, with acid gases stripped off at the top.

• Refluxed water aids in steam stripping the rich amine solution.

• Regenerated amine is recycled back to the absorption tower.

Amine Types

• Primary amines (MEA, DGA) react strongly but are difficult to recover.

• Secondary amines (DEA, DIPA) have reasonable capacity and are easily recovered.

• Tertiary amines (MDEA) have lower capacity but are more selective for $H_2S$ absorption.

• DEA is the most common due to lower installation and operating costs.

• Amines are compounds formed from ammonia ($NH_3$) by replacing hydrogen atoms with hydrocarbon groups.

  • Primary: one hydrogen replaced.

  • Secondary: two hydrogens replaced.

  • Tertiary: three hydrogens replaced.

• Amines remove H2S and CO2 in two steps:

  1. Gas dissolves in the liquid (physical absorption).

  2. Dissolved gas reacts with weakly basic amines.

• Absorption is governed by the partial pressure of H2S and CO2

• Reactions are controlled by the reactivity of the dissolved species.

• Amines are bases that form salts with weak acids (formed byH2S and CO2).

• The reactions are exothermic.

• $H<em>2S$ reacts rapidly with amine via direct proton transfer: $R</em>1R<em>2R</em>3N + H<em>2S \rightleftharpoons R</em>1R<em>2R</em>3NH^+HS^-$

• $CO_2$ reaction is more complex.

• First mechanism: $CO<em>2$ hydrolyzes to form carbonic acid: $CO</em>2 + H<em>2O \rightleftharpoons H</em>2CO_3$

• Carbonic acid dissociates to bicarbonate:
  $H<em>2CO</em>3 \rightleftharpoons H^+ + HCO_3^-$

• Bicarbonate reacts with amine:
  $H^+ + R<em>1R</em>2R<em>3N \rightleftharpoons R</em>1R<em>2R</em>3NH^+$

• Overall:
  $CO<em>2 + H</em>2O + R<em>1R</em>2R<em>3N \rightleftharpoons R</em>1R<em>2R</em>3NH^+.HCO_3^-$

• Second mechanism: “Carbamate formation reaction” (primary & secondary amines only).
  $CO<em>2 + R</em>1R<em>2NH \rightleftharpoons R</em>1R<em>2N^+HCOO^- \rightleftharpoons R</em>1R<em>2NCOO^- + R</em>1R<em>2NH</em>2^+$

• Overall:
  $CO<em>2 + 2R</em>1R<em>2NH \rightleftharpoons R</em>1R<em>2NH</em>2^+ + R<em>1R</em>2NCOO^-$

• Carbamate formation is faster than hydrolysis but slower than $H_2S$ reaction.

• Tertiary amines cannot form carbamate, so they react with $CO_2$ via the slow hydrolysis mechanism.

• For stericly hindered amines the $H_2S$ reaction aren't significantly affected due to proton size however the carbamate formation will only allow the slow bicarbonate formtion reaction.

• High prssures and low pressure drive the reaction to the right, whereas for opposite conditions they favout the reverse reaction. this is the mechansim for regeneration of Amine solution.

Operating Issues of Amine Process

• Corrosion: Affected by amine concentration, oxygen concentration, and heat stable salts (HSS).

• Heat Stable Salt (HSS): Amines react with $CO_2$ and contaminants to form organic acids, which react with amines to form HSS.

• Solution Foaming: Results in poor vapor-liquid contact. Causes include suspended solids, liquid hydrocarbons, surface-active agents, and amine degradation products.

• Foaming is treated with antifoams.

• Batch vs. Amine Process

• Amines are preferred when lower operating costs justify higher equipment costs.

• Key factor is sulfur content: below 20 lb/day, batch processes are more economical; above 100 lb/day, amine processes are preferred.

Determination of Sulfur Content

$\frac{lb \ S}{day} = \frac{Gas \ Flowrate \ in \ scf}{day} \times \frac{lb \ mol \ gas}{379.49 \ ft^3} \times \frac{mol \ H<em>2S }{mol \ gas} \times \frac{lb \ S}{mol \ H</em>2S}$

*1 lb-mol of gas contains 379.49 ft of gas
*Can be translated directly from ppm or percent
*MW of S = 32

*Example:Which sweetening process (batch or amine) is suitable for the following gas stream?
$Q= 1000 Mscfd; H_2S \ concentration = 200 \ ppm.$
$\frac{lb \ S}{day} = \frac{1 \times 10^6}{day} \times \frac{1}{379.49} \times \frac{200}{1 \times 10^6} \times \frac{32}{1} = 17.0$
Less than 20 lb S/day. So, batch process is suitable

Chemical Absorption: Potassium Carbonate Process

• Hot potassium carbonate ($K<em>2CO</em>3$) removes both $CO<em>2$ and $H</em>2S$.

• Also removes COS and $CS_2$.*

• Works best when $CO_2$ partial pressure is 30-90 psi.

• Reactions:
  $K<em>2CO</em>3 + CO<em>2 + H</em>2O \rightleftharpoons 2KHCO<em>3$ (5) $K</em>2CO<em>3 + H</em>2S \rightleftharpoons KHS + KHCO_3$ (6)

• High partial pressure of $CO<em>2$ is needed to keep $KHCO</em>3$ in solution.

• This process cannot achieve low concentrations of acid gases, so a polishing process (molecular sieve) is needed.

• An elevated temperature ensures that potassium carbonate and reaction products remain in solution.

• This process cannot be used for gases containing $H_2S$ only.

• The hot carbonate process operates both absorber and regenerator at elevated temperatures (230-240 °F).

• Sour gas flows countercurrently to the carbonate liquid stream in the absorber.

• Sweet gas exits at the top.

• Rich carbonate solution is flashed in the stripper (245 °F and atmospheric pressure), where acid gases are driven off.

• Lean carbonate solution is pumped back to the absorber.

3: Physical Solvent Processes

• Organic liquids absorb $H<em>2S$ preferentially over $CO</em>2$ at high pressure and low temperatures.

• Regeneration is carried out by releasing the pressure to the atmosphere and sometimes in vacuum with no heat.

• At high pressure, acid gases will dissolve in solvents, and as the pressure is released, the solvent can be regenerated.

• Properties of important solvents are:

Direct Conversion Processes

• Convert $H_2S$ to sulfur; discussion limited to processes applied to natural gas.

• $H_2S$ is absorbed in an alkaline solution containing an oxidizing agent, which converts it to sulfur.

• The solution is regenerated by air in a flotation cell (oxidizer).

• Processes used include:

  1. Stretford Process.

  2. LOCAT Process.

  3. Sulferox Process.

Stretford Process

• Absorbing solution is dilute $Na<em>2CO</em>3$, $NaVO_3$, and anthraquinone disulfonic acid (ADA).

• Reactions occur in four steps:
  $H<em>2S + Na</em>2CO<em>3 \rightarrow NaHS + NaHCO</em>3$ (1)
  $4NaVO<em>3 + 2NaHS + H</em>2O \rightarrow Na<em>2V</em>4O<em>9 + NaOH + 2S$ (2) $Na</em>2V<em>4O</em>9 + 2NaOH + H<em>2O +ADA(quinone) \rightarrow 4NaVO</em>3 + 2ADA(hydroquinone)$$(3)$
  $ADA(hydroquinone) + 1/2O_2 \rightarrow ADA(quinone)$

• Sour gas enters the bottom, and sweet gas exits at the top.

• Stretford solution enters at the top, and reaction takes place in the bottom part of the absorber, where $H_2S$ is selectively absorbed.

• The reaction products are fed to the oxidizer, where air is blown to oxidize ADA(hydroquinone) back to ADA(quinone).

• The sulfur froth is skimmed and sent to either a filtration or centrifugation unit.

• If heat is used, molten sulfur is produced; otherwise a filter sulfur cake is obtained.

• The filtrate of these units along with the liquid from the oxidizer are sent back to the absorber.

LOCAT Process

• Uses an extremely dilute solution of iron chelates.

• A small portion of the chelating agent is depleted in some side reactions and is lost with precipitated sulfur.

• Sour gas is contacted with the chelating reagent in the absorber, and $H_2S$ reacts with the dissolved iron to form elemental sulfur.

• The reactions involved are:
  $H_2S + 2Fe^{3+} \rightarrow 2H^+ + S + 2Fe^{2+}$ (1)

• The reduced iron ion is regenerated in the generator by blowing air as:
  $1/2O<em>2 + H</em>2O + 2Fe^{2+} \rightarrow 2(OH)^- + 2Fe^{3+}$ (2)

• The sulfur is removed from the regenerator to centrifugation and melting.

Sulferox Process

• Chelating iron compounds are also at the heart of the sulferox process.

• Sulferox is a redox technology, as is the LOCAT; however, in this case, a concentrated iron solution is used to oxidize $H_2S$ to elemental sulfur.

• Patented organic liquids or chelating agents are used to increase the solubility of iron in the operating solution.

• As a result of high iron concentrations in the solution, the rate of liquid circulation can be kept low and, consequently, the equipment is small.

• As in the LOCAT process, there are two basic reactions; the first takes place in the absorber, as in reaction (1), and the second takes place in the regenerator, as in reaction (2).

• The sour gas enters the contactor, where $H_2S$ is oxidized to give elemental sulfur.

• The treated gas and the Sulferox solution flow to the separator, where sweet gas exits at the top, and the solution is sent to the regenerator where $Fe^{2+}$ is oxidized by air to $Fe^{3+}$ and the solution is regenerated and sent back to the contactor.

• Sulfur settles in the regenerator and is taken from the bottom to filtration, where sulfur cake is produced.

• At the top of the regenerator, spent air is released.

Membrane Separations

• Membranes are thin polymer-based barriers that allow the preferential passage of certain substances over others.

• The membranes consist of an ultra-thin polymer film on top of a thin porous substrate.

• Gas separation through membranes relies on the principle that gases dissolve in and diffuse through the membrane polymers.

• Certain gases will permeate through a membrane at a faster rate than others due to the difference in solubility and diffusion ability of those gases through the membrane.

• The differences in gas permeability rates through the membrane provides the basis for the separation.

• Membranes separate gases by the difference in the rates at which the gases diffuse across the film.

• Fast gases collect in the permeate stream, and slow gases remain in the non-permeate stream.

• The permeation flow rate of any gas is given by:
  $Permeation \ rate = Permeability \ Coefficient \ X Membrane \ Area X Partial \ Pressure \ Across \ Membrane$

• When the difference in the permeation coefficient is large, good separation of the gases can be achieved.

• When the difference is small, separation is difficult and expensive because multiple stages are needed.

Advantages:

• Low capital investment when compared with solvent system.

• Ease of operation: process can run unattended.

• Ease of installation: Units are normally skid mounted

• Simplicity: No moving parts for single-stage units.

• No Chemicals needed

• Good weight and space efficiency

Disadvantages:

• Clean feed: Pre-treatment of the feed to the membrane to remove particulates and liquids is generally required.

• Gas compression: Because pressure difference is the driving force for separation,considerable compression may be required for either or both the residue and permeate streams.

• Generally higher hydrocarbon losses than solvent systems.

SDG 9 and Achieving Net Carbon Zero in Natural Gas Sweetening

Introduction to SDG 9 (Industry, Innovation, and Infrastructure)

Purpose of SDG 9:

• Promote resilient infrastructure, inclusive and sustainable industrialization, and foster innovation.

• Importance in sustainable development, supporting economic growth and human well-being.

Key SDG 9 Objectives Related to the Energy Industry:

• Sustainable Industry: Shift towards eco-friendly processes.

• Resilient Infrastructure: Develop adaptable infrastructure.

• Innovation and Research: Invest in environmentally sustainable technology.

Why SDG 9 Matters for the Energy Sector:

• Industrial sectors like energy production are major emitters.

• Sustainable energy development aligns with SDG 9 goals by reducing environmental impact.

Importance in the Energy Sector:

• Improves natural gas quality, reduces hazards, and protects equipment.

• Supports cleaner energy transition by reducing greenhouse gas emissions compared to coal or oil.

Techniques in Gas Sweetening:

• Amine Gas Treating: Uses amine solution to absorb CO₂ and H₂S.

• Membrane Separation: Uses selective membranes to separate CO₂.

• Adsorption: Solid materials like activated carbon capture impurities.

Challenges to Carbon Neutrality:

• High energy consumption and CO₂ emissions.

• Environmental risks from chemicals.

Challenges in the Natural Gas Sweetening Process

• High Energy Consumption:

• Amine Gas Treating requires substantial heat, increasing energy usage

• Membrane Separation and Adsorption also demand high energy

• Environmental Risks:

• Amine sweetening can release degradation products, risking pollution

• Proper handling of chemicals is critical to avoid contamination.

• CO₂ Emissions:

• Sweetening processes release CO₂, challenging net-zero goals.

Path to Net Carbon Zero in Gas Sweetening

1. Efficiency Improvements:

• Use of low-energy solvents reduces heat requirements,

• Process optimization i.e. heat integration reduces energy use.

1. Carbon Capture and Storage (CCS):

• Captures CO₂ produced during sweetening.

• Stored in geological formations to sequester CO₂ long-term.

1. Renewable Energy Integration:

• Powering facilities with solar or wind energy reduces fossil fuel reliance.

1. Alternative Technologies:

• Hybrid amine-membrane systems lower energy costs and emissions.

Conclusion

• Gas sweetening faces challenges due to emissions and environmental risks.

• Achieving net carbon zero aligns with SDG 9 through sustainable industry.

The Path Forward:

• New technologies and process improvements are crucial for sustainability.

• Integrating renewable energy and CCS can make sweetening carbon-neutral.

Future Outlook:

• Continuous research and development will support stricter emissions goals.

• Partnerships in sustainable tech development are key for industry progress.