Gas Quality Fundamentals

1. Natural Gas Composition

Natural gas is a complex mixture of hydrocarbons and non-hydrocarbon components. The composition varies significantly by reservoir, producing formation, and geographic region. Raw gas from the wellhead typically requires processing to remove contaminants and adjust composition before it meets pipeline tariff specifications.

Typical Components

Component	Formula	Typical Range (mol%)	Category
Methane	CH4	70 – 98	Primary hydrocarbon
Ethane	C2H6	0.5 – 15	NGL component
Propane	C3H8	0.2 – 8	NGL component
Butanes	iC4/nC4	0.1 – 4	NGL component
Pentanes+	C5+	0.05 – 2	NGL / condensate
Carbon dioxide	CO2	0.1 – 30	Acid gas (corrosion)
Hydrogen sulfide	H2S	0 – 30	Acid gas (toxic)
Nitrogen	N2	0.2 – 15	Inert (dilutes HV)
Water vapor	H2O	Saturated	Corrosion, hydrates

Gas Classification by Composition

Dry Gas

< 1 GPM C3+ liquids

Predominantly methane (>95%). Minimal NGL value. Requires treating and dehydration only. Common in Marcellus, Haynesville shales.

Wet Gas / Rich Gas

> 2.5 GPM C3+ liquids

Significant NGL content. Requires cryogenic or mechanical refrigeration processing. Common in Eagle Ford, Permian condensate windows.

Sour Gas

> 4 ppmv H2S

Contains hydrogen sulfide above pipeline spec. Requires amine treating. Common in Permian, West Texas, and many international reservoirs.

Regional variation: Gas composition drives the entire midstream value chain. Permian Basin gas is typically rich and sour (high NGL, high H2S/CO2), requiring comprehensive processing. Appalachian Marcellus gas is dry and sweet, often needing only dehydration. Knowing the expected composition is the first step in facility design and processing economics.

2. Pipeline Tariff Specifications

Pipeline tariffs define the gas quality standards that shippers must meet for acceptance into the pipeline system. These specifications are established by the pipeline operator and filed with FERC (for interstate pipelines) or state regulators. Failure to meet tariff specifications results in rejection, penalties, or price adjustments at the custody transfer point.

Typical US Pipeline Tariff Specifications

Parameter	Typical Limit	Unit	Purpose
Gross Heating Value	950 – 1,100	BTU/scf (dry)	Energy content for billing
H2S	≤ 0.25	gr/100 scf (4 ppmv)	Safety, corrosion
Total sulfur	≤ 5 – 20	gr/100 scf	Downstream process protection
CO2	≤ 2 – 3	mol%	Corrosion, dilution
N2	≤ 3 – 4	mol%	Heating value dilution
Total inerts (CO2 + N2)	≤ 4 – 5	mol%	Combined dilution limit
Water vapor	≤ 7	lb/MMscf	Corrosion, hydrate prevention
Hydrocarbon dewpoint	≤ 15 – 20	°F at 800 psig	Prevent liquid dropout
Oxygen	≤ 0.2 – 1.0	mol%	Combustion safety, corrosion
Temperature	50 – 120	°F	Coating and valve protection

Penalty Mechanisms

Rejection: Gas exceeding any specification limit may be refused by the pipeline, forcing the shipper to curtail production or flare until the quality issue is resolved.
Price adjustment: Some tariffs allow acceptance of off-spec gas with a BTU adjustment or penalty fee deducted from the gas price.
Blending credits: Gas below the minimum heating value may be blended with richer gas to meet spec. Some pipelines allow blending agreements between shippers.
Curtailment: Repeated quality violations can result in flow restriction or contract termination under force majeure provisions.

Commercial impact: Off-spec gas events cost operators $10,000–$100,000 per day in lost revenue and penalties, depending on volume and duration. Every midstream facility should have continuous gas quality monitoring with automated shut-in capability at the custody transfer point to prevent off-spec delivery to the pipeline.

3. Heating Value

Heating value is the most commercially important gas quality parameter because natural gas is bought and sold on an energy basis (MMBtu). The gross (higher) heating value includes the latent heat of water vapor condensation from combustion products, while the net (lower) heating value excludes it.

Heating Value Calculation

Gross Heating Value (GHV) from composition: GHV = Σ (yi × HVi) Where: yi = mole fraction of component i HVi = ideal gross heating value of component i (BTU/scf) Component heating values (ideal, 60°F, 14.696 psia): Methane (CH4): 1,010.0 BTU/scf Ethane (C2H6): 1,769.7 BTU/scf Propane (C3H8): 2,516.1 BTU/scf i-Butane (iC4): 3,251.9 BTU/scf n-Butane (nC4): 3,262.3 BTU/scf i-Pentane (iC5): 4,000.9 BTU/scf n-Pentane (nC5): 4,008.9 BTU/scf Hexanes+ (C6+): 4,755.9 BTU/scf (approx) Non-combustibles (N2, CO2, H2O): 0 BTU/scf Real gas correction: GHV_real = GHV_ideal / Z_mix Where Z_mix = compressibility factor at standard conditions (typically 0.997–1.000 for pipeline-quality gas)

Wobbe Index

Wobbe Index (interchangeability): WI = GHV / √(SG) Where: WI = Wobbe Index (BTU/scf) GHV = gross heating value (BTU/scf) SG = specific gravity (air = 1.0) Typical pipeline gas: GHV = 1,030 BTU/scf, SG = 0.60 WI = 1,030 / √0.60 = 1,330 Acceptable range: 1,280 – 1,400 BTU/scf Significance: The Wobbe Index measures gas interchangeability for burner applications. Gases with the same Wobbe Index produce the same heat input through a given orifice at a given pressure. Pipeline operators use WI to ensure consistent combustion performance for downstream customers.

Heating Value Adjustment Factors

Factor	Effect on GHV	Magnitude
Add 1% ethane	Increases GHV	+7.6 BTU/scf
Add 1% N2	Decreases GHV	−10.1 BTU/scf
Add 1% CO2	Decreases GHV	−10.1 BTU/scf
Add 1% propane	Increases GHV	+15.1 BTU/scf
Water-saturated vs. dry	Decreases GHV	−1 to −2% (depends on P, T)

Billing impact: A 10 BTU/scf difference in heating value on a 100 MMscf/d pipeline represents approximately $10,000–$30,000 per day in revenue difference at typical gas prices. Accurate chromatographic analysis and proper heating value calculation per GPA 2172 are critical for fair custody transfer.

4. Contaminant Limits

Contaminants in natural gas pose safety, corrosion, environmental, and operational risks. Each contaminant has specific pipeline tariff limits and corresponding treating processes required for removal.

Hydrogen Sulfide (H2S)

H2S Specifications and Conversions: Pipeline tariff limit: 0.25 grain/100 scf = 4 ppmv Unit conversions: 1 grain/100 scf = 15.9 ppmv = 22.8 mg/m³ 0.25 grain/100 scf = 4 ppmv = 5.7 mg/m³ Safety limits: OSHA PEL: 10 ppmv (8-hour TWA) OSHA ceiling: 20 ppmv (instantaneous) IDLH: 100 ppmv (immediately dangerous) LC50: 500–800 ppmv (lethal, 30 min exposure) Treating processes: - Amine treating (MDEA, DEA): bulk removal to < 4 ppmv - Iron sponge / SulfaTreat: polishing for low-rate streams - LO-CAT / SulFerox: liquid redox for small to medium rates - Molecular sieve: combined H2S and water removal

Carbon Dioxide (CO2)

CO2 is limited to 2–3 mol% in most tariffs to prevent internal corrosion in carbon steel pipelines and to maintain heating value. CO2 removal is typically accomplished with amine treating (MDEA selective for CO2, or generic amines) or membrane separation for high-CO2 streams.

Water Vapor

The standard US pipeline specification for water vapor is 7 lb/MMscf (approximately 112 ppmv at 1,000 psig). This level prevents free water condensation at ambient pipeline temperatures above approximately 35°F and provides adequate hydrate prevention margin. Dehydration to this level is achieved with TEG (triethylene glycol) absorbers or molecular sieve adsorbers.

Other Contaminants

Contaminant	Typical Limit	Risk	Removal Method
Mercury (Hg)	≤ 0.001 mg/Nm³	Aluminum corrosion in cryogenic equipment	Sulfur-impregnated activated carbon
Oxygen (O2)	≤ 0.2 – 1.0 mol%	Combustion in pipeline, sulfur oxidation	Catalytic removal, production control
BTEX	Not usually specified	Environmental emissions at dehy units	Condenser on glycol regenerator
Carbonyl sulfide (COS)	≤ 5 ppmv (where specified)	SO2 emissions on combustion	Hydrolysis + amine, or molecular sieve
Mercaptans (RSH)	Included in total sulfur	Odor, corrosion, SO2 emissions	Caustic wash, molecular sieve, amine

Mercury awareness: Mercury in natural gas, even at parts-per-trillion levels, causes catastrophic liquid metal embrittlement in aluminum heat exchangers used in cryogenic NGL recovery plants. Any gas destined for cryogenic processing must be tested for mercury, and removal beds (sulfur-impregnated carbon or silver-doped molecular sieve) must be installed upstream of aluminum equipment.

5. Dewpoint Control

Dewpoint specifications prevent liquid formation in the pipeline, which causes slugging, pressure drop increases, measurement errors, and potential safety hazards at delivery points.

Water Dewpoint

Water Dewpoint vs. Water Content: The water content specification (7 lb/MMscf) corresponds to a water dewpoint of approximately: At 1,000 psig: ~32°F water dewpoint At 800 psig: ~28°F water dewpoint At 500 psig: ~20°F water dewpoint TEG dehydration performance: Standard TEG (99.0%): 7 lb/MMscf achievable Enhanced TEG (99.5%): 3–4 lb/MMscf achievable Stripping gas TEG: 1–2 lb/MMscf achievable Molecular sieve: 0.1 lb/MMscf achievable Hydrate formation temperature (approximate): At 1,000 psig, 0.65 SG gas: ~70°F Must maintain pipeline temperature above hydrate point OR ensure water content is below saturation at minimum pipeline temperature.

Hydrocarbon Dewpoint (HCDP)

The hydrocarbon dewpoint is the temperature at which the first drop of hydrocarbon liquid condenses from the gas at a given pressure. Pipeline tariffs typically specify a maximum HCDP of 15–20°F at the maximum operating pressure (usually 800–1,000 psig). The HCDP is controlled by removing heavier hydrocarbons (C3+) through refrigeration, JT expansion, or cryogenic processing.

Cricondentherm and Phase Envelope

Phase Envelope Terminology: Cricondentherm: Maximum temperature at which liquid can exist at ANY pressure. This is the true maximum hydrocarbon dewpoint. Cricondenbar: Maximum pressure at which liquid and vapor can coexist. HCDP specification applies at operating pressure: A gas may have a cricondentherm of 40°F but meet a 15°F HCDP spec at 800 psig because the dewpoint curve shape means it crosses 15°F at that pressure. Measurement methods: - Manual chilled mirror (Bureau of Mines method) - Automatic chilled mirror (continuous) - Calculated from extended GC analysis (C9+ required) - Equation of state (SRK or PR with proper C6+ split)

HCDP measurement vs. calculation: There is a well-known discrepancy between calculated HCDP (from GC analysis + EOS) and measured HCDP (chilled mirror). Calculated values are often 10–30°F lower than measured because standard GC analysis underestimates the C6+ heavy tail. For tariff compliance, use the method specified in the pipeline tariff. When in doubt, measure with a chilled mirror device.

6. Gas Chromatography

Gas chromatography (GC) is the primary analytical method for determining natural gas composition. The GC separates individual components by their different rates of travel through a chromatographic column, then detects and quantifies each component as it elutes.

GC Analysis Types

Analysis Type	GPA Standard	Components	Application
Standard analysis	GPA 2261	C1 through C6+, N2, CO2	Custody transfer, routine quality
Extended analysis	GPA 2286	C1 through C12+, N2, CO2, H2S	HCDP calculations, processing design
Online process GC	GPA 2261	C1 through C6+, N2, CO2, H2S	Continuous monitoring, BTU tracking
Sulfur speciation	ASTM D5504	H2S, COS, mercaptans, thiophene	Total sulfur compliance

Custody Transfer GC Requirements

Calibration: Daily calibration with certified reference gas mixtures traceable to NIST standards. Calibration gas composition must bracket the expected sample composition.
Repeatability: Consecutive analyses must agree within 0.1 mol% for major components (C1, C2) and 0.05 mol% for minor components.
C6+ characterization: The C6+ fraction must be characterized by molecular weight and specific gravity for accurate heating value and compressibility calculations.
Normalization: Component mole fractions must sum to 100.0%. Any deviation is distributed proportionally across all components.

Online GC cycle time: Modern online process GCs complete a full analysis in 3–8 minutes, providing near-real-time composition data for BTU calculation, process control, and quality monitoring. For custody transfer, the analysis cycle time determines how quickly an off-spec condition is detected, making shorter cycle times commercially valuable.

7. Custody Transfer Measurement

Custody transfer is the point where gas ownership changes hands, and accurate measurement determines the financial value of the transaction. Gas is measured in terms of energy content (MMBtu), not volume, requiring both accurate flow measurement and compositional analysis.

Energy Measurement

Energy flow rate: E = Q × GHV Where: E = energy flow rate (MMBtu/hr or MMBtu/day) Q = volumetric flow rate at standard conditions (Mscf/hr) GHV = gross heating value at standard conditions (BTU/scf) Standard conditions (US industry): Temperature: 60°F (15.56°C) Pressure: 14.696 psia (101.325 kPa) Volume at standard conditions: Q_std = Q_actual × (P_actual / P_std) × (T_std / T_actual) / Z Where Z = compressibility factor (AGA Report No. 8) Monthly billing example: Average flow: 50 MMscf/d Average GHV: 1,035 BTU/scf Monthly energy: 50,000 × 1,035 × 30 = 1,552,500 MMBtu At $3.00/MMBtu: $4,657,500/month

Flow Measurement Methods

Meter Type	Accuracy	Standard	Application
Orifice meter	± 0.5 – 1.0%	AGA Report No. 3	Most common, moderate flow rates
Ultrasonic meter	± 0.2 – 0.5%	AGA Report No. 9	Large pipelines, no pressure drop
Turbine meter	± 0.25 – 0.5%	AGA Report No. 7	Wide rangeability, moderate flows
Coriolis meter	± 0.1 – 0.35%	API MPMS Ch. 5.6	Mass flow, NGL and liquid measurement

Measurement uncertainty: A 0.5% measurement error on a 100 MMscf/d pipeline at $3.00/MMBtu represents approximately $56,000/month in misallocated revenue. Investment in high-accuracy metering (ultrasonic or Coriolis) and frequent GC calibration pays for itself rapidly on high-volume custody transfer points.

8. Processing Targets

Gas processing facilities are designed to bring raw wellhead gas into compliance with pipeline tariff specifications. Each contaminant and composition issue requires a specific treatment process, and the processing sequence is determined by the gas composition and downstream requirements.

Typical Processing Sequence

Standard gas processing train: 1. Inlet separation (slug catcher, inlet separator) → Remove free liquids and solids 2. Acid gas removal (amine treating) → H2S to < 4 ppmv, CO2 to < 2% 3. Dehydration (TEG or molecular sieve) → Water to < 7 lb/MMscf 4. NGL recovery (JT, refrigeration, or cryogenic) → HCDP to < 15°F at MAOP 5. Compression (if needed) → Delivery pressure per tariff 6. Custody transfer measurement → GC analysis + flow metering Process selection drivers: - Gas volume: Smaller streams (<10 MMscf/d) use simpler processes (iron sponge, JT valve) - Gas richness: Rich gas justifies cryogenic processing for NGL revenue - H2S content: High H2S requires amine + sulfur recovery - Water content: Molecular sieve for cryogenic, TEG for pipeline-quality dehydration

Quality vs. Economics Trade-offs

Decision	Option A	Option B	Economic Driver
NGL recovery depth	Leave ethane in gas (higher HV)	Recover ethane (NGL revenue)	Ethane price vs. BTU gas price
N2 rejection	Accept lower HV (blend)	Install NRU (cryogenic)	Capital cost vs. pipeline penalty
CO2 removal depth	2% CO2 (standard spec)	<50 ppmv CO2 (cryogenic feed)	Process downstream of treating

Ethane rejection: When ethane prices are low relative to natural gas, operators choose ethane rejection: leaving ethane in the residue gas stream to increase its heating value and sell ethane as gas rather than NGL. This decision can swing processing economics by millions of dollars annually and directly impacts gas quality (higher GHV when rejecting ethane).

9. Quality Monitoring Systems

Continuous gas quality monitoring is essential for process control, tariff compliance, and early detection of off-spec conditions. Modern facilities integrate multiple analyzers into a quality monitoring system with SCADA integration and automated alarms.

Monitoring Instruments

Parameter	Instrument	Range	Response Time
Composition / BTU	Online GC	Full composition	3–8 min cycle
H2S	Lead acetate tape, TDL	0–100 ppmv	Seconds (TDL), minutes (tape)
Moisture	Aluminum oxide, QCM	0–100 lb/MMscf	1–5 minutes
HCDP	Chilled mirror, calculated	−40 to +60°F	5–15 minutes
Oxygen	Electrochemical cell	0–25 mol%	10–30 seconds
CO2	NDIR, GC	0–10 mol%	Seconds (NDIR)

Alarm and Shutdown Logic

Low alarm: Gas quality approaching spec limit (e.g., H2S at 3 ppmv). Operator notification for process adjustment.
High alarm: Gas quality at spec limit (e.g., H2S at 4 ppmv). Operator must take immediate corrective action.
High-high shutdown: Gas quality exceeds spec limit. Automated diversion or shut-in to prevent off-spec delivery to pipeline.

Response time matters: The time between an off-spec condition developing and the monitoring system detecting it determines how much off-spec gas enters the pipeline. A 3-minute GC cycle means up to 3 minutes of off-spec gas could pass before detection. For critical parameters like H2S, fast-response analyzers (tunable diode laser, <10 seconds) should supplement the GC.

10. Industry Standards

Standard	Title	Relevance
GPA 2261	Analysis of Natural Gas and Similar Gaseous Mixtures by Gas Chromatography	Standard GC analysis method for custody transfer
GPA 2286	Extended Analysis for Natural Gas (C12+)	Extended GC for HCDP and processing design
GPA 2172	Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical HV	Heating value calculation from composition
AGA Report No. 8	Compressibility Factors of Natural Gas	Z-factor for volume correction at custody transfer
AGA Report No. 3	Orifice Metering of Natural Gas	Orifice meter calculation standard
AGA Report No. 9	Measurement of Gas by Multipath Ultrasonic Meters	Ultrasonic meter standard for custody transfer
API MPMS Ch. 14.1	Collecting and Handling of Natural Gas Samples	Proper sample collection for GC analysis
ASTM D1945	Analysis of Natural Gas by Gas Chromatography	Alternative to GPA 2261 for GC analysis
ISO 6976	Natural Gas - Calculation of Calorific Values	International heating value calculation standard

950 – 1,100 BTU/scf

≤ 4 ppmv (0.25 gr/100 scf)

GPA 2261 · AGA Report No. 8

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