1. Overview & Applications
Water content in natural gas is the amount of water vapor present at specified pressure and temperature conditions. Excessive water causes hydrate formation, pipeline corrosion, and reduced heating value. Accurate water content calculations are critical for:
Hydrate prevention
Pipeline integrity
Water forms solid hydrates with methane/ethane at high P, low T—blocking flow.
Corrosion control
Internal corrosion
Free water enables CO₂/H₂S corrosion; dewpoint control prevents condensation.
Dehydration design
Glycol systems
TEG/MEG contactor sizing requires accurate inlet and outlet water content.
Custody transfer
Contract specs
Gas sales contracts specify max water content (typically 4-7 lb/MMscf).
Key Concepts
- Water content (W): Mass of water vapor per standard volume of gas (lb H₂O/MMscf or mg/Nm³)
- Water dewpoint: Temperature at which water vapor condenses at given pressure
- Saturation: Gas in equilibrium with liquid water (maximum water content at P/T)
- Hydrate point: P/T condition where solid gas hydrates form (typically 40-60°F at pipeline pressures)
- PPM (mole basis): Parts per million water on molar basis (ppmv = mole fraction × 10⁶)
Why Water Content Matters
| Problem | Cause | Consequence | Prevention |
|---|---|---|---|
| Gas hydrates | Water + CH₄ at high P, low T | Pipeline blockage, flow stoppage | Dehydration or methanol injection |
| Internal corrosion | Free water + CO₂/H₂S | Pipe wall thinning, leaks | Keep water below dewpoint |
| Slug flow | Water accumulation in low spots | Compressor damage, meter errors | Drip pots, line drains |
| Reduced capacity | Water vapor displaces gas | Lower heating value delivery | Maintain spec water content |
| Freezing | Free water at T < 32°F | Ice blockage, instrument failure | Glycol injection or heating |
Industry standards: ASME B31.8 requires gas transmission pipelines to maintain water content below saturation at minimum operating temperature to prevent hydrate formation and internal corrosion. API RP 500 provides guidance on dewpoint specifications for custody transfer.
Typical Water Content Values
| Gas Condition | Pressure (psia) | Temperature (°F) | Water Content (lb/MMscf) |
|---|---|---|---|
| Wellhead (raw gas) | 1000 | 120 | 80-120 |
| Separator outlet | 800 | 100 | 60-90 |
| After glycol dehydration | 800 | 100 | 2-4 |
| Pipeline specification | 800-1200 | 60-80 | ≤ 7 |
| Transmission pipeline | 1000 | 60 | 4-6 |
2. McKetta-Wehe Charts
The McKetta-Wehe chart (GPSA, Figure 20-3) is the industry-standard graphical method for determining water content of natural gas at saturation. Developed empirically from experimental data, valid for sweet natural gas (no acid gas correction).
Chart Usage Method
McKetta-Wehe Procedure:
1. Locate temperature on X-axis (°F)
2. Follow vertical line to intersection with pressure curve
3. Read water content on Y-axis (lb H₂O/MMscf)
4. Apply corrections for:
- Gas gravity (if SG ≠ 0.6)
- Salt concentration in free water
- Acid gas content (CO₂/H₂S)
Typical Reading:
At 100°F and 1000 psia:
W ≈ 60 lb H₂O/MMscf (from chart/Bukacek)
Gas Gravity Correction
The McKetta-Wehe chart is based on SG = 0.6. For other gas gravities, apply correction factor:
Gravity Correction Factor:
Correction Factor (Cg) = (1 + SG) / 1.6
Where SG = gas specific gravity (air = 1.0)
W_corrected = W_chart × Cg
Example for SG = 0.7:
Cg = (1 + 0.7) / 1.6 = 1.0625
W_corrected = 65 × 1.0625 = 69 lb/MMscf
Note: Correction is small (< 10%) for typical natural gas (SG = 0.55-0.75)
Salinity Correction
Salt dissolved in free water lowers water vapor pressure, reducing equilibrium water content:
Salt Correction (GPSA Method):
Cs = 1 - (0.00134 × S)
Where:
S = Salt concentration (weight % NaCl)
Cs = Salinity correction factor
W_corrected = W_chart × Cs
Example for S = 5% NaCl:
Cs = 1 - (0.00134 × 5) = 0.9933
W_corrected = 65 × 0.9933 = 64.6 lb/MMscf
Seawater (3.5% salt): Cs ≈ 0.995 (0.5% reduction)
Formation brine (15% salt): Cs ≈ 0.980 (2% reduction)
Acid Gas Correction
CO₂ and H₂S increase water solubility, raising equilibrium water content above the McKetta-Wehe chart:
CO₂ Correction (Sharma-Campbell):
B_CO2 = A₁ + A₂/T + A₃/T² + A₄/T³
Where:
T = Temperature (°R)
A₁, A₂, A₃, A₄ = empirical constants
W_mix = W_HC × (1 - y_CO2 - y_H2S) + W_CO2 × y_CO2 + W_H2S × y_H2S
Where:
y_i = mole fraction of component i
W_HC = hydrocarbon water content from McKetta-Wehe
W_CO2, W_H2S = pure component water contents
Typical impact:
10% CO₂: +5% water content
20% CO₂: +10% water content
5% H₂S: +8% water content
Pressure-Temperature Relationship
| Temperature (°F) | 100 psia | 500 psia | 1000 psia | 2000 psia |
|---|---|---|---|---|
| 60 | 127 | 30 | 18 | 12 |
| 80 | 249 | 58 | 34 | 22 |
| 100 | 465 | 105 | 60 | 38 |
| 120 | 825 | 184 | 104 | 64 |
| 140 | 1403 | 309 | 172 | 104 |
| 160 | 2296 | 501 | 277 | 164 |
Water content in lb H₂O/MMscf at saturation for SG=0.6 gas. Values calculated using Bukacek correlation (equivalent to McKetta-Wehe chart, GPSA Section 20). Accuracy ±5%.
Chart limitations: McKetta-Wehe chart accuracy decreases above 300°F or below -40°F. For extreme conditions, use Bukacek correlation or rigorous thermodynamic models (Peng-Robinson EOS).
Example Calculation
Calculate saturated water content for natural gas (SG = 0.65, 5% CO₂) at 1000 psia and 100°F with 3% salt concentration:
Step 1: Calculate base water content at 100°F, 1000 psia
W_base = 60 lb/MMscf (from Bukacek/McKetta-Wehe, SG = 0.6)
Step 2: Apply gas gravity correction
Cg = (1 + 0.65) / 1.6 = 1.031
W_gravity = 60 × 1.031 = 61.9 lb/MMscf
Step 3: Apply salinity correction
Cs = 1 - (0.00134 × 3) = 0.996
W_salt = 61.9 × 0.996 = 61.6 lb/MMscf
Step 4: Apply acid gas correction
For 5% CO₂ at these conditions: +5% increase
W_final = 61.6 × 1.05 = 64.7 lb/MMscf
Result: Saturated water content ≈ 65 lb H₂O/MMscf
If actual water content is 7 lb/MMscf (pipeline spec), gas is well below saturation:
Dewpoint depression ≈ 25-35°F below operating temperature
3. GPSA & ISO Correlations
Analytical correlations provide computer-friendly alternatives to graphical McKetta-Wehe charts. These equations are programmed into flow computers, SCADA systems, and process simulators.
Bukacek Correlation
The Bukacek equation (1955) is widely used for hand calculations and spreadsheet applications:
Bukacek Water Content Equation:
W = (Pv / P) × A + B
Where:
W = Water content (lb H₂O/MMscf)
P = System pressure (psia)
Pv = Water vapor pressure at temperature T (psia)
A = 47430 (GPSA constant for lb/MMscf conversion)
B = Non-ideal gas correction factor
B coefficient calculation:
log₁₀(B) = -3083.87 / T + 6.69449
T = Temperature (°R = °F + 459.67)
First term (Pv/P × A): Ideal gas contribution (Raoult's Law)
Second term (B): Non-ideal correction for gas solubility effects
Water Vapor Pressure (Antoine Equation):
log₁₀(Pv) = A - B / (C + T)
For water (T in °C, Pv in mmHg):
A = 8.07131, B = 1730.63, C = 233.426 (valid 1-100°C)
A = 8.14019, B = 1810.94, C = 244.485 (valid 99-374°C)
Convert: Pv (psia) = Pv (mmHg) / 51.715
Accuracy: ±5% for 60-460°F, 15-10000 psia
ISO 18453 Method
ISO 18453 (Natural gas — Correlation between water content and water dew point) provides standardized calculation methods:
ISO 18453 Water Content:
xw = (Pv / P) × f
Where:
xw = Water mole fraction
Pv = Saturated water vapor pressure (Pa)
P = System pressure (Pa)
f = Enhancement factor (accounts for non-ideality)
Enhancement factor:
f = exp[(V̄w × (P - Pv)) / (R × T)]
Where:
V̄w = Partial molar volume of water in gas phase
R = Universal gas constant (8.314 J/mol·K)
T = Temperature (K)
Convert mole fraction to lb/MMscf:
W = xw × (MW_water / MW_gas) × 379.49 × ρ_std
Typical values:
f = 1.0-1.2 for low pressure (< 500 psia)
f = 1.2-1.5 for high pressure (1000-2000 psia)
Ning-Anderko-Saul Correlation
The Ning correlation (2012) extends accuracy to high pressures and temperatures encountered in deep gas wells:
Ning-Anderko-Saul Model:
ln(yw) = ln(Pv/P) + (Bwg - Vw∞) × P / (R × T) + ln(φw)
Where:
yw = Water mole fraction
Bwg = Second virial coefficient for water-gas interaction
Vw∞ = Infinite dilution partial molar volume of water
φw = Water fugacity coefficient
Valid range:
0-200°C (32-392°F)
0-200 MPa (0-29000 psia)
Accuracy: ±2% across full range
Required: Gas composition for virial coefficient calculation
Comparison of Correlation Accuracy
| Method | Accuracy | Valid Range (P) | Valid Range (T) | Application |
|---|---|---|---|---|
| McKetta-Wehe | ±5-10% | 15-10000 psia | -40-300°F | Hand calculations, screening |
| Bukacek | ±5% | 100-3000 psia | 60-200°F | Spreadsheets, simple programs |
| ISO 18453 | ±3% | 50-5000 psia | 20-250°F | Flow computers, custody transfer |
| Ning-Anderko | ±2% | 0-29000 psia | 32-392°F | High P/T wells, simulators |
| Peng-Robinson EOS | ±5-10% | All pressures | All temperatures | Phase equilibrium, multiphase |
Dewpoint Calculation
Given water content, calculate dewpoint by iterative solution:
Dewpoint from Water Content:
Problem: Find T_dewpoint given W (lb/MMscf) and P (psia)
Method 1 - Iterative Solution:
1. Guess initial T_dewpoint
2. Calculate W_sat at T_dewpoint and P using chosen correlation
3. Compare W_sat to known W
4. Adjust T_dewpoint and repeat until W_sat = W (within tolerance)
Method 2 - Approximate Formula (Maddox et al.):
T_dewpoint = B / (A - log₁₀(W × P / C)) - D
Where A, B, C, D are fitted constants:
A = 8.15, B = 1810, C = 53000, D = 460
Accuracy: ±5°F for pipeline conditions
Example:
W = 7 lb/MMscf, P = 1000 psia
T_dewpoint = 1810 / (8.15 - log₁₀(7 × 1000 / 53000)) - 460
T_dewpoint ≈ 35°F
Gas must be kept above 35°F to prevent condensation.
Method selection: Use McKetta-Wehe/Bukacek for typical pipeline conditions (100-1500 psia, 60-120°F). Use ISO 18453 for custody transfer and contractual calculations. Use Ning or rigorous EOS for high-pressure wells (> 3000 psia) or extreme temperatures.
4. Dehydration Systems
Dehydration removes water vapor from natural gas to meet pipeline specifications, prevent hydrate formation, and minimize corrosion. Three primary methods: glycol absorption, molecular sieves, and refrigeration.
Glycol Dehydration (TEG/MEG)
Triethylene glycol (TEG) absorption is the most common dehydration method in midstream operations:
TEG Contactor Design Basis:
Water removal required:
ΔW = W_inlet - W_outlet (lb H₂O/MMscf)
Glycol circulation rate:
Gal_TEG/lb_H2O = 3.0-4.0 (typical design)
Minimum circulation:
Gal_TEG = (Q_gas × ΔW) / (Conc_lean - Conc_rich)
Where:
Q_gas = Gas flow rate (MMscfd)
Conc_lean = Lean glycol concentration (wt% TEG, typically 99.0-99.5%)
Conc_rich = Rich glycol concentration (wt% TEG, typically 97-98%)
Number of theoretical trays:
N_trays = 6-8 for standard service
N_trays = 10-12 for deep dehydration (< 2 lb/MMscf)
Actual trays = N_trays / tray_efficiency (efficiency ≈ 0.25-0.33)
TEG System Performance
| Lean TEG Conc. | Outlet Water Content | Dewpoint Depression | Application |
|---|---|---|---|
| 98.5 wt% | 10-15 lb/MMscf | 20-30°F | Minimal service (rare) |
| 99.0 wt% | 5-7 lb/MMscf | 30-40°F | Standard pipeline spec |
| 99.5 wt% | 2-4 lb/MMscf | 40-60°F | Deep dehydration |
| 99.9 wt% (with stripping gas) | < 1 lb/MMscf | 60-80°F | Cryogenic processing feed |
Molecular Sieve Dehydration
Molecular sieves (zeolites) achieve extremely low water content through adsorption:
Molecular Sieve Sizing:
Bed capacity:
Q_capacity = W_ads × M_sieve × RCF
Where:
W_ads = Water adsorption capacity (wt%, typically 10-14% for 4A zeolite)
M_sieve = Mass of sieve material (lb)
RCF = Remaining capacity factor (0.7-0.8, accounts for cycling losses)
Bed sizing:
V_bed = Q_gas × t_ads × ΔW / (Q_capacity × ρ_bulk)
Where:
t_ads = Adsorption cycle time (8-12 hours typical)
ΔW = Water loading (lb H₂O/MMscf)
ρ_bulk = Bulk density of sieve (45-50 lb/ft³)
Regeneration requirements:
- Temperature: 400-600°F
- Gas flow: 5-10% of process gas throughput
- Cycle time: 2-4 hours heating + 2-4 hours cooling
Outlet water content: < 0.1 ppmv (< 0.5 lb/MMscf)
Refrigeration Dehydration
Mechanical refrigeration condenses water by cooling gas below dewpoint:
Refrigeration System Design:
Cooling load:
Q_cool = Q_gas × ρ × Cp × ΔT
Where:
Q_gas = Gas volumetric flow (ft³/hr)
ρ = Gas density (lb/ft³)
Cp = Specific heat (Btu/lb·°F, ≈ 0.5 for natural gas)
ΔT = Temperature drop (°F)
Water removal:
W_removed = W_inlet - W_sat(T_chiller, P)
Typical performance:
Chiller temperature: 35-40°F
Outlet water content: 15-25 lb/MMscf
Application: Partial dehydration, hydrocarbon recovery
Limitations:
- Cannot achieve pipeline spec (< 7 lb/MMscf) without glycol or sieves
- Hydrate formation risk in chiller (requires methanol injection)
- High energy consumption at low temperatures
Dehydration Method Comparison
| Method | Outlet Water (lb/MMscf) | Capital Cost | Operating Cost | Best Application |
|---|---|---|---|---|
| TEG absorption | 2-7 | Low | Low-moderate | Pipeline transmission, standard service |
| Molecular sieves | < 0.5 | Moderate-high | Moderate | Cryogenic plant feed, deep dehydration |
| Refrigeration | 15-25 | Moderate | High (power) | Hydrocarbon recovery, partial dehydration |
| Membrane | 10-20 | Moderate | Low | Offshore, remote locations |
| Methanol injection | Not applicable | Very low | Low (chemical) | Hydrate prevention only (no dehydration) |
System selection criteria: TEG is preferred for 90% of pipeline applications due to low cost and 2-7 lb/MMscf capability. Molecular sieves required for cryogenic processing (< 1 lb/MMscf) or when TEG regeneration is impractical. Refrigeration used primarily for hydrocarbon recovery with partial dehydration as secondary benefit.
Glycol Loss Mechanisms
- Vaporization loss: TEG vapor carried out with gas stream (0.1-0.3 gal/MMscf typical)
- Entrainment loss: Liquid droplets entrained by high gas velocity (use mist eliminator)
- Flash loss: Glycol flashes when pressure drops across control valve
- Filter/drain loss: Glycol removed with filters and drain systems
- Degradation loss: Thermal degradation in reboiler (> 400°F causes breakdown)
Typical total glycol makeup: 0.3-0.5 gal TEG per MMscf gas processed (includes all loss mechanisms)
5. Practical Applications
Hydrate Formation Prevention
Gas hydrates form when free water exists at specific P/T combinations. Water content calculations determine if dehydration is needed:
Hydrate Prevention Strategy:
Option 1 - Maintain gas below saturation (no free water):
W_actual << W_sat at (P_min, T_min)
Safety factor: W_actual ≤ 0.7 × W_sat
Option 2 - Operate above hydrate formation temperature:
T_operating > T_hydrate + safety_margin
Typical safety margin: 10-15°F above hydrate point
Option 3 - Methanol/MEG injection (if free water present):
Methanol required (wt% in water phase) = Depression / K
Where:
Depression = T_hydrate - T_operating (°F)
K = 2300-2500 °F (empirical constant)
Example:
Depression = 20°F, K = 2400
Methanol = 20 / 2400 = 0.0083 = 0.83 wt% in water phase
Hydrate prediction: Use CSMGem, PVTsim, or similar software for multi-component systems
Pipeline Dewpoint Specification
Design pipeline operation to maintain gas temperature above dewpoint with safety margin:
Dewpoint Specification Method:
Step 1: Determine minimum operating temperature
T_min = min(T_ambient, T_chiller, T_expansion) - margin
Typical ambient: T_min = T_ambient,winter - 10°F
Step 2: Calculate maximum allowable water content
W_max = W_sat(T_min, P_max) × safety_factor
Safety factor = 0.5-0.7 (provides 10-20°F dewpoint depression)
Step 3: Set pipeline specification
Spec: "Water content shall not exceed [W_max] lb/MMscf,
equivalent to dewpoint ≤ [T_min] at [P_max] psia"
Example:
T_min = 40°F, P_max = 1000 psia
W_sat(40°F, 1000 psia) ≈ 15 lb/MMscf (from McKetta-Wehe)
With 0.5 safety factor: W_max = 7.5 lb/MMscf
Round down for conservatism: Spec = 7 lb/MMscf
This provides ~20°F dewpoint depression (dewpoint ≈ 20°F at 1000 psia)
TEG System Troubleshooting
| Problem | Symptom | Likely Cause | Solution |
|---|---|---|---|
| High outlet water content | W > 7 lb/MMscf | Low lean glycol concentration | Increase reboiler temperature, check for water in still column |
| High glycol losses | > 0.5 gal/MMscf makeup | Excessive vaporization or entrainment | Lower contactor temperature, install mist eliminator |
| Foaming | High ΔP across contactor | Hydrocarbon contamination | Add activated carbon filter, check for condensate carryover |
| Dark glycol color | Brown/black solution | Thermal degradation | Reduce reboiler temp (< 400°F), reclaim or replace glycol |
| Corrosion | Fe²⁺ in glycol, wall thinning | Low pH from acid gas | Add neutralizing amine, check for H₂S/CO₂ |
Water Content Measurement Methods
- Chilled mirror hygrometer: Cools sample until water condenses; measures dewpoint directly (±1°F accuracy)
- Aluminum oxide sensor: Capacitance changes with moisture absorption (±2°F dewpoint, requires calibration)
- Karl Fischer titration: Laboratory chemical analysis (±0.5 lb/MMscf, slow but accurate)
- Tunable diode laser (TDL): Infrared absorption spectroscopy (real-time, ±1 ppmv)
- Gas chromatography: Separates water peak in GC analysis (requires careful calibration)
Regulatory Requirements
| Standard/Code | Requirement | Application |
|---|---|---|
| ASME B31.8 | Prevent hydrate formation and internal corrosion | Gas transmission pipeline design |
| API RP 500 | ≤ 7 lb/MMscf for custody transfer | Sales gas specifications |
| GPA 2174 | Water content by gravimetric method | Laboratory analysis procedures |
| ISO 10101 | Dewpoint measurement by chilled mirror | Field measurement standards |
| NACE MR0175 | Material selection for sour service | H₂S-containing gas dehydration |
Common Calculation Errors
- Using gauge pressure: Water content correlations require absolute pressure (psig + 14.7)
- Ignoring gas gravity correction: 0.1 SG difference = ~6% error in water content
- Mixing temperature scales: Correlations use °R (°F + 459.67), not °F directly
- Confusing ppmv and lb/MMscf: 1000 ppmv ≈ 47 lb/MMscf (for MW=19 gas), conversion is NOT 1:1
- Applying sweet gas correlations to sour gas: H₂S/CO₂ increases water content significantly
- Neglecting enhancement factor: At high pressure, ideal mixing rules underpredict water content
Unit Conversions
Common Water Content Units:
lb H₂O/MMscf ↔ mg H₂O/Nm³:
mg/Nm³ = lb/MMscf × 16.0185
lb H₂O/MMscf ↔ ppmv (mole basis):
ppmv = (lb/MMscf) × (MW_gas / MW_water) × 21.5
For MW_gas = 19:
ppmv ≈ (lb/MMscf) × 22.7
Examples:
7 lb/MMscf = 112 mg/Nm³ = 159 ppmv (for SG=0.65 gas)
50 ppmv = 2.2 lb/MMscf = 35 mg/Nm³ (for SG=0.65 gas)
Dewpoint conversions:
°F = (°C × 9/5) + 32
°R = °F + 459.67
K = °C + 273.15
Best practice: Always verify dewpoint specification accounts for minimum operating temperature with adequate safety margin. A 7 lb/MMscf spec at 1000 psia provides dewpoint ≈ 20-25°F, suitable for pipelines operating above 35-40°F ambient. For colder climates, specify 4 lb/MMscf or lower.
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