Hydrate Prevention

Overview

Gas hydrates are crystalline solid compounds in which gas molecules become trapped within cages formed by hydrogen-bonded water molecules. They resemble ice in appearance but can form at temperatures well above the freezing point of water when pressure is sufficiently high.

Hydrate formation is one of the most serious flow assurance risks in oil and gas production:

• Pipeline blockages -- hydrate plugs can completely block flowlines
• Equipment damage -- plug movement can cause mechanical impact on bends and valves
• Safety hazards -- pressure buildup behind a plug can lead to catastrophic failure
• Production losses -- remediation of a hydrate plug can take days to weeks

Three conditions must be present simultaneously for hydrate formation:

1. Free water -- liquid water in contact with gas
2. High pressure -- typically above 200 psia
3. Low temperature -- below the hydrate equilibrium temperature at system pressure

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Hydrate Formation Conditions

The Hydrate Equilibrium Curve

The hydrate equilibrium curve defines the pressure-temperature boundary above which hydrates are thermodynamically stable:

P (psia)
 │
 │                          ╱ Hydrate
 │                        ╱   Stable
 │                      ╱     Region
 │                    ╱
 │                  ╱
 │                ╱
 │              ╱  Hydrate Equilibrium Curve
 │            ╱
 │          ╱
 │        ╱
 │      ╱   No Hydrate
 │    ╱     Region
 │  ╱
 │╱
 └────────────────────────→ T (degF)

At any given pressure, the hydrate formation temperature is the temperature below which hydrates will form. Operating conditions must remain to the right of the equilibrium curve (higher temperature) to avoid hydrate formation.

Factors Affecting Hydrate Formation

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The Hammerschmidt Equation

General Form

The Hammerschmidt equation (1934) predicts the depression of the hydrate formation temperature caused by the presence of a thermodynamic inhibitor in the aqueous phase:

$$\Delta T = \frac{K_H \cdot w}{M \cdot (100 - w)}$$

Where:

• $\Delta T$ = hydrate temperature depression, degF
• $K_H$ = Hammerschmidt constant (depends on inhibitor type)
• $w$ = weight percent of inhibitor in the aqueous phase, wt%
• $M$ = molecular weight of the inhibitor, lb/lbmol

Inhibitor-Specific Constants

The constant $K_H = 2{,}335$ is commonly used for all inhibitors, though some references report slightly different values.

Temperature Depression by Inhibitor Type

For methanol:

$$\Delta T_{MeOH} = \frac{2335 \cdot w}{32.04 \cdot (100 - w)}$$

For MEG:

$$\Delta T_{MEG} = \frac{2335 \cdot w}{62.07 \cdot (100 - w)}$$

At the same weight percent, methanol provides approximately twice the temperature depression of MEG because of its lower molecular weight.

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Inhibitor Concentration

Inverse Hammerschmidt Equation

Given a required temperature depression, the required inhibitor concentration is obtained by rearranging the Hammerschmidt equation:

$$w = \frac{100 \cdot \Delta T \cdot M}{K_H + \Delta T \cdot M}$$

Where:

• $w$ = required weight percent of inhibitor in the aqueous phase, wt%
• $\Delta T$ = required temperature depression, degF
• $M$ = molecular weight of the inhibitor
• $K_H$ = Hammerschmidt constant

Concentration Comparison

Practical Limits

Above these concentrations, the Hammerschmidt equation becomes increasingly inaccurate and alternative approaches (e.g., Nielsen-Bucklin or thermodynamic models) should be used.

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Inhibitor Injection Rate

Calculation Method

The required inhibitor injection rate depends on the amount of free water that must be treated and the target inhibitor concentration:

$$Q_{inj} = \frac{Q_w \cdot w}{(100 - w) \cdot \rho_{inj}}$$

Where:

• $Q_{inj}$ = inhibitor injection rate, gal/day
• $Q_w$ = free water production rate, bbl/d
• $w$ = required inhibitor concentration, wt%
• $\rho_{inj}$ = inhibitor density, lb/gal

For methanol ($\rho_{MeOH} = 6.63$ lb/gal at standard conditions):

$$Q_{inj,MeOH} = \frac{Q_w \cdot w_{MeOH}}{(100 - w_{MeOH})} \cdot \frac{350.5}{6.63}$$

For MEG ($\rho_{MEG} = 9.34$ lb/gal at standard conditions):

$$Q_{inj,MEG} = \frac{Q_w \cdot w_{MEG}}{(100 - w_{MEG})} \cdot \frac{350.5}{9.34}$$

The factor 350.5 converts from lb/d of water (at 350.5 lb/bbl) to consistent units.

Methanol vs. MEG Selection

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Subcooling Margin

Definition

The subcooling is the temperature difference between the hydrate equilibrium temperature and the actual operating temperature at a given pressure:

$$\Delta T_{sub} = T_{hydrate}(P) - T_{operating}$$

Where:

• $\Delta T_{sub}$ = subcooling, degF (positive means hydrate risk)
• $T_{hydrate}(P)$ = hydrate equilibrium temperature at pressure $P$, degF
• $T_{operating}$ = actual fluid temperature, degF

Interpretation

Design Margin

Standard practice adds a safety margin of 3 to 5 degF beyond the calculated subcooling to account for:

• Uncertainty in gas composition
• Uncertainty in P-T profile predictions
• Transient conditions during shut-in and restart
• Measurement accuracy

The total required temperature depression for inhibitor sizing is:

$$\Delta T_{required} = \Delta T_{sub} + \Delta T_{margin}$$

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Calculation Workflow

Complete Hydrate Inhibition Design

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Applicability and Limitations

Hammerschmidt Equation Validity

Known Limitations

1. No composition dependence -- the equation uses gas gravity as a proxy rather than detailed composition
2. Ideal solution assumed -- activity coefficient effects are neglected at high concentrations
3. Single inhibitor only -- does not handle mixtures of inhibitors
4. No kinetic effects -- predicts thermodynamic equilibrium, not formation rate

When to Use More Advanced Methods

• Sour gas systems (H2S > 5 mol%)
• Very high inhibitor concentrations (> 50 wt% MeOH)
• Mixed inhibitor systems
• Detailed compositional studies for FEED or detailed design

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Related Documentation

• Flow Assurance Overview -- scope and decision frameworks
• Corrosion and Erosion -- CO2 corrosion and erosional velocity
• PVT Properties Overview -- fluid property correlations
• Gas Properties -- gas gravity, Z-factor calculations
• Pipe Flow Overview -- pressure and temperature profiles

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References

1. Hammerschmidt, E.G. (1934). "Formation of Gas Hydrates in Natural Gas Transmission Lines." Industrial & Engineering Chemistry, 26(8), pp. 851-855.

2. Sloan, E.D. and Koh, C.A. (2008). Clathrate Hydrates of Natural Gases, 3rd Edition. CRC Press. Chapter 6: Thermodynamic Inhibition.

3. Carroll, J.J. (2014). Natural Gas Hydrates: A Guide for Engineers, 3rd Edition. Gulf Professional Publishing. Chapter 4: Inhibiting Hydrate Formation.

4. Kidnay, A.J., Parrish, W.R., and McCartney, D.G. (2011). Fundamentals of Natural Gas Processing, 2nd Edition. CRC Press. Chapter 9: Gas Dehydration and Hydrate Prevention.

5. Nielsen, R.B. and Bucklin, R.W. (1983). "Why Not Use Methanol for Hydrate Control?" Hydrocarbon Processing, 62(4), pp. 71-78.