JAWAHARLAL NEHRU TECHNOLOGICAL UNIVERSITY HYDERABAD B.Tech IV NATURAL GAS PROCESSING Previous Question Paper (October/November - 2020 - R15)

Hydrate formation in natural gas streams occurs when water vapor condenses in the presence of light hydrocarbons at high pressures and low temperatures. To prevent hydrate formation, the thermodynamic equilibrium conditions must be shifted or the water content must be reduced. The primary methods to achieve this are as follows:

• Dehydration: This is the most common method, involving the removal of water vapor from the gas stream until the dew point is below the lowest expected operating temperature. Common processes include absorption using liquid desiccants like triethylene glycol (TEG) or adsorption using solid desiccants like molecular sieves or silica gel.
• Chemical Inhibition: This involves injecting thermodynamic inhibitors into the gas stream to lower the hydrate formation temperature. Methanol or monoethylene glycol (MEG) are typically used. These chemicals act by disrupting the hydrogen bonding of water molecules, effectively shifting the hydrate equilibrium curve to lower temperatures or higher pressures.
• Heating: Increasing the temperature of the gas stream above the hydrate formation temperature prevents the condensation of water. This is often achieved using line heaters or heat exchangers, particularly in short-distance gathering lines or at wellheads where pressure drops occur.
• Pressure Reduction: Since hydrate formation is pressure-dependent, reducing the operating pressure of the system can move the gas out of the hydrate formation region. However, this is often limited by downstream processing requirements or pipeline capacity constraints.
• Kinetic Inhibitors and Anti-Agglomerants: These are specialty chemicals used in subsea or long-distance pipelines. Kinetic inhibitors delay the nucleation and growth of hydrate crystals, while anti-agglomerants allow hydrates to form but keep them dispersed as a slurry in the hydrocarbon phase, preventing the formation of plugs.

To calculate the inhibitor requirement, we first determine the water content of the gas at the separator conditions and the required depression in hydrate formation temperature.

1. Water content at 100°F and 600 psia: Using standard gas industry charts (McKetta and Wehe), the water content of natural gas at 100°F and 600 psia is approximately 145 lb/MMscf.

2. Hydrate formation temperature (HFT) depression: The gas is cooled to 35°F, while the hydrate formation temperature at 500-600 psia is 59°F. The required temperature depression is ΔT = 59°F - 35°F = 24°F.

3. Methanol requirement: The Hammerschmidt equation for methanol is ΔT = (K × W) / (M × 100 - K × W), where K = 2335, M = 32.04 (MW of methanol), and W is the weight percent of methanol in the aqueous phase. Rearranging for W: W = (100 × M × ΔT) / (K + M × ΔT) = (100 × 32.04 × 24) / (2335 + 32.04 × 24) ≈ 24.78 wt%. The required methanol is calculated as: (W / (100 - W)) × (lb water / MMscf) = (24.78 / 75.22) × 145 ≈ 47.76 lb/MMscf.

4. Ethylene Glycol (EG) requirement: Using the Nielsen-Bucklin correlation or standard charts for 80 wt% EG solution, the depression constant for EG is lower than methanol. For a 24°F depression, the required concentration of pure EG in the aqueous phase is approximately 35 wt%. Since the inhibitor is supplied as an 80 wt% mixture, the total amount of solution required is: (lb pure EG needed) / 0.80. Based on standard charts, to achieve a 24°F depression, approximately 0.65 lb of pure EG is required per lb of water removed. Total pure EG = 0.65 × 145 = 94.25 lb/MMscf. Total 80 wt% solution = 94.25 / 0.80 = 117.81 lb/MMscf.