Hydrate formation prevention

Under certain conditions of temperature and pressure, and in the presence of free water, hydrocarbon gases can form hydrates, which are a solid formed by the combination of water molecules and the methane, ethane, propane or butane. Hydrates look like compacted snow, and can form blockages in pipelines and other vessels. Process engineers use correlation techniques and process simulation to predict the possibility of hydrate formation, and prevent its formation by either drying the gas or adding a chemical (such as tri-ethylene glycol), or a combination of both. This is further discussed in SectionlO.1. 

Dehydration can be performed by a number of methods cooling, absorption and adsorption. Water removal by cooling is simply a condensation process at lower temperatures the gas can hold less water vapour. This method of dehydration is often used when gas has to be cooled to recover heavy hydrocarbons. Inhibitors such as glycol may have to be injected upstream of the chillers to prevent hydrate formation. 

To meet sales specifications, gas produced at the wellheads must be free of water and hydrocarbon liquids. Twin turboexpanders are a key component in this process, providing dewpoint control with optimal efficiency. Initial processing takes place at the wellhead platforms, where methanol is injected to inhibit hydrate formation. A corrosion inhibitor is also added to prevent gas from damaging downstream equipment. 

In a typical gas oil design, the lighter products overhead from the quench tower/primary fractionator are compressed to 210 psi, and cooled to about 100°F. Some Q plus material is recovered from the compressor knockout drums. The gases are ethanolamine and caustic washed to remove acid gases sulfur compounds and carbon dioxide, and then desiccant dried to remove last traces of water. This is to prevent ice and hydrate formation in the low temperamre section downstream. 

Methods of preventing hydrate formation include adding heat to assure that the temperature is always above the hydrate formation temperature, lowering the hydrate formation temperature with chemical inhibition, or dehydrating the gas so that water vapor will not condense into free water. It is also feasible to design the process so that if hydrates form they can be melted before they plug equipment. 

Knowledge of the temperature and pressure of a gas stream at the wellhead is important for determining whether hydrate formation can be expected when the gas is expanded into the flow lines. The temperature at the wellhead can change as the reservoir conditions or production rate changes over the producing life of the well. Thus, wells that initially flowed at conditions at which hydrate formation in downstream equipment was not expected may eventually require hydrate prevention, or vice versa. 

Chapter 4 discussed the need to prevent hydrates, the techniques necessary to predict hydrate formation, and the use of chemical inhibitors. This chapter covers two types of equipment for handling hydrates. 

In order to adequately describe the size of a heater, the heat duty, the size of the fire tubes, the coil diameters and wall thicknesses, and the cor lengths must be specified. To determine the heat duty required, the maximum amounts of gas, water, and oil or condensate expected in the heater and the pressures and temperatures of the heater inlet and outlet must be known. Since the purpose of the heater is to prevent hydrates from forming downstream of the heater, the outlet temperature will depend on the hydrate formation temperature of the gas. The coil size of a heater depeiuLs on the volume of fluid flowing through the coil and the required heat duty. 

Dehydration to dew points below the temperature to which the gas will be subjected will prevent hydrate formation and corrosion from condensed water. The latter consideration is especially important in gas streams containing CO2 or H2S where the acid gas components will form an acid with the condensed water. 

Moisture must be removed from natural gas to reduce corrosion problems and to prevent hydrate formation. Hydrates are solid white compounds formed from a physical-chemical reaction between hydrocarbons and water under the high pressures and low temperatures used to transport natural gas via pipeline. Hydrates reduce pipeline efficiency. 

Stoppage of natural gas-water streams due to the formation of gas hydrates is prevented by incorporation of a surface-active agent in such streams, e.g., a 15% aqueous solution of hydroxylamine phosphate, which inhibits the formation of gas hydrates and the agglomeration of hydrate crystallites into large crystalline masses [255],... 

Kinetic inhibitors for hydrate formation may also be effective in preventing scale deposition [1627]. This may be understood in terms of stereospecific and nonspecific mechanisms of scale inhibition. 

Thermodynamic inhibitors Antinucleants Growth modifiers Slurry additives Anti-agglomerates Methanol or glycol modify stability range of hydrates. Prevent nucleation of hydrate crystals. Control the growth of hydrate crystals. Limit the droplet size available for hydrate formation. Dispersants that remove hydrates. 

Hydrate formation can be prevented by drying a gas to such an extent that no condensate can be formed. This method is the preferable one, but inhibition of hydrate formation from the liquid phase can be achieved. 

As mentioned previously, the classic additive to prevent hydrate formation is alcohol. Traditional hydrate inhibitors such as methanol and glycols have been in use for many years, but demand for cheaper methods of inhibition is great. Therefore the development of alternative, cost-effective, and environmentally acceptable hydrate inhibitors is a technologic challenge for the oil and gas production industry [947]. 

Gas specifications will be inqportant only if the gas is to be delivered to a gas pipeline system. If the gas is to be injected in the producing field the only usual critical requirement is to dehydrate the gas adequately to prevent hydrate formation anywhere in the system. The gas pipeline specification which most Influences the design of oil-gas separation systems is the hydrocarbon dewpoint limitation. This is usually expressed as a maximum dewpoint temperature at a specified pressure. For onshore gas pipelines in the USA end Europe this specification may be in the range of 32°F (0°C) at 1000 paia (68 atmospheres), which is adequate to prevent condensation of liquids in the pipelines in the normal range of onshore pipeline operating pressures from 900 to 1000 psl. In the USA this specification is seldom iiqposcd on producers and is controlled with pipeline facilities. 

Even if water vapor does not condense in CNG systems under static condition, some water vapor may condense in the portions of the system where pressure is reduced. The combination of water vapor and sulfur compounds has been known to cause the formation of hydrates, which are crystalline in structure (similar to snow) and which can cause operational and materials compatibility problems. Ways to prevent hydrate formation include limiting water vapor and sulfur in the natural gas, and through good system design. 

The metastability of the system prevents hydrate forming immediately at Point D (at the hydrate equilibrium temperature and pressure Figure 3.1b). Instead the system pressure continues to decrease linearly with temperature for a number of hours, without hydrate formation occurring (A to B is the induction period, cf. 1 in Figure 3.1a). At Point B, hydrates begin to form. The pressure drops rapidly to Point C (about 1.01 MPa or 10 atm in 0.5 h). B to C is the catastrophic growth period (cf. 2 in Figure 3.1a). 

The inhibition of three-phase hydrate formation is discussed in Section 4.4. These predictions enable answers to such questions as, How much methanol (or other inhibitor) is required in the free water phase to prevent hydrates at the pressures and temperatures of operation Classical empirical techniques such as that of Hammerschmidt (1934) are suitable for hand calculation and provide a qualitative understanding of inhibitor effects. It should be noted that only thermodynamic inhibitors are considered here. The new low-dosage hydrate inhibitors [LDHIs, such as kinetic inhibitors (KIs) or antiagglomerants (AAs)] do not significantly affect the thermodynamics but the kinetics of hydrate formation LDHIs are considered in Chapter 8. 

The calculation of two-phase (hydrate and one other fluid phase) equilibrium is discussed in Section 4.5. The question, To what degree should hydrocarbon gas or liquid be dried in order to prevent hydrate formation is addressed through these equilibria. Another question addressed in Section 4.5 is, What mixture solubility in water is needed to form hydrates ... 

Each line in Figure 4.2d (except for the lower, almost vertical I-Lw-V lines) bounds hydrate formation conditions listed with a methanol concentration in the free water phase. To the left of each line with H in the label, hydrates will form with a water phase of the given methanol composition to the right of the line hydrates will not form. For example, when the free water phase has 10% methanol, hydrates will not form at pressure-temperature conditions to the right of the line marked 10% MeOH. Yet if no methanol were present, the hydrates would form at pressures and temperatures between the two lines marked 10% and 0% MeOH. Similarly, for process pressure and temperature conditions between the lines marked 10% and 20%, at least 20% methanol in the free water phase would be required to prevent hydrate formation. 

Of alcohols, methanol has been the most popular inhibitor, due to its cost and its effectiveness. Katz et al. (1959, p. 218) indicated that the inhibition ability of alcohols increases with volatility, that is, methanol > ethanol > isopropanol. Typically methanol is vaporized into the gas stream of a transmission line, then dissolves in any free water accumulation(s) where hydrate formation is prevented. Makogon (1981, p. 133) noted that in 1972 the Soviet gas industry used 0.3 kg of methanol for every 1000 m3 of gas extracted. Stange et al. (1989) indicated that North Sea methanol usage may surpass the ratio given by Makogon by an order... 

To prevent water occlusion. Without agitation, Villard (1896) showed, for example, that nitrous oxide hydrate formation was continuous for a period longer than 15 days under a pressure of 2 MPa. Villard also determined that in previous research the ratio of water to guest molecules had been analyzed as greater than G 6H20 (Villard s Rule) due to either occlusion of water within the hydrate mass, or due to the loss of the guest component. 

While the past methods of preventing hydrate plugs have been to use avoidance with thermodynamic inhibitors such as methanol or glycols, our new understanding of how plugs form, allows us to propose economic risk management (kinetics) to avoid hydrate formation. These concepts differ in type for oil-dominated and gas-dominated systems. 

Considering hydrate formation and prevention, the physical conditions necessary for hydrates are... 

Notz (1994) noted that almost all of Texaco s efforts concerning natural gas hydrates dealt with the prevention of hydrate formation in production and transportation systems. He presented Figure 8.1 from Texaco s hydrate prevention program in a 50 mile deepwater gas pipeline, using a phase diagram similar to those discussed with Figure 4.2. 

In Figure 8.1, by mile 30 the gas in the pipeline has cooled to within a few degrees of the ocean floor temperature, so that approximately 23 wt% methanol in the free water phase is required to prevent hydrate formation and subsequent... 

Note that regular methanol (or monoethylene glycol) injection is used only with gas-dominated systems. In oil-dominated systems the higher liquid heat capacity allows the system to retain reservoir heat, so that insulation maintains sufficient temperatures to prevent hydrate formation. Thermodynamic inhibitor is normally only injected for planned shutdowns in oil-dominated systems. 

Line heaters could be installed at the wellhead to increase the inlet gas temperature from 85°F to 125°F. Figure 8.5 shows the pipeline temperature increase caused by the combined prevention methods of burial and wellhead heating. Use of these two methods permitted the methanol concentration in the free water phase to be reduced to approximately 14 wt% to prevent hydrate formation in the line. It should, however, be noted that heating may increase the amount of corrosion in the line. 

To prevent hydrate formation in expansion on the downstream side of a valve, the most common method is to inject methanol or glycol before the value, removing the hydrate formation (shaded) region to the left of Figure 8.7 from the expansion conditions. Alternatives include heating the inlet gas or limiting the downstream pressure. 

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