Hydrates formation

Finally, gas-solid equilibria should be studied to avoid plugging problems due in particular to hydrate formation. 

Calculating the hydrate formation temperature is essential when one needs to guard against equipment and line plugging that can result when wet gas is cooled, intentionally or not, below 30°C. 

Hydrate formation is possible only at temperatures less than 35°C when the pressure is less than 100 bar. Hydrates are a nuisance they are capable of plugging (partially or totally) equipment in transport systems such as pipelines, filters, and valves they can accumulate in heat exchangers and reduce heat transfer as well as increase pressure drop. Finally, if deposited in rotating machinery, they can lead to rotor imbalance generating vibration and causing failure of the machine. 

To avoid hydrate formation, it is necessary either to dry the stream, or to inject a substance that, dissolving the water, lowers its partial fugacity and, consequently, the temperature of hydrate formation. 

Calculation of the conditions of hydrate formation is generally accomplished by software employing the Parrish and Prausnitz (1972) model. It is difficult to predict the conditions by a simple method. 

Parameters of the simplified model for calculating hydrate formation temperatures. 

The average error of this simplified method is about 3°C and can reach 5°C. Table 4.22 shows an application of this method calculating the temperature of hydrate formation of a refinery gas at 14 bar. Table 4.23 gives an example applied to natural gas at 80 bar. Note that the presence of H2S increases the hydrate formation temperature. 

Table 4.23 Example calculation of the hydrate formation temperature for a natural gas at 80 bar abs. Result = 29.1 "C. ...

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. 

When a customer agrees to purchase gas, product quality is specified in terms of the calorific value of the gas, measured by the Wobbe index (calorific value divided by density), the hydrocarbon dew point and the water dew point, and the fraction of other gases such as Nj, COj, HjS. The Wobbe index specification ensures that the gas the customer receives has a predictable calorific value and hence predictable burning characteristics. If the gas becomes lean, less energy is released, and if the gas becomes too rich there is a risk that the gas burners flame out . Water and hydrocarbon dew points (the pressure and temperature at which liquids start to drop out of the gas) are specified to ensure that over the range of temperature and pressure at which the gas is handled by the customer, no liquids will drop out (these could cause possible corrosion and/or hydrate formation). 

The amount of processing required in the field depends upon the composition of the gas and the temperature and pressure to which the gas will be exposed during transportation. The process engineer is trying to avoid liquid drop-out during transportation, since this may cause slugging, corrosion and possibly hydrate formation (refer to Section 10.1.3). For dry gases (refer to Section 5.2.2) the produced fluids are... 

If produced gas contains water vapour it may have to be dried (dehydrated). Water condensation in the process facilities can lead to hydrate formation and may cause corrosion (pipelines are particularly vulnerable) in the presence of carbon dioxide and hydrogen sulphide. Hydrates are formed by physical bonding between water and the lighter components in natural gas. They can plug pipes and process equipment. Charts such as the one below are available to predict when hydrate formation may become a problem. 

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. 

If high wellhead pressures are available over long periods, cooling can be achieved by expanding gas through a valve, a process known as Joule Thomson (JT) throttling. The valve is normally used in combination with a liquid gas separator and a heat exchanger, and inhibition measures must be taken to avoid hydrate formation. The whole process is often termed low temperature separation (LTS). 

Aldehydes (including chloral hydrate) formates and lactates some esters chloroform and iodoform reducing sugars some phenols. 

Formation of silver mirror or precipitate of silver indicates reducing agent. (This is often a more sensitive test than I (a) above, and some compounds reduce ammoniacal silver nitrate but are without effect on Fehling s solution.) Given by aldehydes and chloral hydrate formates, lactates and tartrates reducing sugars benzoquinone many amines uric acid. 

Below 65°C, sodium iodide is present ia aqueous solutions as hydrates containing varyiag amounts of water. When anhydrous sodium iodide is dissolved ia water, heat is Hberated because of hydrate formation, eg, AH = —174.4 kJ/mol (—41.7 kcal/mol), when the dihydrate is formed. At room temperature, sodium iodide crystallizes from water as the dihydrate [13517-06-1/, NaI-2H2 02H2O, ia the form of colorless prismatic crystals. 

Anhydrous a-dextrose is manufactured by dissolving dextrose monohydrate in water and crysta11i2ing at 60—65°C in a vacuum pan. Evaporative crysta11i2ation is necessary to avoid color formation at high temperatures and hydrate formation at low temperatures. The product is separated by centrifugation, washed, dried to a moisture level of ca 0.1%, and marketed as a very pure grade of sugar for special appHcations. 

Because of hydrate formation, the sodium salts tend to be difficult to dry. Excess water over that of hydration is beheved to accelerate the decomposition of the xanthate salts. The effect of heat on the dryiag of sodium ethyl xanthate at 50°C has been studied (84) ... 

Although the ethyleneamines ate water soluble, soHd amine hydrates may form at certain concentrations that may plug processing equipment, vent lines, and safety devices. Hydrate formation usually can be avoided by insulating and heat tracing equipment to maintain a temperature of at least 50°C. Water cleanup of ethyleneamine equipment can result in hydrate formation even in areas where routine processing is nonaqueous. Use of warm water can reduce the extent of the problem. 

The basic piSTa values, which have to be considered as equilibrium values, including those of anhydrous and hydrated species, reveal a destabilizing inductive effect of the 6- and 7-methyl group towards 3,4-hydrate formation, as do also the 2-methylamino and 2-dimethylamino groups for additional steric reasons. If the cation of 2-aminopteridine did not add water its value would be about 1.6, arrived at by substracting from the piSTa 2.6 of the essentially anhydrous 2-amino-4,7-dimethylpteridine cation 0.3 for the 7- and 0.7 for the 4-methyl group. The difference between the observed value of 4.29 and the... 

A third alternative design is to ehill the gas and separate the water eontent. In this option, water and hydroearbon speeifieations may be satisfied simultaneously if the gas temperature is kept above hydrate formation. This option is the simplest proeess and most engineering studies have shown it to be the least expensive gas treatment method. 

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. 

The formation of hydrates downstream of the expander does not appear to be a problem in this faeility. The original design studies indieated that hydrates should not form with this pipeline gas above temperatures of 20°F. The downstream temperature was not expeeted to drop this low. In operation, the downstream temperature has been above 25°F most of the time and has not dropped below 20°F. This is with inlet temperatures normally above 65°F. There have been no indieations of hydrate formation downstream of the expander. Indeed, eleetrie power produetion has aeutually exeeeded the quantity estimated for all years of operation. 

The need for auxiliary heating is another factor that must be carefully evaluated. Due to the nature of the thermodynamic process, the gas discharging from an expander is at a much lower temperature than gas discharging from a regulator station operating within the same pressure bounds. If temperatures downstream of the expander are allowed to drop too low, potential problems may arise, such as hydrate formation and material compatibility. 

Methanol is frequently used to inhibit hydrate formation in natural gas so we have included information on the effects of methanol on liquid phase equilibria. Shariat, Moshfeghian, and Erbar have used a relatively new equation of state and extensive caleulations to produce interesting results on the effeet of methanol. Their starting assumptions are the gas composition in Table 2, the pipeline pressure/temperature profile in Table 3 and methanol concentrations sufficient to produce a 24°F hydrate-formation-temperature depression. Resulting phase concentrations are shown in Tables 4, 5, and 6. Methanol effects on CO2 and hydrocarbon solubility in liquid water are shown in Figures 3 and 4. 

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. 

Englezos, P., Kalogerakis, N., Dholababhai, P.D. and Bishnoi, P.R., 1987b. Kinetics of gas hydrate formation from mixtures of methane and ethane. Chemical Engineering Science, 42(11), 2659-2666. 

The two major conditions that promote hydrate formation are (1) the gas being at the appropriate temperature and pressure, and (2) the gas being at or below its water dew point with free water present. For any particular composition of gas at a given pressure there is a temperature below which hydrates will form and above which hydrates will not form. As the pressure increases, the hydrate formation temperature also increases. If there is no... 

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. 

This chapter discusses the procedures used to calculate the temperature at which hydrates will form for a given pressure (or the pressure at which hydrates will form for a given temperature), the amount of dehydration required to assure that water vapor does not condense from a natural gas stream, and the amount of chemical inhibitor that must be added to lower the hydrate formation temperature. It also discusses the temperature drop that occurs as gas is expanded across a choke. This latter calculation is vital to the calculation of whether hydrates will form in a given stream. 

The next chapter discusses the use of LTX units to melt the hydrates as they form, and the use of indirect fired heaters to keep the gas temperature above the hydrate formation temperature. Chapter 8 describes processes and equipment to dehydrate the gas and keep free water from forming. 

---