Natural Gas Hydrates

HYDRATE FORMATION AND

CONTROL

MR. KWAME SARKODIE

OUTLINE

GAS HYDRATE FORMATION

CONDITIONS FOR HYDRATE FORMATION

HYDRATE PROPERTIES

GAS HYDRATE FORMATION PREDICTION

HYDRATE INHIBITION METHODS


Natural gas hydrates are solid crystalline

compounds formed by the chemical combination

of natural gas and water under pressure and at

temperatures considerably above the freezing

point of water.

In the presence of free water, hydrates would form

when the temperature is below a certain degree

(hydrate temperature).

Chemical formulae of gas hydrates :

Methane CH4.7H2O

Ethane C2H6.8H2O

Propane C3H8.18H2O

Carbon dioxide CO2.7H2O

CONDITIONS FOR HYDRATES FORMATION

• Natural gas at or below its water dew point with

liquid water present.

• Temperature below the hydrate formation

temperature for the pressure and gas

composition considered.

• High operating pressures that increase the

hydrate formation temperature.

• High velocity or agitation through piping or

equipment.

• Presence of a small seed crystal of hydrate.

• Presence of H2S and CO2 since these gases are

more soluble in water than in hydrocarbons

HYDRATE BUILD-UP INSIDE A PIPE

PROPERTIES

Gas hydrates are a class of solid, non-stoichiometriccompounds called clathrates.

They form when a host material, water for hydrates through hydrogen bonding, forms a caged structure that contains guest molecules, such as methane.

Both host and guest must be present for the solid to form, but not all of the cages will be occupied.

HYDRATE FORMATION CONDITIONS FOR

PURE METHANE, ETHANE, AND PROPANE

The Figure above shows a break in all of the

curves at 32°F (0°C) because the hydrates are in

equilibrium with gas and ice at the lower

temperatures, and with gas and liquid water at

the higher temperatures.

For the ethane hydrate line, an abrupt change

occurs at 57°F (14°C).

At this point, the hydrate is in equilibrium with

gaseous ethane and both liquid ethane and liquid

water

At higher temperatures, the ethane hydrate is in

equilibrium with liquid ethane and liquid water


PREDICTION

There are three methods basically used in the

prediction of hydrate formation, they are:

K-values method

The gas gravity correlation

The use of computer programs.

In this lecture the gas gravity method would be

discussed.

The figure below shows hydrate formation prediction

curves for natural gases as a function of gas specific

gravity. For below 1,000 psi (70 bar), the figure can

be

t(°F) = −16.5 − 6.83/(SpGr)2 + 13.8 ln[P(psia)]

t(°C) = −6.44 – 3.79/(SpGr)2 + 7.68 ln[P(bara)]


PREDICTION

EXAMPLE

Estimate the hydrate-formation temperature at

325 psia (22.4 bar) for the gas with the

composition in the Table. Compare the results

from curve above and the Equation.

Solution

1. The specific gravity of the gas is calculated as

molar massgas /molar massair = 20.08/28.96 = 0.693.

2. Using the equation,

t = −16.5 − 6.83/(0.693)2 + 13.8 × ln(325) = 49°F.

3. The figure gives 50oF

GAS COMPOSITION

HYDRATE INHIBITION

Three ways exist to avoid hydrate formation in

natural gas streams:

Operate outside the hydrate formation region.

Dehydrate the gas.

Add hydrate inhibitors.

HYDRATE INHIBITORS.

The proper inhibitor dosage must be known to

avoid plugging or needless chemical costs, but

oftentimes it is determined empirically.

The chemical cost, although it is usually a small

fraction of overall operating costs

The reliability of inhibitor injection can be a

problem because of malfunctioning injection

pumps and depleted inhibitor reservoirs,

especially at remote sites.

The possible interaction between hydrate

inhibitors and other additives reduces the

effectiveness of some of additives, an effect that

is usually determined empirically.

HYDRATE INHIBITORS

Chemical hydrate inhibitors come in three types:

1. Antiagglomerates (AA)

2. Kinetic (KHI)

3. Thermodynamic

ANTIAGGLOMERATES

Antiagglomerates

prevent small hydrate particles from

agglomerating into larger sizes to produce a plug.

The inhibitors reside in the liquid hydrocarbon

phase and are most often used in pipelines where

gas is dissolved in oil.

They require testing to ensure proper

concentrations.

KINETIC INHIBITORS

Kinetic inhibitors slow crystal formation by

interfering with the construction of the cages.

advantage is that they can be used at

concentrations in the 1 wt% range in the aqueous

phase, and they are nonvolatile

disadvantage is that the proper dosage must be

determined empirically, as too much inhibitor

may enhance hydrate formation rates

THERMODYNAMIC INHIBITORS

Thermodynamic inhibitors, mainly methanol and

ethylene glycol, are widely used.

They are essentially antifreeze. Inorganic salts

are effective but rarely used, and further

discussion relates only to methanol and ethylene

glycol.

The required dosage of thermodynamic inhibitors

is predictable, but the concentrations can be high,

over 50 wt% of the water phase


A number of empirical correlations, on the basis

of thermodynamic properties of solutions,

predict the amount of any hydrate inhibitor

required to depress hydrate formation

temperatures.

The two most commonly used are discussed

here).

Hammerschmidt (1939) proposed the following

equation:


where

t is the hydrate-depression temperature,°F,

Xi is the mass fraction of inhibitor in the free-water phase,

and MWi is the molecular weight of the inhibitor.

• It is recommended to use this equation for methanol concentrations of 20 to 25 wt% of the water phase;

• It is also recommended to use the equation

for ethylene glycol concentrations up to 60 to 70 wt%.


Nielsen and Bucklin (1983) proposed

Δt(°F) = −129.6 ln Xw,

where Xw is the mole fraction of water in the

aqueous phase

METHANOL VS. ETHYLENE GLYCOL

METHANOL ETHYLENE GLYCOL

More volatile Less volatile

Less viscous (high vapour pressure) More viscous (lower vapour

pressure)

Difficult to recover (requires distillation) Easy to recover (evaporation by

water)

Widely used Less widely used

CONTRASTS

SIMILARITES

Both inhibitors

are hydrophilic and remain predominantly with a

condensed water phase, even if

a condensed hydrocarbon phase is present

Both toxic compounds and must be well treated and before

disposal.

EXAMPLE

A sweet gas with a specific gravity of 0.73 leaves

a gas−liquid separator at 100°F and 600 psia

saturated with water.

The gas drops to 35°F before reaching the next

booster station at 500 psia.

Assume no hydrocarbon condensate has formed

in the line.

Calculate how much methanol must be added to

prevent hydrate formation between the separator

and the booster station per MMscf.

Repeat the calculation for ethylene glycol, which

is added in an 80 wt% mixture with water.

SOLUTION

If the formation of hydrate is probable, then;

Determination of the inhibitor rate requires:

1. Determination of the amount of liquid water

formed

2. Calculation of the required amount of inhibitor

in the water phase

3. Calculation of the required amount of inhibitor

in the gas phase

PROBABLE HYDRATE FORMATION

Use of Equation or chart to predict probable

hydrate formation

Shows that the hydrate formation temperature at

600 psia is 59oF.

This value means a 59°F – 35°F = 24°F sub-

cooling into the hydrate region, and hydrate

formation is probable without inhibition.

THUS WE CARRY ON TO DETERMINE THE

INHIBITOR RATE

DETERMINATION OF THE AMOUNT OF

LIQUID WATER FORMED

From the chart below,

the water content of the gas leaving the separator is

95lb/MMScf and

13lb/MMScf at 35°F and 600 psia

Thus

95 lb – 13 lb = 82 lb of water per MMscf drops out in the

line, assuming worse-case conditions

DETERMINATION OF THE AMOUNT OF LIQUID

WATER FORMED

METHANOL REQUIREMENT

To estimate the concentration of methanol, rearrange

Nielsen and Bucklin Equation to give

ln Xw = −t(°F)/129.6 = −24/129.6 = −0.185

Xw = 0.831 or

XMeOH = 0.169 mole fraction.

In Wt %

= (0.169 × 32)/(0.831× 18 + 0.169 × 32) = 26.6 wt%

or 0.362 lb methanol/lb water

Thus, the methanol needed in the water phase is

0.362 × 82 = 29.7 lb/MMscf.

METHANOL IN THE VAPOR PHASE

To estimate the methanol in the vapor phase use the figure below which at 35oF and 600 psia, gives 1.22 lb methanol vaporized per wt% methanol in the aqueous phase,

or 1.22 × 26.6 = 32 lb methanol per MMscf

Thus, the vapor phase consumes more methanol than does the aqueous phase.

The total amount of methanol required

is (29 + 32) = 61 lb/ MMscf.

If a condensate phase was present as well, the losses estimated by use of the solubility chart would have to be added into that phase.

This amount of methanol will be much less than what goes into the aqueous and vapor phase in gas lines.

RATIO OF METHANOL-VAPOR COMPOSITION TO METHANOL-

LIQUID COMPOSITION.

SOLUBILITY OF METHANOL IN PARAFFINIC HYDROCARBONS AS A FUNCTION OF

TEMPERATURE AT VARIOUS METHANOL CONCENTRATIONS.

ETHYLENE GLYCOL REQUIREMENT

Use the Hammerschmidt Equation with the 2235

constant and a molar mass of ethylene glycol of

62 to obtain the mass fraction of pure glycol

required:

However, the glycol is diluted to 80 wt%. To

obtain the mass of inhibitor solution added per

unit mass of free water present to obtain the

desired concentration,

we use X0 /(X0 – Xi), where X0 is the weight

fraction of inhibitor in the solution to be added.

The amount of inhibitor solution added per

pound of free water initially present is then

0.8/(0.8 – 0.40) = 2.00,

and the total amount of ethylene glycol solution

added is 2.00 × 82 = 164 lb/MMscf.

At these conditions, glycol loss into the vapor

phase is negligible, so the total amount of

solution required is 164 lb/MMscf.

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Natural Gas Hydrates