Abstract

This paper discusses the more significant advances in hydrate control technology in the past twenty years. It also presents a comparison of four of the more widely used methods for predicting the water content of natural gas hydrates and comments on their limitations.

Some development is reported on the problem of controlling and preventing hydrate formation in offshore wells and onshore Arctic completions. Control techniques commonly used in these areas comprise variations on long-established practices such as application of heat, lowering system pressure, at least a partial dehydration of gas and/or liquid phases, addition of inhibitors, and purposeful formation of gas hydrates followed by their entrapment, decomposition and discharge of the water phase (known to many as the LTX system).

HISTORICAL BACKGROUND:

Although Sir Humphrey Davy first reported on hydrates of organic compounds in 1810, it was not until 1934 that Elmer G. Hammerschmidt1 described natural gas hydrates and their formation in natural gas transmission systems. A growing awareness of this problem led to extensive research or. several facets of gas hydrate formation by W.M. Deaton and E.M. Frost, Jr. of the USBM prior to World War II. These studies, though nearly complete, were interrupted by wartime activities and the results were not published until 1946 as USBM MONOGRAPH 8.2

These and other investigations established the nature of hydrate formation in multi component mixtures of hydrocarbons and water and the effect of other gases such as H2, CO2, N2 and H2S on hydrate formation by hydrocarbon gases. Methods were developed to calculate the equilibrium conditions of hydrate formation, or in essence to predict the conditions under which hydrate formation is likely to occur in any of several pure and multicomponent hydrocarbon gas systems. Hydrate forming conditions for a number of binary systems containing water and hydrocarbons or CO2 and H2S are shown by the equilibrium curves of Figure 1. Generally, each component has a critical temperature above which no hydrate of this compound is formed. This temperature corresponds to the point of intersection of the equilibrium hydrate-formation curve of the hydrate forming compound. The figure shows H2S with the highest critical temperature. Therefore, natural gas systems containing H2S form hydrates more readily than do gases of the same density without H2S.

By 1955, present-day technology had been developed and was in use by the petroleum industry. Several tenets were well-established, such as:

  1. Essential Conditions for Gas Hydrate Formation

    1. Favorable conditions of pressure and temperature of the gas.

    2. Presence of a liquid water phase.

    3. Thorough agitation between the phases.

  2. Methods for Preventing Gas Hydrate Formation

    1. Heating gas above hydrate formation temperature.

    2. Lowering gas pressure on the system.

    3. Dehydrate the gas to a level where no condensation occurs.

    4. Use of inhibitors to depress hydrate formation temperature.

    5. Use of the low-temperature separation process (LTX) which purposely forms hydrates by Joule-Thomson (J-T) expansion, separates them from the cold gas, moves them to a warm zone, and there hydrates are decomposed into hydrocarbons and water. The latter is discharged from the system.

  3. Inhibitor Choices

    1. Methanol

    2. Ethylene Glycol

    3. Diethylene Glycol

    4. Others, including triethylene glycol, amonia, calcium, chloride brine, oil field brines, heavier alcohols, and aqueous sugar solutions.

Keywords:
wax remediation, wax inhibition, scale remediation, Production Chemistry, flow assurance, oilfield chemistry, Upstream Oil & Gas, ethylene glycol, prediction, scale inhibition
Subjects:
Production Chemistry, Metallurgy and Biology, Flow Assurance, Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene, Hydrates
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1978. Society of Petroleum Engineers
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