Summary
Organic inhibitors (e.g. methanol, ethanol, ethylene glycol, and triethylene
glycol) are generally used to reduce the risk of gas hydrate formation in
drilling and production operations. The addition of organic inhibitors has a
significant adverse effect on the solubility of salts, increasing the risk of
salt deposition. A better understanding of salting-out problems is necessary
for effective design and implementation of flow assurance strategies in such
complex systems.
In this paper, we present an experimental investigation on the effect of
methanol, ethanol, and ethylene glycol on the solubility of several salts,
including halite, sylvite, and antarcticite. The results show that ethylene
glycol has a much lesser adverse impact on salt deposition than methanol and
ethanol. The details of an experimental setup used for measuring salt
solubility and salting out are described. The setup could also provide valuable
information on the effectiveness of various inhibitors used for preventing salt
deposition in the presence or absence of gas hydrate organic inhibitors.
In addition, a novel predictive numerical approach is proposed to model salt
formation in brine solutions with or without hydrate organic inhibitors. The
model is based on the equality of the fugacity of salt in the solid phase and
aqueous phase, which are calculated by an equation of state. The validity of
the new developed model is demonstrated over a wide temperature range (i.e.,
–20 to 125°C), salt concentration up to saturation point, and hydrate inhibitor
concentration up to 50 mass%.
Introduction
Flow assurance is an essential aspect of safe and economical production of
hydrocarbons over the lifetime of a field. Gas hydrate and scale control
are two of the key aspects of flow assurance.
Gas hydrates, or clathrates, are icelike crystalline compounds consisting of
low molecular diameter gases inside cavities formed by water molecules, which
can form at certain pressure and relatively low temperature conditions. Gas
hydrate formation is particularly troublesome for offshore drilling and
production because of low seabed temperature, high residence time, and high
operating pressure. Hydrates can block pipelines and subsea transfer lines and,
in the event of a gas kick during drilling, form in the wellbore, risers,
blowout preventers (BOPs), and choke lines (Barker and Gomez 1989). Common
practice for preventing gas hydrate formation involves the injection of a large
quantity of thermodynamic inhibitors (e.g., methanol, ethanol, ethylene glycol,
or triethylene glycol). However, the addition of organic inhibitors may
adversely affect salt solubility in the associated brine solutions, which often
contain high concentrations of dissolved minerals, leading to potential salt
precipitation, commonly termed “salting out” (Kan et al. 2002; Matthews et al.
2002). The deposition of salt may result in flow restriction due to salt-plug
formation, as well as hydrate formation (as a result of neglecting the effect
of salt deposition on reducing the overall hydrate prevention characteristics
of the system).
In the open literature, there is a little information on the solubility of
mineral salts in hydrate organic inhibitor/water/salt solutions, which is only
applicable to the studied systems and limited range of temperature and pressure
(Kan et al. 2002; Tomson et al. 2003; Masoudi et al. 2004a; Pinho and Macedo
1996), and no accepted methodology for correlating the effects of hydrate
organic inhibitors on scale formation/inhibition. Therefore, a better
experimental and theoretical understanding of the salt formation as a function
of both electrolyte and organic inhibitor concentrations in the presence or
absence of scale inhibitors over a wide range of temperature and concentration
is crucial to the success of any flow assurance strategy.
The work in this communication is the result of a systematic experimental
and modeling investigation on the effect of three hydrate organic inhibitors
(i.e., methanol, ethanol, and ethylene glycol) on various mineral salt
solubility (i.e., halite, sylvite, and antarcticite) over a wide range of
temperature and concentration. The applied experimental setup and its
capability in determining salt solubility data in the presence or absence of
hydrate organic inhibitor are first described. The development of a new
thermodynamic approach capable of predicting salt formation in electrolyte
solutions with or without hydrate organic inhibitors is then detailed for the
studied systems in this work.
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
28 June 2004
- Revised manuscript received:
20 August 2005
- Manuscript approved:
22 August 2005
- Version of record:
20 May 2006
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