Page 148 - Handbook Of Multiphase Flow Assurance

144 5. Flow restrictions and blockages in operations

Heavy oil
Heavy oils have asphaltenes stabilized by other molecules. When light oil or condensate
is added, the solubility of lighter resins in heavy oil changes and asphaltenes can flocculate.
3
Light oils (reservoir fluid density below 0.75 g/cm ) are more likely to have asphaltene
instability (pose high risk) than heavy oils.

Role of asphaltenes in microbubble capture
Asphaltenes are polar compounds and adsorb on microbubbles of water. This leads to
stabilization of water-in-oil emulsion.
An early warning of an imminent asphaltene issue is an increase in emulsion stability in
separators if nothing else changed. Precipitated asphaltenes stabilize emulsions. As the as-
phaltenes precipitate in the separator, they can also precipitate and deposit in other parts of
the production system.

Asphaltene precipitation and deposition in wells and pipelines

If the upper asphaltene instability envelope on the pressure-temperature phase diagram is
crossed while oil is flowing in the pipeline, then asphaltenes will precipitate there. Although
precipitation does not necessarily lead to deposition, it usually does.
Asphaltenes deposited in the pipelines need to be removed by routine maintenance scrap-
ing. If this is not or cannot be done as in single flowline tiebacks, the deposited asphaltenes
may lead to accumulation of other solids such as waxes or hydrates or sand, depending on
conditions. Asphaltenes cannot be removed by heating, and solvent soaks require large quan-
tities of solvent and downtime.
Asphaltene dispersant chemicals, if successfully identified and selected for a given crude
oil, may be useful in reducing the need for scraping. However, the effectiveness of asphal-
tene dispersants is still not as certain as for scale or hydrate inhibitors, and require further
research.
Thus the single unscrapable flowlines may be a poor choice for asphaltene-prone crudes
unless a service pipeline is available for periodic deployment of aromatic solvent for deposit
removal, and field economics allow for a regular downtime for solvent soaks.
The profile of an asphaltene deposit in a wellbore was reported with depth and time by
Haskett and Tartera (1965). The variation of asphaltene deposit thickness in a well tubing
with depth and time is approximately redrawn from their work as shown in Fig. 5.28.
One important parameter from this work is the time it takes to plug the well with as-
phaltenes. While few months is a relatively short time, it is still longer compared to days it
takes for a scale to plug production or hours for a hydrate.
This parameter, time to form a blockage, may be used to help an operator distinguish
between the nature of blockages. The longest time to form a plug is wax, which may take
months to years to form a complete blockage.
Other reports such as (Kabir et al., 2001) show asphaltene deposition characteristics.