Page 146 - Handbook Of Multiphase Flow Assurance

142 5. Flow restrictions and blockages in operations

Asphaltenes can also alter reservoir effective permeability if more viscous emulsions with
water are stabilized by asphaltene particles, without asphaltene deposition on rock pores.
Asphaltenes may become unstable and precipitate from oil in the wellbore. This usually
occurs after the reservoir pressure drops substantially so that produced fluid enters the upper
asphaltene instability envelope while it is in the wellbore. This may also happen during a
temporary high well drawdown condition.
Destabilized asphaltenes precipitate and may deposit on tubing wall or in SCSSV down-
hole valve. Removal of deposited asphaltene has to be done either by dispersant chemical,
if effective in laboratory tests, or by solvent soak with toluene or another aromatic solvent.

Prediction of asphaltene risk

A quick screening for asphaltene precipitation may be done using SARA analysis of crude
oil which subdivides the oil into four groups: saturates, aromatics, resins and asphaltenes.
Laboratories have a detailed sequence of solvents used to determine the SARA fractions as
each one has its own solubility characteristics. Asphaltenes are stabilized by resins and are
soluble in aromatics, so a higher content of resins and aromatics will reduce the risk of as-
phaltene precipitation.
Oil is considered stable and have low asphaltene risk if either the Resin/Asphaltene ra-
tio > 10 or Aromatics/Saturates ratio > 2.
A similar method for asphaltene stability derived from the Hirschberg model (Hirschberg
et al., 1984) is known as deBoer plot which compares reservoir fluid undersaturation and den-
sity. Asphaltenes are generally stable (pose low risk) if the undersaturation, calculated as the
difference between the initial reservoir pressure and the bubble point pressure is <5000 psi or
3
if the live oil density is >0.75 g/cm (not the stock oil density).
Both the SARA ratios and the deBoer plot are qualitative only and may serve as a prelimi-
nary indicator of the asphaltene risk.
Laboratory tests are more reliable in identifying the conditions of asphaltene instability
and the rate of asphaltene deposition.
Asphaltene onset pressure can be measured by isothermal depressurization of a live oil
sample in a visual cell in infrared light. As oils are translucent to infrared light, a camera can
detect the appearance of solids as pressure goes below the upper instability envelope.
If several asphaltene onset pressures are measured at different temperatures, the asphaltene
instability phase envelope may be constructed to find pressure and temperature conditions
where the risk of asphaltene precipitation is minimal, and possibly design the production
system to avoid entering the asphaltene instability conditions.
Core flood test can predict the conditions and rate of formation damage due to asphaltene
plugging of rock pores.
Laboratories should also be used to check the effectiveness of asphaltene inhibitor or dis-
perant chemicals. The chemical testing process requires adequate amount of oil samples, so
the exploration well sampling program should be planned with anticipation of such needs.
Wang and Buckley (2001) have developed asphaltene instability test (ASIST) method
which allows to rely on laboratory measurement of asphaltene instability in stock oil by mea-
suring refractive index, capillary tube flow pressure drop, near infrared light scattering or
microscopic observation at atmospheric pressure to predict instability at other conditions.