TOPIC 2: Oilfield Scale
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The type of chemical required for
a particular scaling problem, in either a
vertical or a horizontal well, must be selected based on the following:
The specific mineral scale to be inhibited
The type of scale inhibitors which will give effective control of sulphate and
carbonates scales include phosphonates, phosphino carboxylic acids (PPCA),
carboxylic acids, vinyl sulphonate co-polymers and poly vinyl sulphonate
(PVS).
Compatibility with the produced brine chemistry
The scale inhibitor may be incompatible with the
produced brine leading to
precipitation of an inhibitor-cation complex. In particular, the concentration of
divalent cations has a significant bearing on the compatibility of scale
inhibitors,
when used for squeeze, continuous injection, and topside
applications; chemicals such as poly vinyl sulphonate (PVS) and sulphonated
co-polymer have high divalent ion compatibility.
Low pH phosphonates have moderate compatibility,
but partially neutralised
polymers and phosphonates may have very poor compatibility when a 5% to
10% scale inhibitor solution in seawater is mixed with the formation water.
In a vertical well, such problems can be reduced by the application of a
seawater preflush containing 500 ppm to 1000 ppm scale inhibitor. This
pushes the formation water away from the near wellbore region and prevents
the high concentration slug from mixing with the formation water.
This type of preflush strategy has been used with considerable success in
vertical and deviated wells. However, it may be very difficult, if not impossible,
to apply such a preflush in horizontal wells.
There are significant differences in the types of scaling problem – their
practical treatment strategy will depend on the
type of well which is to be
treated. A possible way forward when considering the implication of recovery
methods and well design would be to carry out the following studies:
1. Evaluate the levels of the selected scale inhibitor in order to determine
the minimum inhibitor concentration (MIC) required to prevent
carbonate and/or sulphate scale.
2. Determine which chemicals have suitable compatibility in the formation
brine.
3. Carry out a limited core flood study (using the chosen product from
steps 1 and 2) in order to better assess issues of formation damage
and the expected squeeze lifetime.
4. Carry out a modelling study to design the initial squeeze treatments in
this formation.
From this information, it should be possible to make a
more informed prediction as to the likely squeeze lifetimes and the
required frequency of treatment. This information will have significant
implication for the type of well design.
TOPIC 2: Oilfield Scale
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NIVERSITY B41OA December 2018 v3
In summary, the last few sections have discussed:
•
The types of carbonate and sulphate scales which may be expected in
oil reservoirs, why these occur and how they may be predicted in order
to make as assessment of the severity of the scaling problem.
•
Several issues surrounding how the reservoir recovery mechanism and
the well configuration may influence the scaling problem – in terms of
the severity of scale formation, the accessibility of the scale deposition
problem and in the ease of treating the scale problem.
•
The use of scale inhibitors in the prevention of scale for both downhole
and topside treatments (which are related).
In this section, these issues are covered in an introductory manner in order to
help those who may be unfamiliar with the subject.
In later sections, much
more detail will be given, in terms of both chemical and field operational
matters, as they relate to scale prevention and removal.
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