Summary
It is generally assumed that scale-inhibitor squeeze treatments in
production wells are displaced radially into the formation because it is normal
to pump these treatments below the fracture pressure. However, it is known that
thermal stresses as a result of injecting cold fluids can result in thermally
induced fractures (TIFs). This paper addresses the evidence of thermal
fracturing during low-volume (less than 10,000 bbl) treatments, and asks: What
would be the impact on squeeze life of treating a well that was fractured
during treatment vs. a nonfractured well?
The process involves modeling fractured and unfractured treatments to
identify advantages and disadvantages of temporarily fracturing a well during a
squeeze treatment in terms of inhibitor placement. While inhibitor may be
placed at a greater distance from the wellbore if the formation is fractured
during the treatment, the surface area of rock contacted during the treatment
may be less than is the case in radial displacements. Issues such as
consolidated vs. unconsolidated formations, initial reservoir temperature,
fluid temperature at the sandface during injection, injection rate, and
fracture dimensions should be considered.
In general, this work demonstrates that there are clear advantages to
temporarily fracturing a well during a squeeze treatment, depending on the
inhibitor-return concentrations required to prevent mineral-scale
formation.
© 2011. Society of Petroleum Engineers
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History
- Original manuscript received:
18 October 2010
- Meeting paper published:
16 February 2006
- Revised manuscript received:
17 October 2010
- Manuscript approved:
5 February 2011
- Published online:
29 March 2011
- Version of record:
10 August 2011
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