Summary
Throughout a well's lifetime, formation damage can occur during the
activities of drilling, completion, injection, or well-stimulation treatments.
Typically, remedial treatments to restore the well performance involve
injection of reactive fluids capable of removing such damage. Therefore,
understanding damage mechanism and type is critical for fluid selection and
effective treatment design. Without this knowledge, the conducted stimulation
treatment could cause a more-severe form of formation damage.
This report discusses the improper use of mud acid [at 9 wt% hydrochloric
acid (HCl)/1 wt% hydrofluoric acid (HF)] in restoring the injectivity of Well
N-510. The subject well was stimulated with two acid-stimulation treatments in
an attempt to improve the poor results of a previous cleanout job, conducted to
remove mud filter cake. These treatments were designed to remove the damage
that has been limiting the well injectivity. However, it was found that these
acidizing treatments created a new formation damage that resulted in the severe
decline of well injectivity.
Integration of chemical-analysis techniques performed on return fluids and
coreflood experiments was used to assess the effectiveness of all conducted
treatments. This report demonstrates the techniques used to identify the source
and type of formation-damage mechanism that occurred during each treatment. On
the basis of these studies, it was found that the poor results of the cleanout
job were caused by precipitation of calcium sulfate. This precipitation was a
result of the mixing between spent cleanout acid, having a high amount of
calcium, and the high-sulfate-content water. Most of this precipitation
occurred in the wellbore vicinity during the preceding stages of the well
flowback.
Calcium sulfate precipitation had a negative impact on the performance of
the conducted acid-stimulation treatments. In the presence of this
precipitation, the two successive mud-acid-stimulation treatments created
another form of damage (i.e., in-situ fluoride-based scale). Initially, the
fresh injected mud acid dissolved most of the calcium sulfate scale, and as a
result, it contained a high amount of dissolved calcium ions. However, upon the
spending of injected mud acid in the formation, calcium fluoride precipitated
as a result of the increase of solution pH value.
The interactions between different acid systems and the constituents of the
downhole environment, resulting in the precipitation of calcium sulfate and
calcium fluoride, are discussed. In addition, this report provides recommended
modifications for future stimulation treatments, conducted under similar
conditions, so as to prevent the formation of these scales.
© 2012. Society of Petroleum Engineers
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History
- Original manuscript received:
21 June 2011
- Meeting paper published:
8 June 2011
- Revised manuscript received:
5 September 2011
- Manuscript approved:
10 September 2011
- Published online:
25 April 2012
- Version of record:
12 September 2012
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