Formation damage problems in the Brutus A-8 well in the Gulf of Mexico have provided a rich opportunity to study mechanisms of pore plugging. Field data and laboratory experiments have led to the following conclusions.
Unexpected reactions can take place between spent organic acids and completion brine, resulting in polymerization and other reactions that can plug formations.
These precipitates can be prevented by appropriate acidizing practices, including the use of sufficient (ammonium chloride or other innocuous brine) spacers to maintain separation of the (spent) acid and completion brine and the use of an appropriate post-flush acid to maintain a low pH in the spent acid.
If a precipitate does form, it can be cleaned up readily by acid treatment if the acid reaches the occluding precipitate.
Organic acids should not be mixed. That is, if completion uses one organic acid, no other organic acids should be used in subsequent stimulation treatments.
Well A-8 on the Brutus platform was completed in September, 2001, using a high rate water pack, with acidization of the perforations using an organic acid/HF generating mixture. Organic acid was chosen over the more conventional HClHF treatment because the formation contained about 5% zeoilites, in the form of clinoptilolite; an important point to note is that, as with most acid treatments, in general, and with this and other acid treatments in this well, in particular, only about 40–50% of the stimulating fluid was recovered during flowback. A considerable volume of 13.6 ppg (1.63 s.g.) calcium bromide completion brine, about 2000 bbl, was lost during completion. Within a few weeks of initiation of production, production had declined to such an extent that intervention was required. Stimulation with the same acid system used in the completion resulted in only a short-term improvement. After a couple of weeks, an ammonium chloride flush was done, with similar results. After another couple of weeks, another stimulation effort was made, this time with another organic acid, with an immediate reduction in production of 75%. Since lab tests indicated that subsequent acid treatments would be unsuccessful, the well was re-completed using a different philosophy, with much better results.
Flowback from the first remedial treatment provided many surprises (Figure 1), among them the following:
the presence of a fluffy white precipitate in the last few samples before the water cut diminished to5%, the cutoff before full production was begun;
a red color;
high solubility of the white solid in seawater, as discovered when rig personnel washed off the solids filter with a stream of seawater;
a pH of 3.5 in the flowback fluid;
high concentrations of the organic acid and calcium bromide, with the ratios suggesting the presence of both free acid and its calcium salt in approximately equal abundance; and
a small amount of iron in the solution, about 50 ppm.