OTC 2026: When does an idle well become too risky to restart?

Borrel: The most common integrity issues we see include tubular damage,  such as corrosion, collapse or mechanical wear, as well as wellbore debris, scale buildup and fluid leaks. These leaks can often result from damage to completion products (such as packers) or degradation in the cement sheaths responsible for providing zonal isolation.

What tends to be underestimated early on is the extent to which these issues can develop during periods of inactivity, particularly when wells are assumed to be in stable condition simply because they are not actively producing.

Offshore: What diagnostic data or assessments tend to be most decisive in determining whether a well can be safely restarted, versus cases where uncertainty still remains even after extensive evaluation?

Borrel: Data on the static condition of well construction components (completion hardware and cement integrity) provides a good baseline, particularly when there are no obvious symptoms of a problem.

However, when issues are suspected, such as potential leaks, dynamic data as a diagnostic tool becomes critical, including understanding fluid movement both inside and outside the wellbore. It is the fusion of these datasets that offers the best chance to resolve uncertainty and support informed restart decisions.

Offshore: Based on your experience, where do restart decisions go wrong most often: in understanding the condition of the well itself, the surrounding infrastructure or the assumptions made about historical operating envelopes?

Borrel: The condition of the well is often a key blind spot, particularly when wells have been shut in for some time. A shut-in well behaves very differently from a producing well; fluid levels, temperatures, pressures and chemical conditions all change when a well is shut in over time.

These changes, combined with the duration of inactivity, can lead to unforeseen issues, such as corrosion or scale buildup. In many cases, decisions go wrong when operators rely too heavily on historical assumptions rather than reassessing the well’s current condition.

Offshore: How do integrity risks differ between wells that were intentionally shut in and those that became idle due to disruptions, deferred maintenance or prolonged underinvestment?

Borrel: Wells that are intentionally suspended typically present lower initial risk, as they are more likely to have been shut in with a defined plan for reactivation or abandonment and may include temporary hardware designed for suspension, and therefore are likely to have been managed better.

However, from an integrity standpoint, many of the underlying risks to integrity remain similar across both scenarios. The condition of the well prior to shut-in, combined with the time elapsed and how the well was managed during that period, are often the most important determining factors in determining risk.

Offshore: From an integrity standpoint, what should trigger a clear “do not restart” decision, and why can delaying that call ultimately increase risk or cost?

Borrel: There will be many triggers for a “do not restart” decision, some pertaining to safety and environmental concerns, others relating to economics. The key to supporting that decision is having actionable data at the right time.

In well integrity, conditions do not improve with time; issues such as corrosion, degradation or leaks tend to worsen. Knowing when your well has passed its useful life is a data-driven determination. Delaying that call can increase both operational risk and cost over time.