Reducing the Risk of Shutting in Wells: Part 1

Turning the valve to shut in a well is trivial, but the implications of the decision are not. Even worse the range of uncertain outcomes skews to the negative; wells rarely become more productive from a shut-in, but they can certainly be damaged.

While short shut-ins persist as a common fact of life, the operations engineer strives not to shut in wells. Though everyone knows anecdotally that shutting a well in for an extended period risks its future production, the cautionary tales often lack a clear diagnosis. What experience we do have leaving wells shut in usually occurs at the end of the economic life, when there is nothing concrete to study or to preserve. Combined, these facts make us often casual about shutting in a well, superstitious against leaving it shut in, and largely flat-footed about how best to protect it when we do. Even the petroleum engineering literature offers only a handful of on-point papers in its master database of over 200,000 studies.

My own experience, analysis and research, incomplete as they necessarily are, have fleshed out three classes of risks--contractual risks, mechanical risks and risks to future recovery--after the decision to shut-in.

The economics of shutting in a well are simple enough: It should produce as long as it pays its unique costs and helps to cover shared costs, or maybe a little longer to avoid long shut-ins and to hope for a price improvement. Though the unprofitable well it unlikely to be plugged (on account of its option value and the cost of plugging), it is often not proactively preserved.

Doing the right thing the wrong way is still wrong.

Contractual risk from the shut in usually sits front and center, particularly mineral lease contracts which can trigger the loss of the right to produce from the well or the lease. The list of potentially-impacted contracts runs all the way through the business: equipment rentals like compressors and pumps at the wellheads, midstream contracts with costs variable with throughput or minimum volume commitments, joint operating agreements, and hedges (though obviously not when they are $60 /bbl in the money) and other pre-sales. Whatever they are, the contractual risks can be known precisely and mitigated directly, especially when systems exist to create a holistic picture from a database query. Mechanical risks and reserve risks aren't so cut and dried, even evading quantification.

Mechanical risks mean that the artificial lift may not work as well or that a leak may develop. In the same way that an airplane engine accumulates "hours" of use while sitting in the hangar, oilfield equipment can deteriorate as bad or worse while sitting idle. In my inexpert observation, ESPs need to be removed from the wells while other forms of lift may not necessarily require pulling. Either way, wells and even surface lines and equipment can be protected by "pickling" them with a chemical cocktail held under a little pressure. The pressure serves to alert the operator when there is a leak, while the cocktail unique to the chemistry of the well does the actual protection. It includes corrosion inhibitor, but it may also include scale inhibitor, paraffin inhibitor, oxygen scavenger, salts or other clay-stabilizers, and perhaps some kind of surfactant.

If you have any more wisdom to share about these issues, please share in the comments below. What I know for sure is that especially in crisis like today, an operator needs to have done his research and needs to have information about all his wells' status and history at his fingertips.

(This article continues in Part 2 which relies on my own expertise and research to lay out the issues around reserve risk.)