Oil and gas producers in the US are required by law to cap and cap off their wells once they have finished producing. But a new survey of wells along the Gulf of Mexico coast indicates that there are 14,000 wells that are not producing, unlikely to return to service, and have their caps closed.
The bad news is that the estimated cost to cover them all would be in the neighborhood of $30 billion. The good news is that in most cases one of the major oil companies will be responsible for these costs.
Put a cork in it
The fundamental risk of uncovered wells is that material will not necessarily stop coming out when the equipment to which the well was connected is turned off and removed. An obvious potential problem is the continued leakage of hydrocarbons. Light material such as methane and simple hydrocarbons are usually consumed by microbial life, which converts it into carbon dioxide which usually finds its way into the atmosphere. More complicated molecules will be insoluble and will remain as a contaminant.
But other contaminants can also come from wells, including salty brines. If they escape from the well, they can contaminate drinking and agricultural water supplies by seeping into sediments.
Usually this is handled by filling the upper portion of the borehole with cement plugs. Once that is done, the top sections of the pipes will be cut off and the site will be abandoned. In general, this process is required by law. Federal lands and waters are governed by rules that ensure that the lease on a site expires one year after production ceases; the operator then has another year to close the well. State laws vary in details, but generally follow the same principle: Once wells have passed a period of no production, their owners have a limited amount of time to cover them.
The risk of these systems arises from the possibility that a company can avoid the cost of hedging by transferring ownership of the wells to a company that then goes bankrupt. But that’s not really an option for federal leases where, if the owner of a well goes bankrupt, the liability is split between all previous owners.
In deep
So, how many wells are not yet capped? To find out, a team of researchers focused on oil and gas producers along the coast of the Gulf of Mexico (states of Alabama, Louisiana, Mississippi and Texas). Using a combination of private company sources and government data, they identified the production history of offshore wells, along with those in coastal areas such as marshes and shallow bodies of water.
They identified more than 82,000 individual wells, of which only 6,500 are actively producing. The majority (64,000) are already capped and retired. But there are still more than 14,000 wells that are not currently producing and have no permanent cap. (About 3,500 of those have a temporary cap.) While some of these wells may be revived due to changes in technology or fossil fuel prices, that’s quite rare. Based on data from wells in federal waters, the researchers find that less than 4 percent of wells that have been idle for five years ever return to production.
The complexity of closing a well increases significantly with the depth of the water in which it is located. The good news here is that most of the wells — 85 percent of them — are in shallow water. For these wells, the average cost is about $660,000 for every foot of water they are in, with a total aggregate liability of $7.6 billion dollars.
However, despite being outnumbered, the deepwater springs are where the costs pile up. Here, the average cost of decommissioning and capping is more than $1 million per foot of water, so the roughly 1,600 deep-water wells ready for closure would cost about $35 billion to decommission. Limiting things to wells that are currently idle results in a total cost of about $30 billion.
Of course, if these are orphaned wells where the responsibility lies with a long-gone company, it can be difficult to actually cover them. But given the federal rules on liability, it’s not too bad. The researchers say 87 percent of offshore wells were owned by one of the major oil companies (things like Exxon and Chevron); Exxon could have paid for hedging every idle well last year and still had a profit of more than $80 billion.
However, that raises a very obvious question: If capping the wells is required by law, and the companies can easily afford to cap them, why don’t they? One explanation is that while the supermajors could end up in trouble because of past ownership, they are not the current owners, and those current owners may not be as well positioned financially to pay for decommissioning. Another possibility is that forcing someone to follow these rules requires the federal government to enforce them, and its willingness to do so likely changes depending on which administration is running things.
Nature Energy, 2023. DOI: 10.1038/s41560-023-01248-1 (About DOIs).
