Iranian officials often speak about oil as if the only question were whether crude can be sold today or tomorrow. In that telling, if exports stop, the oil simply stays underground until sanctions or a blockade ease, after which production can resume from where it left off.
Oil Minister Mohsen Paknejad said earlier this month that Iran’s oil exports did not stop “even for an hour” during the 40-day war. He had previously said there was not even a single day of production decline during that period.
Even if those claims are accurate for the war itself, they do not answer a more important question about what followed: how much production must be shut in when exports collapse and storage fills, and what will it cost to bring those wells and facilities back?
Energy intelligence firm Kpler estimated Iranian oil loadings fell from about 1.83 million barrels per day in March to around 255,000 bpd in August. It also estimated crude production dropped from about 3.24 million bpd to 1.755 million bpd, while inventories at terminals, refineries and other onshore storage sites increased.
Some Iranian crude may still be discharged in China, but much of that oil had already left Iran before the blockade intensified and remained for a time on tankers in Asian waters. Selling those cargoes is not the same as moving fresh crude out of Iranian wells and export terminals.
When exports fall, producers can initially divert crude into onshore storage, refineries and tankers. But storage is finite. Once it fills, the pressure moves upstream, forcing the National Iranian Oil Company to reduce production from some wells or shut them altogether.
An oil field is not an underground warehouse
An oil reservoir is sometimes imagined as an underground lake that can simply be tapped, closed and reopened months later.
In reality, oil sits within porous rock and networks of natural fractures. Its movement toward a producing well depends on reservoir pressure, rock properties, fluid composition and the way the field is managed.
That means shutdowns do not affect every well in the same way.
Some conventional Middle Eastern reservoirs can tolerate short shutdowns without serious damage. In certain fractured reservoirs, temporarily reducing output may even allow pressure to recover and oil to migrate from the rock matrix into fractures.
Robin Mills, a researcher at Columbia University’s Center on Global Energy Policy, has argued that production shutdowns are unlikely to cause catastrophic or permanent damage across most of Iran’s oil industry.
He has pointed to Iran’s relatively rapid production recovery after previous declines caused by sanctions and the Covid-19 pandemic.
That distinction matters. There is little basis for claiming that shutting production will inevitably destroy Iran’s oil wells.
But recoverable does not mean free, immediate or risk-free.
Iran has many mature fields and aging wells. Ahvaz, Marun, Gachsaran and Aghajari, among the country’s most important producing areas, have been in operation for decades.
Low-pressure wells, or wells producing large volumes of water alongside crude, may fail to flow naturally after a prolonged shutdown. Restarting them can require pumping, nitrogen injection, chemical treatment or other well-servicing operations.
During a shutdown, mineral scale, asphaltenes and other heavy compounds can accumulate around the wellbore, in production tubing or in flow lines.
Corrosion, sand and solids deposition, pump failures and unwanted flows between zones with different pressures are also recognized risks.
An analysis by the Society of Petroleum Engineers’ Reservoir Advisory Committee on prolonged shut-ins warned that corrosion, deposits, pump damage and plugging can leave some wells requiring repairs, stimulation or recompletion before they return to production.
For weak-performing wells, remediation can also become expensive enough to call their economics into question.
None of those costs appears in a simple calculation of barrels that were not sold.
Rotating shutdowns also cost money
NIOC has experience managing production cuts during earlier rounds of sanctions.
One option is to rotate shutdowns among wells rather than take an entire field offline, reducing the amount of time any single well remains idle.
That can limit the risks, but it requires continuous monitoring of reservoir pressure, fluid composition, gas injection, corrosion, pumps and surface facilities.
Repeated shutdowns and restarts, changes in chemical injection and the recalibration of processing equipment also add to operating costs.
In other words, not producing oil still costs money.
If falling oil revenues squeeze maintenance budgets, what begins as a manageable shutdown can develop into a far more expensive repair problem.
The question is therefore not whether every shut well will be lost. It is how many will return without additional work, how long the others will take to restart and how much that process will cost.
Gas injection links the oil problem to Iran's gas crisis
Many of Iran’s mature oil fields rely on gas injection to maintain reservoir pressure and improve recovery.
Kpler has estimated historical gas injection into Iranian oil fields at about 4.8 billion cubic feet per day. Even before the current crisis, Iran was injecting less gas than its reservoirs required.
That problem could become more acute.
Gas production from South Pars also produces condensate. If Iran becomes unable to export, store or consume enough of that condensate, it may eventually have to reduce gas output.
The government would then face harder choices over how to allocate gas among households, power plants, industry, exports and injection into oil reservoirs.
Lower gas injection does not destroy a well overnight. But over time, it can reduce reservoir pressure and potentially lower ultimate oil recovery.
A crisis that begins with crude exports can therefore feed back into oil production through constraints on condensate and natural gas.
This part of the cost rarely features in official statements.
Iranian officials emphasize continued exports and efforts to circumvent restrictions, but disclose little about how much gas, equipment and investment is needed to maintain reservoirs while production is being curtailed.
Shared fields create another risk
Not all Iranian fields can be treated in the same way.
Azadegan and Yadavaran are shared with Iraq, Forouzan with Saudi Arabia and Salman with the United Arab Emirates, with production taking place from different parts of connected geological structures.
A reduction in Iranian output does not mean crude immediately flows across a border toward a neighboring country’s wells. Reservoir behavior is more complicated and depends on geology.
But if Iran reduces production and development for an extended period while the other side continues drilling and extracting oil, Iran’s economic position in those shared resources can weaken.
Oil left underground in such fields is not necessarily being preserved exclusively for Iran to produce later.
Continued extraction across the border can, in some reservoirs, reduce Iran’s future recoverable share or economic opportunity.
The real cost of shutting production
The impact of a forced production cut cannot be measured by lost sales alone.
It also includes the cost of storing crude, maintaining idle wells, carrying out repairs and restarts, any loss in future productive capacity or reservoir recovery, and missed opportunities in shared fields.
There can be broader consequences as well.
Lower gas production would put more pressure on power generation, petrochemical feedstock and industrial consumption, forcing the government to make increasingly difficult choices over scarce energy supplies.
A prolonged blockade and collapse in exports therefore affects more than the Islamic Republic’s immediate oil revenue.
If wells and facilities are not adequately maintained, part of the cost can persist long after exports recover.
Paknejad can point to uninterrupted exports or production during a limited period, but more important questions remain unanswered.
How many Iranian wells are now producing at full capacity? How many have been throttled back or shut? How has gas injection changed? How much is being spent to manage shut-ins, maintain equipment and eventually restore production?
Without those figures, claims of continued production offer only a partial picture of the state of Iran’s oil industry.
Most Iranian wells may eventually be recoverable. But shutting them is neither cost-free nor necessarily quick to reverse.
The longer production remains constrained, the more maintenance, reservoir management and restart costs may accumulate — costs whose full scale cannot be known without far greater transparency about the condition of Iran’s wells and fields.
