MAY 1 — There have been weeks of naval blockade along the Iranian Gulf coast by the United States.
The maritime pressure on Iran is now pushing the country towards a far more dangerous threshold.
Millions of barrels of crude that would normally leave the country each day are instead backing up into onshore storage.
Its largest terminal, which handles roughly 90 per cent of Iran’s crude exports, Kharg Island, has only 12–13 days of usable capacity remaining.
Once the tanks are full, the problem is no longer simply that Iran cannot sell its oil, but that it may not be able to keep producing it.
The strategy behind the blockade by Donald Trump’s administration is clear and brutally simple: The real pressure begins when crude keeps flowing from the fields but has nowhere to go.
Blocking tankers at sea is only the first layer; the inner layer is to force Iran to shut in producing wells.
In fact, this is a very real problem for Iran, and obviously, the team behind the Trump administration clearly understands the natural characteristics of Iranian reservoirs far better than many expected.
This is not only a matter of stopping exports or creating short-term financial pain; it is a calculated pressure point aimed at the subsurface itself.
The reason forcing crude well shut-ins is an effective strategy is because, fundamentally, a crude reservoir is not a storage tank that can simply be switched off and restarted at will.
This handout image taken by the European Space Agency (ESA) captured by the Copernicus Sentinel-2 satellite shows a view of Iran’s Kharg Island, which hosts the country’s main crude export terminal. — AFP pic
Most of the major crude-producing fields, particularly in the southwest of Iran, such as Ahvaz, Marun and others, are mature carbonate reservoirs with strong dual-porosity characteristics – the natural rock fracture matrix that stores the crude, while also providing pathways for crude to flow towards the wellbore.
This system works only when reservoir pressure is carefully maintained.
After decades of production, many of these ageing fields have lost a significant portion of their natural pressure and rely heavily on continuous gas reinjection to sustain output and prevent rapid decline.
Once production is forcibly shut in, pressure redistribution inside the reservoir changes fluid movement and cool-down of liquids.
It leads to precipitation of asphaltene and halite clogging, a phenomenon in which precipitation of sodium chloride and calcium chloride may build up geostress, leading to the collapse of corroded wells.
Reopening these wells is therefore not as simple as reopening a valve.
Some crude wells may require major intervention, pressure support restoration, chemical treatment, or even expensive workovers to return to normal operation.
In general, depending on the duration of closure, reopening old crude wells normally sees a significant drop in production index (PI), which quantifies crude production.
Let’s carry out a general case study.
A mature Iranian onshore carbonate well producing 2,000 STB/d before shut-in (PI ≈ 2.5 STB/d/psi, water cut ~35 per cent), with a 12-month unmanaged shut-in, typically results in a 40–50 per cent permanent PI loss, driven by combined near-wellbore chemical reactions, including asphaltene precipitation, fines migration and scale deposition.
Using a mid-case 45 per cent PI loss, the restarted oil rate falls to ~1,100 STB/d, a loss of 900 STB/d (≈328,500 bbl/yr) compared to pre-shut-in levels.
Even with standard remediation such as acid stimulation and lift replacement, full PI recovery is rarely achieved in such reservoirs because the field experiences partial restoration, leaving a structural, long-term rate penalty.
This magnitude of PI degradation is consistent with long shut-ins in sour and mature carbonate wells.
Let’s look at the financial impact in a simple numerical simulation.
At an oil price of US$65/bbl, variable opex of US$12/bbl, 10 per cent discount rate, and seven years of remaining field life, the permanent rate loss from the 45 per cent PI degradation reduces annual net cash flow by approximately US$17.4 million/yr.
This is equivalent to approximately US$87 million of net present value (NPV) destruction from rate loss alone.
Adding deferred production value erosion from the 12-month shut-in (~US$4 million), restart capex for stimulation, electrical submersible pump (ESP) replacement, and integrity work (US$3 million), and incremental opex due to higher water handling and lift inefficiency, the total NPV impact approaches US$98 million per well.
In practice, this means that even if a well can be restarted successfully, the restart economics become negative unless the oil price is exceptionally high.
However, what is shown above is not the worst case.
In a multi-well plateau decline model, plateau loss is more economically catastrophic because the plateau of a field is a system-level outcome, rather than a simple aggregation of independent wells.
In a simple simulation, a 20-well mature carbonate field producing 40,000 STB/d suffers a one-year shut-in, inducing an average 45 per cent permanent PI loss across the wells.
When production restarts, each well can deliver only ~1,000 STB/d instead of 2,000 STB/d, collapsing the field plateau abruptly to 20,000 STB/d.
The loss of 20,000 STB/d is not a temporary decline but an irreversible step-down caused by near-wellbore damage, increased water and gas encroachment, as well as the loss of drawdown headroom that balances strong and weak wells.
Over the remaining five-year plateau window, approximately 33 million barrels of oil will never be produced.
Hence, at a net margin of US$53/bbl, the plateau collapse alone causes approximately US$1.3 billion in NPV, dwarfing ~US$70 million restart capex and higher opex, pushing total value destruction towards US$1.7 billion for the field.
This is a staggering economic loss as plateau barrels are high-rate, early-life barrels with the highest present value.
When PI degradation forces the field into a lower-rate regime, the operation changes from capacity-limited to reservoir-limited.
The field permanently forfeits its most valuable cash flow years.
As a practical rule of thumb, beyond 45 per cent PI loss, plateau recovery is practically impossible without infilling or massive lift upgrades.
The pressure campaign from Washington is not merely on seaborne crude exports, but on deeper vulnerabilities embedded in Iran’s reservoirs.
When sanctions and blockades force ageing and rate-controlled plateau wells offline, the damage is not unimaginable.
From the standpoint of strategy, time and patience are assets: Every additional month of constrained production quietly degrades the future revenue base.
As Iran diverts its limited resources towards deterrence and domestic stability, it lacks both the capital and operational freedom to protect reservoir integrity at scale.
Time is not on Iran’s side.
Iran may survive the sanctions and blockade politically, but its core economic engine is being structurally impaired by time.
*Phar Kim Beng is a professor of Asean Studies and director of the Institute of International and Asean Studies, International Islamic University of Malaysia. Jitkai Chin is from the Department of Chemical Engineering, Universiti Teknologi Petronas, and also expert committee member in Centre of Strategic Regional Studies.
** This is the personal opinion of the writer or publication and does not necessarily represent the views of Malay Mail.
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