An oil field does not have to run out of crude for its production to start falling.
In fact, declining production is a normal part of an oil field’s life. A reservoir may still contain millions of barrels underground while producing considerably less oil each day than it did at its peak.
The reason comes down largely to pressure, the movement of fluids underground and how easily the remaining oil can be recovered.
Reservoirs lose pressure over time
Oil is held within tiny spaces in porous rock, often thousands of meters beneath the seabed. When wells are drilled into a reservoir, differences in pressure allow oil and other fluids to move through the rock towards the wells and eventually to the surface.
But producing oil changes conditions inside the reservoir.
As hydrocarbons are removed, reservoir pressure can decline. The lower pressure generally means less natural energy is available to move oil towards producing wells. Production from individual wells therefore tends to decline over time. The US Energy Information Administration notes that declining reservoir pressure is one of the fundamental reasons oil and gas well production falls as wells age.
Operators use several techniques to counter this.
One is gas injection, where gas is reinjected into the reservoir to help maintain pressure and support continued oil recovery. Depending on the reservoir, the injected gas can also help displace oil towards producing wells. Water injection can serve a similar purpose, replacing some of the fluids withdrawn from the reservoir, supporting pressure and sweeping oil towards production wells.
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These methods can sustain production and improve the amount of oil ultimately recovered, but they cannot prevent decline indefinitely.
More water can eventually come up with the oil
Another challenge develops as a field matures.
Oil reservoirs commonly contain water as well as hydrocarbons. As production continues and injected or naturally occurring water moves through the reservoir, producing wells can begin bringing increasingly large quantities of water to the surface along with the oil.
The proportion of produced fluid that is water is commonly referred to as the water cut.
An offshore facility therefore might continue handling large volumes of fluid even as the amount of oil contained in that fluid declines. At some point, producing particular wells may become technically or economically unattractive.
Operators can intervene by adjusting wells, drilling additional wells or targeting other parts of the reservoir, but eventually the field enters sustained decline.
A field’s decline is different from a country’s decline
This distinction is particularly important for Guyana.
Production began at Liza 1 in December 2019, followed by Liza 2 in 2022, Payara in 2023 and Yellowtail in 2025. ExxonMobil said Yellowtail’s startup took Guyana’s installed production capacity above 900,000 barrels per day (b/d).
The older developments can therefore begin experiencing natural production declines while Guyana’s total production continues rising.
That is because new projects and wells can add more production than older assets are losing.
Uaru, the fifth Stabroek Block development, is expected to add around 250,000 b/d of capacity, while Whiptail is expected to add another 250,000 b/d.
This creates two different production curves: one for each individual field or development and another for the Stabroek Block as a whole.
For several years, new developments can push the overall curve upward even while the earliest projects move down their individual curves.
This is the case currently with the country’s total production continuing to increase, while Liza 1 experiences decline. Liza 1, the oldest project, has seen highs of 160,000 b/d but averaged 120,000 b/d in the first half of 2026.
