How Much of Your OOIP Have You Actually Recovered?

Oil fields are often judged by what they have already produced.

That can be misleading.

A better starting question is:

Across U.S. conventional oil fields, primary recovery typically produces about 10% of OOIP.¹ Add secondary recovery, usually water or gas injection, and historical recovery across U.S. conventional fields averages about 33% of OOIP, leaving roughly 67% remaining in place.²

The numbers vary materially by basin. Primary plus secondary recovery has been estimated at about 32% in Central and East Texas, 35% in the Permian Basin, and 27% in the Mid-Continent.²

That does not mean 67% is waiting to be produced.

It does mean there may be a much larger remaining resource than the production history alone suggests.

Primary recovery only gets you so far

Primary recovery relies on natural reservoir energy, gravity drainage and artificial lift to move oil toward the wellbore and bring it to the surface.

DOE estimates that primary recovery typically produces only about 10% of OOIP.¹

That matters in mature conventional fields developed with older vertical wells. Those wells may have produced successfully for decades and still have contacted only part of the reservoir effectively.

The fact that a field is old does not tell you how efficiently it was drained.

Secondary recovery changes the equation

Secondary recovery generally introduces water or gas to maintain pressure and displace oil toward producing wells. DOE cites total recovery after secondary methods in the range of roughly 20% to 40% of OOIP.¹

In many conventional fields, that means waterflooding.

But a waterflood is not a switch you turn on and walk away from. It is management-intensive.

Injection rates, pressure behavior, communication between wells, breakthrough, sweep efficiency, well performance, mobility ratio, conformance and reservoir heterogeneity all have to be monitored and adjusted over time.

A good flood can materially increase recovery. A poorly understood or poorly managed flood can move water efficiently without moving enough oil.

In practice, managing a mature waterflood can feel a little like juggling bowling balls. There are several moving pieces, and dropping one can affect the whole system.

Tertiary recovery can move the ceiling higher

Even after primary and secondary recovery, significant oil may remain because it was never swept or remains trapped by capillary forces.

That is where enhanced oil recovery, or EOR, can come into play.

DOE identifies three major commercial EOR categories: thermal recovery, gas injection including CO2, and chemical injection. DOE states that EOR methods can ultimately raise recovery to roughly 30% to 60% of OOIP or more, depending on the reservoir and the process.¹

For many large Permian Basin carbonate reservoirs, NETL notes post-waterflood recovery of approximately 30% to 45% of OOIP, with successful CO2 EOR potentially adding another 5% to 15% of OOIP.³

That is not a promise. It is evidence that the recovery ceiling can move materially when the reservoir, fluids and economics support the method.

Heavy oil is a different problem

Not every reservoir fits neatly into the same recovery sequence.

Heavy oil is the obvious example. When oil viscosity is high, simply maintaining pressure may not be enough. The oil may need to be mobilized before it can move efficiently through the reservoir.

DOE describes thermal recovery as the introduction of heat, commonly steam, to reduce oil viscosity and improve flow.¹ USGS documents the importance of steam-assisted production in California heavy-oil fields such as Kern River, Midway-Sunset and South Belridge.⁴

Heavy oil is not just a California story. USGS identifies substantial heavy-oil resources in Texas and other states,⁵ while historical DOE work estimated significant heavy OOIP in Texas.⁶

For heavy oil, steam may be part of the commercial development concept from the beginning rather than something introduced only after decades of conventional production.

That is exactly why recovery strategy should begin with the reservoir rather than with a preferred technology.

There is more than one way to capture what remains

Once you establish that significant OOIP remains, the next question should not automatically be, "Where should we drill another well?"

It should be, "What is the best way to capture the economic portion of what remains?"

The objective is not to maximize barrels at any cost. It is to maximize economic recovery.

Remaining OOIP is not the same as reserves

This distinction is critical.

If a field has recovered 33% of OOIP, the remaining 67% does not automatically become reserves.

Some of that oil may be physically immobile. Some may be poorly connected to existing wellbores. Some may require a recovery process that is technically possible but uneconomic. Some may only become economic under different commodity prices, capital costs or technology.

And some may become accessible because the technology available today is better than the technology available when the field was originally developed.

That is the opportunity.

Not to assume every barrel can be recovered, but to identify which barrels deserve another look.

Modern technology can change what is recoverable

A field developed twenty, thirty or forty years ago was developed using the technology, data and economics available at the time.

Today operators may have access to better petrophysics, horizontal drilling, geosteering, improved completions, better artificial lift, improved reservoir surveillance, modern production analytics, CO2 and other EOR methods, and far more computational power.

The original development plan may have been completely rational. It may also have left opportunities that are visible today.

Modern technology can bring more oil to the surface than in the past.

The challenge is determining where that opportunity exists, which recovery method fits the reservoir, which approach fits the operator, and whether the economics justify the capital.

We can help explore what is left to capture

PINN AI is being built to bring the evidence together: rock, historical production, completions, pressure behavior, well geometry, existing development, recovery history and economics.

We do not begin with a preference for a vertical well, a horizontal well, a workover, a waterflood or EOR.

We begin with the field.

How much more can your field yield?

PINN AI
Math that drills deeper.

We can help explore what is left to capture.