Primary Recovery Method

Primary recovery is the first phase of oil and gas production, in which fluid is produced using only the natural energy already stored in the reservoir. That energy comes from the pressure in the reservoir rock and the surrounding fluids: expanding gas, dissolving gas coming out of solution, water influx from an adjacent aquifer, or simple gravity drainage. When reservoir pressure has declined enough that the natural drive can no longer push oil to the wellbore at economic rates, production falls off and the operator considers whether to augment or replace the natural energy with an engineered one. In conventional light oil reservoirs, primary recovery typically extracts 15 to 30 percent of the original oil in place before the well or field needs intervention.

Key Takeaways

The five main natural drive mechanisms in primary recovery are: solution gas drive (dissolved gas expands as pressure drops below bubble point), gas cap drive (free gas above the oil zone expands and pushes oil down and out), water drive (water in an adjacent aquifer pushes into the reservoir as pressure drops), gravity drainage (oil flows downward under its own weight in steeply dipping reservoirs), and rock and fluid expansion (the mechanical expansion of pore rock and remaining fluid at pressures above bubble point).
The producing mechanism determines how quickly pressure declines and how much oil can be recovered. Water drive reservoirs typically have the highest primary recovery (up to 60 percent in strong aquifer cases) because the aquifer maintains reservoir pressure. Solution gas drive reservoirs tend to recover 5 to 15 percent because pressure drops quickly as gas comes out of solution.
In primary recovery, the reservoir does all the work. Artificial lift (pumps, gas lift) may be needed to help the fluid reach surface once wellbore pressure drops below the hydrostatic head, but the energy driving fluid from the rock into the wellbore comes from the reservoir itself.
Oil sands and very heavy oil reservoirs typically cannot produce by primary recovery because the crude is too viscous to flow to the wellbore without heating. SAGD, cyclic steam stimulation (CSS), and in situ combustion are thermal methods that function as primary methods for these deposits even though they require injected energy.
Gas reservoirs often have very high primary recovery (80 to 95 percent) because gas expands greatly as pressure declines, sweeping most of the gas from the reservoir before abandonment pressure is reached.

What Drives a Well During Primary Recovery?

A car tire inflated to 200 kPa has energy stored in the compressed air. Poke a small hole in it and the air pushes itself out through the hole. The tire does not need an electric pump; the pressure inside does all the work. A reservoir is the same idea, scaled up by a factor of millions.

When a well is drilled and perforated, it creates a low-pressure pathway from the high-pressure reservoir rock to the surface. Reservoir fluid (oil, gas, or brine) flows toward the wellbore along the pressure gradient. As fluid leaves the reservoir, pressure drops. The drive mechanism is whatever is supplying that pressure, or more precisely, what resists the pressure decline as production continues.

In a solution gas drive reservoir, the oil is originally undersaturated, meaning no free gas exists. As pressure drops below the bubble point (the pressure at which gas begins to come out of solution), dissolved gas bubbles out and the expanding gas provides drive energy. This is effective initially but pressure declines quickly because the gas is consumed as it expands. In a strong water drive reservoir, an aquifer connected to the producing formation acts like a slowly inflating tire on the outside of the reservoir, pushing fluid toward the well. Pressure holds up better under water drive than under solution gas drive, and sweep efficiency is higher.

Fast Facts

The Leduc D-3 reef oil pool in Alberta, discovered in 1947, is a textbook example of water drive primary recovery. The Leduc reef complex is flanked by a regional Devonian aquifer that maintained reservoir pressure throughout several decades of primary production. The D-3 pool recovered more than 50 percent of original oil in place under primary water drive before water breakthrough at the producing wells signaled the limits of the natural drive. Most of the 1,300 wells drilled into the Leduc reef complex over four decades produced at or near the initial well rates for much of their primary lives without secondary injection.

Recovery Factors by Drive Mechanism

The amount of oil recovered during primary production varies widely depending on the drive mechanism. Solution gas drive reservoirs, where the gas that comes out of solution as pressure drops provides the pushing energy, typically recover 5 to 15 percent of original oil in place (OOIP) during primary production. The gas expands, drives some oil out, then fingers through the rock and the remaining oil is stranded. Many Alberta Jurassic sand pools produce under solution gas drive.

Gas cap drive, where a body of free gas sits above the oil zone and expands downward as oil is removed from below, recovers 20 to 40 percent of OOIP if the reservoir dip is favorable and the cap is large. Gravity segregation helps keep gas in the cap and oil flowing to the producing wells.

Strong water drive, where a large connected aquifer maintains reservoir pressure close to the original level, gives the best primary recovery: 30 to 60 percent of OOIP in favorable cases. The Leduc reef and the Weyburn Mississippian pool in Saskatchewan have both benefited from strong water drive.

Rock and fluid expansion (compaction drive) contributes to recovery in over-pressured or tight reservoirs, particularly in chalk fields like Ekofisk in the Norwegian North Sea, where the chalk compacts measurably as pore pressure declines, helping maintain production rates even as reservoir pressure drops.

Primary Recovery and Heavy Oil in Western Canada

Primary recovery takes on a different meaning in Alberta and Saskatchewan's heavy oil plays. The Peace River, Cold Lake, and Lloydminster fields hold bitumen and heavy oil with viscosities so high (1,000 to over 1,000,000 centipoise at reservoir temperature) that the oil cannot flow to the wellbore under natural reservoir pressure alone. A well drilled into Cold Lake bitumen without thermal stimulation would produce essentially no oil.

Cold heavy oil production with sand (CHOPS) is the one primary recovery mechanism that works for some heavy oil deposits. In this technique, reservoir sand is deliberately produced along with the oil, creating high-permeability wormhole channels that allow the viscous oil to reach the wellbore even at reservoir temperature. CHOPS can recover 5 to 10 percent of OOIP in some Lloydminster heavy oil reservoirs, making it a genuine primary recovery method, but it only works in unconsolidated sands with the right sand content and reservoir geometry.

For oil sands at Cold Lake, SAGD and CSS are the economically primary methods used in development, even though they require injected steam energy. These thermal methods are what makes these deposits commercial, and they are classified by the Canadian Oil and Gas Evaluation Handbook (COGEH) as primary recovery for these specific reservoir types.

Primary recovery is also called primary production or primary depletion. The phase following primary recovery is secondary recovery (typically water or gas injection). Enhanced oil recovery (EOR) or tertiary recovery refers to chemical, thermal, or miscible flood methods. Related terms include solution gas drive (a primary recovery mechanism in which dissolved gas coming out of solution as reservoir pressure drops below bubble point provides the energy to push oil toward the wellbore), water drive (a primary recovery mechanism in which influx from a connected aquifer maintains reservoir pressure and pushes oil toward producing wells; typically gives the highest primary recovery factors), secondary recovery (the application of injected fluids, typically water or gas, to maintain or restore reservoir pressure after primary drive energy has been depleted; the most common form is waterflood), reservoir drive (the general term for the energy source that moves fluid from the reservoir rock into the wellbore; includes all natural and injected drive mechanisms), and original oil in place (OOIP, the total volume of oil that exists in a reservoir before any production begins; primary recovery factor is the fraction of OOIP that can be extracted using only natural reservoir energy).

How Understanding the Drive Mechanism Changed a Saskatchewan Field's Development Plan

A junior oil producer acquired a package of 24 producing wells in the Frobisher-Alida oil pool in southeastern Saskatchewan. The previous operator had drilled and cased all 24 wells but had not studied the reservoir geology beyond what was needed to get the wells producing. The buyer's engineering team ran a reservoir simulation on the historical production data from 18 of the wells using only publicly available data from the Saskatchewan Ministry of Energy and Resources.

The simulation suggested the pool was producing under weak water drive, not the solution gas drive the previous operator had assumed. Pressure maintenance had been better than expected, and the gas-oil ratio had not risen as fast as a solution gas model would have predicted. The estimated primary recovery factor under the previous assumption was 10 percent of OOIP. Under a weak water drive model, the estimate rose to 22 percent.

Based on the simulation result, the buyer elected not to immediately start a waterflood (which had been the previous operator's intention), instead running the 24 wells under primary production for two more years while monitoring reservoir pressure more carefully. Pressure surveillance over 24 months confirmed the water drive mechanism. When the waterflood was eventually implemented, it was designed with injector locations optimized for the now-confirmed aquifer geometry rather than a default symmetric pattern. The final waterflood recovery factor was estimated at 42 percent of OOIP compared to the 30 percent that the defaulted pattern would have achieved, a 40 percent improvement in expected recovery from the field. Primary recovery analysis was the starting point for all of it.