Production modes describe how fluids are brought to surface from the reservoir, ranging from natural flow to artificial lift methods.
A well producing under its own reservoir pressure without artificial lift. Flowing wells have sufficient bottomhole pressure to push fluids to surface naturally. This is the most economical production method but typically only available early in a well's life.
Example: New wells in high-pressure formations often flow naturally for months or years.
A well using a pump to lift fluids to surface. The iconic "pumpjack" or beam pump is the most common artificial lift method in Western Canada. Pumping is required when reservoir pressure declines below what can sustain natural flow.
Example: Most mature oil wells in Alberta use beam pumps.
An artificial lift method that injects gas into the wellbore to reduce fluid density and help lift production to surface. Gas lift is common in wells with high water cuts or low bottomhole pressure where pumps are impractical.
Example: Gas lift is often used in offshore wells and deep formations.
A cyclical artificial lift system using a free-traveling plunger to carry liquids to surface. The plunger rises on accumulated gas pressure and falls back between cycles. Efficient for low-volume gas wells with liquid loading issues.
Example: Many shallow gas wells use plunger lift to remove water from the wellbore.
A well temporarily closed and not producing. Shut-in differs from suspension in that the well remains capable of immediate production. Companies shut in wells for pressure testing, maintenance, pipeline constraints, or economic reasons.
Example: Gas wells are often shut in during summer when prices are lowest.
A well used to inject fluids into a reservoir rather than produce them. Injection wells support enhanced recovery (water or gas injection), disposal of produced water, or carbon capture and storage. They operate in reverse of producing wells.
Example: Waterflood projects use injection wells to maintain reservoir pressure.
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