Formation Pressure: Normal, Subnormal, and Abnormal
Lesson Summary
What pressure do rocks hold in their pores, when is it normal, subnormal, or abnormal, and why this determines the required mud weight.
This lesson is part of the Well Control track and is 10:08 minutes long. Watch the video first, then review the key points and test your understanding with the questions below.
Key Points
- 1Normal pressure is close to the gradient of a formation water column
- 2Abnormal pressure requires heavier mud to balance
- 3Subnormal pressure exposes the well to mud losses
- 4The difference between mud pressure and formation pressure is Overbalance
Written Lesson
What is Formation Pressure?
Sedimentary rocks are not solid blocks; they contain small pores filled with water, oil, or gas. The pressure of these fluids inside the pores is the Formation Pressure, also called Pore Pressure. This is the pressure that the mud column in the well must balance at all times; if mud pressure falls below it, formation fluids enter the well and a kick begins.
To compare pressures at different depths, we convert each pressure into Equivalent Mud Weight (EMW). That is: what mud weight would provide this same pressure at this vertical depth?
EMW (ppg) = P (psi) ÷ (0.052 × TVD (ft))
Normal Pressure
Formation pressure is Normal Pressure when it is approximately equal to the pressure of a column of formation water extending from the layer to the surface, meaning the pores have been hydraulically connected to the surface over geological time. The fresh water gradient is 0.433 psi/ft, but salty formation water is heavier, and its gradient in many basins is near 0.465 psi/ft, equivalent to about 8.9 ppg. The "normal" value varies by basin depending on water salinity, so it is provided in the well program based on regional data.
Calculation Example: A formation at 9,000 ft TVD with a normal gradient of 0.465 psi/ft: its pressure is 0.465 × 9,000 = 4,185 psi, and the EMW is 4,185 ÷ (0.052 × 9,000) = 4,185 ÷ 468 ≈ 8.94 ppg.
Abnormal Pressure: Where does it come from?
Abnormal pressure (Abnormal Pressure or Overpressure) is any pressure higher than normal pressure at the same depth. It is the most dangerous in well control because it can appear suddenly beneath a seal. Its main causes include:
- Undercompaction: Rapid deposition of shale layers does not allow water to escape the pores; the water then carries part of the overburden weight, increasing its pressure.
- Hydrocarbon column: Gas and oil are lighter than water, so the pressure at the top of the reservoir is higher than the normal pressure at that depth; the longer the gas column, the greater the difference.
- Tectonic movements: Uplifting a pressurized layer to a shallower depth while maintaining its pressure, or lateral compression increasing pore pressure.
- Charged Formations: A shallow layer receives pressure from a deeper formation via a fault, poor cement, or an old wellbore.
- Other factors such as mineral transformation of clays with heat, and salt layers that prevent pressure dissipation.
Calculation Example: Calculating pressure at the top of a gas reservoir: Gas-water contact at 8,000 ft with normal pressure 0.465 × 8,000 = 3,720 psi. A 1,000 ft gas column with a gradient of about 0.1 psi/ft means the pressure at the top at 7,000 ft is 3,720 − 0.1 × 1,000 = 3,620 psi. Since normal pressure at 7,000 ft is only 0.465 × 7,000 = 3,255 psi, the top is 365 psi overpressured, and its EMW is 3,620 ÷ (0.052 × 7,000) = 3,620 ÷ 364 ≈ 9.95 ppg instead of 8.94 ppg. This is why entering the top of a gas reservoir is a critical moment in drilling.
Subnormal Pressure
Subnormal pressure (Subnormal Pressure) is lower than normal pressure, often appearing in depleted reservoirs after years of production or in uplifted layers where overburden has eroded. Its danger is different: mud that balances a normal layer above may be too heavy for the subnormal layer, causing the formation to take mud, leading to losses. If the mud level in the well drops, hydrostatic pressure decreases on all exposed formations, and another higher-pressure layer may start to flow.
Overbalance and the Mud Window
The difference between mud hydrostatic pressure and formation pressure is the Overbalance. We want it to be always positive, but not excessively so, as increasing it slows drilling, raises the risk of differential sticking, and may approach the fracture pressure.
Overbalance (psi) = 0.052 × MW × TVD − Pf
Calculation Example: Formation pressure is 6,240 psi at 10,000 ft TVD, which is an EMW of 6,240 ÷ 520 = 12.0 ppg. If drilling with 12.5 ppg mud, the hydrostatic pressure is 0.052 × 12.5 × 10,000 = 6,500 psi, and the Overbalance = 6,500 − 6,240 = 260 psi.
How do we know if pressure is increasing while drilling?
We don't see formation pressure directly while drilling, but there are indicators monitored by the driller, mud engineer, and mud logging team; these are potential signs, not certain proof:
- Sudden increase in rate of penetration (Drilling Break) or a decrease in the d-exponent trend.
- Increase in background gas and appearance of connection gas or trip gas.
- Splintered and large rock cavings on the shakers, and increased torque and drag.
- Increase in return mud temperature in the flowline.
When these appear, we stop and perform a flow check before proceeding. After shutting in the well on a kick, we calculate formation pressure accurately from the shut-in drill pipe pressure:
Pf = SIDPP + 0.052 × MW × TVD
Summary
- Normal pressure is close to the formation water gradient, about 0.465 psi/ft in many basins (≈ 8.9 ppg).
- Abnormal pressure comes from undercompaction, hydrocarbon columns, tectonics, and charged formations.
- Subnormal pressure causes losses, and losses can lead to a kick from another layer.
- We convert every pressure to EMW for comparison, and calculate formation pressure after shut-in: Pf = SIDPP + Hydrostatic Pressure.
The figures and examples in this lesson are for educational purposes. On the job, always follow your company procedures and accredited training center instructions.
Test Yourself
Lesson Glossary
Pressure of fluids within rock pores, same as formation pressure.
Pressure expressed in ppg at a specific vertical depth: P ÷ (0.052 × TVD).
Formation pressure higher than normal pressure at the same depth.
Formation pressure lower than normal, common in depleted reservoirs.
The difference between mud column pressure and formation pressure.