1.4 Dynamic Well Pressures, Surge & Swab Effects

A high percentage of well control kicks and lost circulation incidents occur not during active drilling, but while tripping pipe. Movement of the drillstring inside the liquid-filled wellbore acts as a hydraulic piston, generating transient dynamic pressure waves known as surge and swab.

Hydrodynamics of Swabbing and Surging

Whenever pipe is moved axially through a viscous fluid column, viscous shear forces develop between the outer surface of the pipe and the inner wall of the hole or casing. In addition, fluid must physically displace around the moving assembly.

1. Swabbing Mechanics

When the drillstring is hoisted out of the hole, fluid clinging to the pipe exterior is dragged upward. Simultaneously, fluid below the bit must flow downward through the annular space to fill the volumetric void vacated by the withdrawing steel. The resistance of the viscous mud to this downward displacement generates a transient suction pressure:

$BHP_{\text{swab}} = P_{\text{hyd}} - \Delta P_{\text{swab}}$

If the swab pressure drop ($\Delta P_{\text{swab}}$) exceeds the hydrostatic overbalance margin, bottomhole pressure falls below formation pore pressure ($BHP_{\text{swab}} < P_p$), drawing an influx of gas or liquid into the wellbore. Because the well is not circulating, a swabbed kick often remains undetected until pipe is pulled several stands or the hole fails to take the proper fill-up volume.

2. Surging Mechanics

When pipe is lowered into the wellbore, the drillstring displaces fluid downward and outward into the annulus. The viscous drag of the fluid moving upward through the narrow annular restriction creates dynamic backpressure:

$BHP_{\text{surge}} = P_{\text{hyd}} + \Delta P_{\text{surge}}$

If the surge pressure increment ($\Delta P_{\text{surge}}$) elevates bottomhole or shoe pressure above the rock fracture gradient ($BHP_{\text{surge}} > P_{\text{frac}}$), the formation breaks down. This causes lost circulation, a drop in fluid level, and a subsequent loss of primary hydrostatic well control.

The Safe Tripping Window

To prevent both kicks and lost circulation, dynamic bottomhole pressure must remain strictly within the operational envelope:

$P_{\text{pore}} < BHP_{\text{swab}} \le P_{\text{hyd, static}} \le BHP_{\text{surge}} < P_{\text{fracture}}$

---

Dominant Operational Factors Controlling Swab and Surge Pressures

Drilling supervisors must evaluate five critical parameters that determine the magnitude of transient surge and swab pressures:

1. Tripping Velocity and Pipe Acceleration

Dynamic pressure varies directly with pipe speed, but non-linearly with pipe acceleration. Rapid hoisting off the slips or abrupt braking of the traveling block generates extreme pressure pulses. Smooth, gradual clutch engagement and controlled deceleration are vital.

2. Annular Clearance Around the BHA

Annular clearance between the hole and the drillstring is the most influential geometric factor. The Bottom Hole Assembly (drill collars, heavy-weight drillpipe, and stabilizers) can create high local pressure losses where annular clearance is small:

• In an $8\text{-}1/2\text{ inch}$ hole with $5\text{ inch}$ drillpipe, diametral clearance is $3.5\text{ inches}$.
• Across $6\text{-}3/4\text{ inch}$ drill collars, diametral clearance shrinks to $1.75\text{ inches}$.
• Across $8\text{-}3/8\text{ inch}$ near-bit stabilizers, clearance is $1/8\text{ inch}$, creating a tight hydraulic choke.

3. Drilling Fluid Rheology and Gel Strength Breakdown

Fluid yield point (YP) and plastic viscosity (PV) dictate steady-state viscous drag. Even more critical is thixotropic gel strength:

• When mud remains static during a round trip, clay platelets form an internal electrostatic lattice (10-second, 10-minute, and 30-minute gels).
• Initiating pipe movement or circulation requires breaking this gel lattice, generating an initial pressure spike:

$P_{\text{break gel}} = \frac{\tau_g \times L}{300 \times (D_h - D_p)}$

Where $\tau_g$ is gel strength ($\text{lb/100 ft}^2$), $L$ is section length ($\text{ft}$), $D_h$ is hole diameter ($\text{in}$), and $D_p$ is pipe OD ($\text{in}$).

4. Pipe Condition: Open-Ended Versus Float Valve (Closed-Ended)

• Open-Ended Drillstring (No Float): Fluid enters the inside of the drillpipe, displacing only the volume of the steel walls (metal displacement). Annular velocities and dynamic pressures remain low.
• Drillstring with a Float Valve: A float valve prevents fluid from entering the drillstring. The pipe acts as a closed cylinder, displacing its entire external bulk volume (closed-end displacement). The greater annular displacement can increase surge pressure; calculate it for the actual geometry, running speed and fluid rheology.

5. Bit and Stabilizer Balling

When drilling sticky, reactive shales with water-based mud, cuttings can ball up around bit cutters and stabilizer blades. A balled assembly acts as a mechanical piston, swabbing almost the entire hole volume and generating massive pressure drops ($>500\text{ psi}$) even at slow hoisting speeds.

---

Operational Mitigation Practices and Trip Sheet Management

Establishing a Trip Margin

A trip margin is an intentional hydrostatic overbalance added to the drilling mud prior to tripping out of the hole, ensuring that anticipated swabbing pressures do not pull bottomhole pressure below formation pore pressure:

$\text{Trip Margin (psi)} = \Delta P_{\text{swab (calculated)}} + \text{Safety Buffer (typically 50-100 psi)}$ $\text{MW}_{\text{trip}} = \text{MW}_{\text{pore equivalent}} + \frac{\text{Trip Margin}}{0.052 \times \text{TVD}}$

Typical field trip margins range from $0.2\text{ to }0.5\text{ ppg}$ ($100 - 250\text{ psi}$).

Continuous Trip Tank Monitoring

The rig trip tank is the primary kick detection tool during tripping operations:

• The hole must be filled continuously or lined up to the trip tank so every stand pulled can be verified.
• If pulling $5\text{ stands}$ of $5\text{ inch}$ drillpipe should displace $3.8\text{ bbl}$ of steel, the trip tank must deliver exactly $3.8\text{ bbl}$ of mud into the well.
• If the hole takes only $2.0\text{ bbl}$, formation fluid has entered the wellbore to replace the missing $1.8\text{ bbl}$—the well has swabbed a kick!

---

Worked Field Calculations for Wellsite Supervisors

Problem 1: Swab Pressure and Dynamic Underbalance Analysis

• Well depth: $11,000\text{ ft TVD}$
• Static drilling fluid density: $11.0\text{ ppg}$
• Formation pore pressure gradient: $0.551\text{ psi/ft}$ (equivalent to $10.60\text{ ppg}$)
• Calculated dynamic swab pressure loss during fast pulling: $\Delta P_{\text{swab}} = 310\text{ psi}$

1. Calculate formation pore pressure: $P_{\text{pore}} = 0.551\text{ psi/ft} \times 11,000\text{ ft} = 6,061\text{ psi}$
2. Calculate static bottomhole hydrostatic pressure: $P_{\text{hyd}} = 0.052 \times 11.0\text{ ppg} \times 11,000\text{ ft} = 6,292\text{ psi}$
3. Determine static overbalance: $\text{Static Overbalance} = 6,292\text{ psi} - 6,061\text{ psi} = +231\text{ psi}$
4. Calculate dynamic bottomhole pressure while pulling pipe: $BHP_{\text{swab}} = P_{\text{hyd}} - \Delta P_{\text{swab}} = 6,292\text{ psi} - 310\text{ psi} = 5,982\text{ psi}$
5. Evaluate wellbore status: $\text{Dynamic Margin} = BHP_{\text{swab}} - P_{\text{pore}} = 5,982\text{ psi} - 6,061\text{ psi} = -79\text{ psi}$ Conclusion: The well is dynamically underbalanced by $79\text{ psi}$. Formation fluids will enter the wellbore unless pulling speed is reduced or mud weight is increased.

Problem 2: Gel Strength Breakdown Pressure Across BHA

After a 12-hour logging run, estimate the annular pressure required to break the measured 10-minute gel strength across the BHA when circulation starts:

• BHA Length ($L$): $900\text{ ft}$; Hole Diameter ($D_h$): $8.5\text{ in}$; Drill Collar OD ($D_p$): $6.5\text{ in}$
• Measured 10-minute Gel Strength ($\tau_g$): $24\text{ lb/100 ft}^2$

$\Delta P_{\text{break BHA}} = \frac{\tau_g \times L}{300 \times (D_h - D_p)} = \frac{24 \times 900}{300 \times (8.5 - 6.5)} = \frac{21,600}{600} = 36.0\text{ psi}$

If the drillpipe section ($10,100\text{ ft}$ of $5\text{ in}$ pipe in $8.5\text{ in}$ hole) has gelled with $\tau_g = 18\text{ lb/100 ft}^2$: $\Delta P_{\text{break DP}} = \frac{18 \times 10,100}{300 \times (8.5 - 5.0)} = \frac{181,800}{1,050} = 173.1\text{ psi}$ $\text{Total Annular Gel-Break Estimate} = 36.0\text{ psi} + 173.1\text{ psi} = 209.1\text{ psi}$ This $209.1\text{ psi}$ estimate covers the stated annular sections only. Surface pump-start pressure also includes the drillstring and surface circuit. Rotate the drillstring where permitted to shear gels, then establish circulation gradually under the approved procedure.