3.1 Failure to Keep Hole Full, Swabbing & Abnormal Formation Pressure

Tripping creates well-control risks through changes in displaced volume, fluid level and dynamic pressure. Pulling pipe can swab the well; running pipe can cause surge pressure. Maintain the required barriers and keep the appropriate shut-in equipment ready throughout the trip. IWCF Level4 supervisors assess trip-tank volumes, pipe-movement pressures and the actual well response rather than assuming that a trip is safe because drilling has stopped.

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1. Failure to Keep the Hole Full While Tripping

When a drillstring is pulled from a wellbore, the volume previously occupied by the tubulars must be immediately replaced with drilling fluid. Failure to replace this volume causes the fluid level inside the wellbore to fall, directly reducing the total hydrostatic pressure ($P_{\text{hyd}}$) exerted on open formations:

$P_{\text{hyd}} = 0.052 \times \rho_{\text{mud}} \times \text{TVD}$

If the fluid level drops sufficiently, the hydrostatic pressure falls below the pore pressure ($P_{\text{pore}}$) of an exposed permeable formation, precipitating an underbalanced kick.

Mathematical Tripping Mechanics (IWCF EX-0035 Formulas 17–22)

When pipe is pulled without adding fluid, the level drop depends on the volume removed and the space into which the remaining fluid can redistribute. With dry pipe that drains freely, the annulus and pipe bore communicate: the available liquid space per foot is casing capacity minus metal displacement. With wet pipe whose internal fluid is retained, the available space is the external annulus: casing capacity minus closed-end displacement.

These are the distinct denominators in IWCF Formulas 17 and 18 while pipe remains across the falling liquid level. Do not replace them with bare casing capacity. The separate remaining-collar exercises in Formulas 19 and 20 use their stated geometry and bare casing-capacity denominator.

A. Pulling Pipe Dry (Draining String)

When the drillstring drains freely back into the well through bit nozzles or a float valve, only the metal displacement ($V_{\text{disp}}$) is evacuated from the well:

$\text{Pressure drop per foot (psi/ft)} = \frac{\rho_{\text{mud}} \times 0.052 \times \text{metal displacement (bbl/ft)}}{\text{casing capacity (bbl/ft)} - \text{metal displacement (bbl/ft)}}$

$\text{Length dry before overbalance is lost (ft)} = \frac{\text{overbalance (psi)} \times [\text{casing capacity (bbl/ft)} - \text{metal displacement (bbl/ft)}]}{\rho_{\text{mud}} \times 0.052 \times \text{metal displacement (bbl/ft)}}$

B. Pulling Pipe Wet (Plugged or Sealed String)

When bit nozzles are plugged, a float valve is stuck closed, or pipe is intentionally pulled with an inside BOP/dart in place, drilling fluid inside the tubular is pulled out of the well. The evacuated volume equals the closed-end displacement ($V_{\text{closed-end}} = V_{\text{disp}} + V_{\text{cap}}$):

$\text{Pressure drop per foot (psi/ft)} = \frac{\rho_{\text{mud}} \times 0.052 \times \text{closed end displacement (bbl/ft)}}{\text{casing capacity (bbl/ft)} - \text{closed end displacement (bbl/ft)}}$

$\text{Length wet before overbalance is lost (ft)} = \frac{\text{overbalance (psi)} \times [\text{casing capacity (bbl/ft)} - \text{closed end displacement (bbl/ft)}]}{\rho_{\text{mud}} \times 0.052 \times \text{closed end displacement (bbl/ft)}}$

API Tubular Geometry and Physical Consistency

All tubular volumetric quantities are governed by fundamental cylindrical geometry ($V = d^2 / 1029.4\text{ bbl/ft}$):

• External / Closed-End Displacement: $V_{\text{closed-end}} = \frac{OD^2}{1029.4}\text{ bbl/ft}$
• Internal Capacity: $V_{\text{cap}} = \frac{ID^2}{1029.4}\text{ bbl/ft}$
• Metal Displacement: $V_{\text{disp}} = \frac{OD^2 - ID^2}{1029.4}\text{ bbl/ft} = V_{\text{closed-end}} - V_{\text{cap}}$

For example, a uniform 5-inch OD cylinder has a closed-end capacity of $5.0^2 / 1029.4 = 0.024286\text{ bbl/ft}$ (approximately $0.02429\text{ bbl/ft}$). This is a uniform pipe-body value, excluding upsets and tool joints. An assembled-string table can differ; use the supplied exercise data or the applicable manufacturer body/assembly displacement table.

Trip Tank Operations and Monitoring Routines

The trip tank is a dedicated, small-volume (typically 20 to 40 barrels), tall, narrow tank equipped with high-resolution level indicators calibrated to 0.1 barrel (or 10 liters). It is the primary tool for monitoring wellbore volumetric integrity during trips.

1. Continuous Filling System: The trip tank pump continuously circulates mud into the casing annulus over the bell nipple, with an overflow line returning excess mud to the trip tank. As pipe is withdrawn, the mud level in the trip tank drops continuously, providing real-time displacement tracking.
2. Batch Filling System: The hole is filled periodically (e.g., every 3 to 5 stands). This method introduces dangerous blind intervals where a swabbing influx can develop undetected between fills.
3. The Trip Sheet: Prior to pulling out of the hole (POOH), the drilling supervisor must prepare a comprehensive trip sheet tabulating theoretical cumulative fill volume stand-by-stand versus measured cumulative volume.

Worked Numerical Example: Tripping Hydrostatic Loss

Scenario: A drilling crew pulls 15 stands ($15 \times 90\text{ ft} = 1,350\text{ ft}$) of 5-inch drillpipe ($OD = 5.0\text{ in}$, $ID = 4.276\text{ in}$, $V_{\text{disp}} = 0.00652\text{ bbl/ft}$, $V_{\text{closed-end}} = 0.02429\text{ bbl/ft}$) from 9-5/8" casing ($8.681\text{ in}$ ID, capacity $C_{\text{csg}} = 0.0733\text{ bbl/ft}$). Mud weight is $12.5\text{ ppg}$ (mud gradient $g_m = 12.5 \times 0.052 = 0.65\text{ psi/ft}$), initial TVD is $11,500\text{ ft}$, and initial trip overbalance is $200\text{ psi}$. The trip tank is misaligned, and zero mud is pumped into the hole.

Case A: Pulling Dry (String Drains)

1. Theoretical Metal Displacement Evacuated: $V_{\text{disp}} = 1,350\text{ ft} \times 0.00652\text{ bbl/ft} = 8.802\text{ bbl}$
2. Drop in Fluid Level ($\Delta h_{\text{dry}}$): $\Delta h_{\text{dry}} = \frac{\text{total metal volume removed}}{C_{\text{csg}} - \text{metal displacement per foot}} = \frac{8.802\text{ bbl}}{0.0733 - 0.00652\text{ bbl/ft}} = \frac{8.802\text{ bbl}}{0.06678\text{ bbl/ft}} = 131.81\text{ ft}$
3. Pressure Drop per Foot and Total Hydrostatic Loss: $\text{Drop per foot} = \frac{12.5 \times 0.052 \times 0.00652}{0.0733 - 0.00652} = 0.06346\text{ psi/ft}$ $\Delta P_{\text{hyd, dry}} = 1,350\text{ ft} \times 0.06346\text{ psi/ft} = 85.67\text{ psi} \quad (131.81\text{ ft} \times 0.65\text{ psi/ft} = 85.68\text{ psi})$
4. Maximum Length Pulled Dry Before Overbalance ($200\text{ psi}$) is Lost: $L_{\text{max, dry}} = \frac{200\text{ psi} \times (0.0733 - 0.00652)}{12.5 \times 0.052 \times 0.00652} = \frac{200}{0.06346} = 3,151.6\text{ ft} \quad (\approx 35.0\text{ stands})$

Case B: Pulling Wet (String Plugged / Sealed)

1. Theoretical Closed-End Volume Evacuated: $V_{\text{wet}} = 1,350\text{ ft} \times 0.02429\text{ bbl/ft} = 32.792\text{ bbl}$
2. Drop in Fluid Level ($\Delta h_{\text{wet}}$): $\Delta h_{\text{wet}} = \frac{V_{\text{wet}}}{C_{\text{csg}} - V_{\text{closed-end}}} = \frac{32.792\text{ bbl}}{0.0733 - 0.02429\text{ bbl/ft}} = \frac{32.792\text{ bbl}}{0.04901\text{ bbl/ft}} = 669.09\text{ ft}$
3. Pressure Drop per Foot and Total Hydrostatic Loss: $\text{Drop per foot} = \frac{12.5 \times 0.052 \times 0.02429}{0.0733 - 0.02429} = 0.32215\text{ psi/ft}$ $\Delta P_{\text{hyd, wet}} = 1,350\text{ ft} \times 0.32215\text{ psi/ft} = 434.90\text{ psi} \quad (669.09\text{ ft} \times 0.65\text{ psi/ft} = 434.91\text{ psi})$
4. Resulting Underbalance Condition: $\text{Underbalance} = 434.90\text{ psi} - 200\text{ psi} = 234.90\text{ psi}$ Pulling 15 stands wet without filling creates an underbalance of $234.90\text{ psi}$, inducing an uncontrolled kick.
5. Maximum Length Pulled Wet Before Overbalance ($200\text{ psi}$) is Lost: $L_{\text{max, wet}} = \frac{200\text{ psi} \times (0.0733 - 0.02429)}{12.5 \times 0.052 \times 0.02429} = \frac{200}{0.32215} = 620.8\text{ ft} \quad (\approx 6.9\text{ stands})$ Pulling fewer than 7 stands wet without filling completely eliminates the entire $200\text{ psi}$ safety margin.

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2. Swabbing Mechanics and Influencing Factors

Swabbing is a transient reduction in wellbore pressure caused by upward drillstring movement. The moving pipe drags fluid upward while fluid must replace the volume vacated below the assembly. Resistance to that replacement flow lowers the pressure below the moving assembly.

$\text{Dynamic BHP} = P_{\text{hyd}} - \Delta P_{\text{swab}}$

If $\Delta P_{\text{swab}} > (P_{\text{hyd}} - P_{\text{pore}})$, formation fluid enters the wellbore.

   ▲ Hoisting Motion (Upward Pipe Velocity V_p)
   │
┌──┴──┐ ◄── Narrow Clearance (BHA / Stabilizers / Bit)
│ BHA │
└──┬──┘
   ▼ Pressure Falls Below Assembly (-ΔP_swab)
═════════════════════════════════════════════
Formation Pore Pressure > Swabbed BHP ===> INFLUX (KICK)

Primary Factors Governing Swab Pressure Magnitude

1. Pipe Hoisting Speed: Fluid shear stress along the borehole wall increases non-linearly with pulling velocity. Accelerating pipe out of the slips too rapidly produces severe swab spikes.
2. Mud Rheology (Plastic Viscosity, Yield Point, and Gel Strength): Elevated Plastic Viscosity (PV) and Yield Point (YP) increase frictional pressure loss through the restricted annular space. Thixotropic gel strength creates an initial yield threshold; pulling pipe after a connection or static logging period without breaking circulation causes severe pressure drawdown.
3. Annular Clearance Geometry: Tight clearances around large-diameter bottom hole assembly (BHA) components (drill collars, stabilizers, mud motors, MWD/LWD tools, core barrels) create a flow constriction. Fluid cannot bypass the ascending tool string easily, magnifying the piston/syringe effect.
4. Balled-Up BHA Components: Dispersed reactive clays (gumbo shales) adhere to stabilizers, bit cones, and reamers, completely packing off the annular space. A balled BHA can act like a swab cup, creating a large pressure drop below the assembly and increasing influx risk.
5. Hole Condition: Keyseats, ledges, thick filter cakes, and reactive shale swelling physically reduce effective hole diameter, exacerbating swabbing.

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3. Abnormal Formation Pressure and Transition Zones

Abnormal formation pressure (overpressure) occurs whenever the pore fluid pressure within a rock unit exceeds the hydrostatic pressure of a column of native formation brine (typically $> 0.465\text{ psi/ft}$ or $> 8.95\text{ ppg}$ equivalent mud weight).

Geological Mechanisms Generating Overpressure

• Disequilibrium Compaction (Under-Compaction): Rapid deposition of low-permeability mudstones and silts prevents pore fluids from escaping as overburden stress increases. The entrapped pore fluid bears a significant portion of the overburden weight, resulting in abnormally high pore fluid pressures.
• Tectonic Stresses: Horizontal compressive stresses in active tectonic margins increase rock strain, pressurizing entrapped fluids beyond vertical overburden balances.
• Fault Crossover and Fluid Migration: Drilling across an impermeable or sealing fault into an isolated, structurally elevated block, or crossing a permeable fault plane that acts as a conduit charging shallow reservoirs from deep, high-pressure reservoirs.
• Charged Shallow Sands: Shallow permeable formations recharged by leaking casing shoes, failed primary cement jobs, or subterranean crossflow from nearby blowout wells. These present extreme hazards due to minimal fracture margins.

Transition Zone Detection and Early Warning Signs

Drilling into an abnormal pressure transition zone presents distinct physical signatures that drilling engineers and supervisors must monitor continuously: