12.1 Surge and Swab Pressure Dynamics During Casing Running

Surge and Swab Pressure Dynamics During Casing Running

Casing and liner operations represent one of the most critical phases of well construction. The physical introduction of massive, large-diameter steel tubulars into a wellbore drastically alters the hydraulic equilibrium of the open hole. In contrast to standard drillstrings—where the annular clearance between the drillpipe and the borehole wall is relatively generous—casing strings and liners exhibit very small diametrical clearances. Examples include running $9\text{-}5/8\text{"}$ casing inside a $12\text{-}1/4\text{"}$ borehole, running a $7\text{"}$ liner inside an $8\text{-}1/2\text{"}$ hole, or running heavy $13\text{-}3/8\text{"}$ casing inside a $17\text{-}1/2\text{"}$ hole.

When casing is lowered into the wellbore, it acts as a massive mechanical piston. The displaced drilling mud must force its way upward through the narrow annular constriction surrounding the casing. The resulting hydraulic friction, viscous drag, and inertial resistance create dynamic pressure increases known as surge pressures. If the casing is subsequently pulled back, picked up off slips, or reciprocated during reaming, the opposite phenomenon occurs: fluid cannot flow downward rapidly enough to backfill the void, generating negative pressure differentials known as swab pressures.

For an IWCF Level 4 Wellsite Supervisor, understanding surge and swab dynamics is vital. Excessive surge can exceed formation integrity and cause losses. If losses reduce hydrostatic support below an exposed formation pressure, an influx or subsurface crossflow can develop. Conversely, swabbing draws formation gas or reservoir fluids into the wellbore, causing an underbalanced influx during casing running.

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Physics of the Piston Effect and Annular Bypass Velocity

To understand why surge pressures are so much more severe during casing operations than during routine drilling or tripping, consider the geometric relationship between the casing exterior and the wellbore wall.

          FLUID BYPASS AND PISTON EFFECT IN TIGHT CLEARANCE

         Wellbore Wall (Dh = 12.25")        Wellbore Wall
         │                                              │
         │◄────────────── Annulus Clearance ───────────►│
         │    ▲ Mud Bypass Flow            ▲ Mud Bypass │
         │    │ (Velocity Vann)            │ (Vann)     │
         │    │                            │            │
         │  ┌─┴────────────────────────────┴─┐          │
         │  │                                │          │
         │  │      9-5/8" Casing Body        │          │
         │  │         (Dc = 9.625")          │          │
         │  │                                │          │
         │  │    Downward Running Motion     │          │
         │  │    (Pipe Velocity Vpipe)       │          │
         │  │              ▼                 │          │
         │  └────────────────────────────────┘          │
         │                                              │
         ▼  Bottomhole Pressure Surge: BHP = Phyd + ΔPsurge

When casing with a conventional non-return check valve (float collar and float shoe) is run into the hole, the casing interior is isolated from the wellbore. The casing acts as a closed-ended cylinder. Every foot of casing submerged into the hole must displace a volume of mud equal to the entire outside diameter ($OD$) of the pipe:

$V_{\text{displaced}}=\frac{\pi D_c^2 L\times 12}{4\times 9702}=\frac{D_c^2 L}{1029.4}\quad(\text{bbl})$

Where:

• $D_c$ = Outside diameter of casing (inches)
• $L$ = Length of casing run (feet)
• $1029.4$ is the unit-conversion divisor for diameters in inches and length in feet: $42\times 231\times 4/(12\pi)\approx 1029.4$.

Because this displaced volume must evacuate through the annular space between the casing outer diameter ($D_c$) and the hole diameter ($D_h$), the upward fluid velocity through the annulus ($v_{ann}$) is multiplied by the ratio of the cross-sectional areas:

$v_{ann} = v_{pipe} \times \left( \frac{A_{casing}}{A_{annulus}} \right) = v_{pipe} \times \left( \frac{D_c^2}{D_h^2 - D_c^2} \right)$

Furthermore, because the casing string is moving downward at velocity $v_{pipe}$ while the annular mud is moving upward at velocity $v_{ann}$, the mean fluid velocity relative to the moving casing ($v_{rel}$) is the algebraic sum of both velocities:

$v_{rel} = v_{ann} + v_{pipe} = v_{pipe} \times \left( 1 + \frac{D_c^2}{D_h^2 - D_c^2} \right) = v_{pipe} \times \left( \frac{D_h^2}{D_h^2 - D_c^2} \right)$

Practical Geometric Example

Consider running a $7\text{"}$ liner ($D_c = 7.000\text{"}$) inside an $8\text{-}1/2\text{"}$ open hole ($D_h = 8.500\text{"}$) with closed float equipment at a running speed of $60\text{ ft/min}$ ($1.0\text{ ft/sec}$):

1. Area ratio calculation: $\frac{D_c^2}{D_h^2 - D_c^2} = \frac{7.0^2}{8.5^2 - 7.0^2} = \frac{49.0}{72.25 - 49.0} = \frac{49.0}{23.25} = 2.108$

2. Annular bypass velocity: $v_{ann} = 60\text{ ft/min} \times 2.108 = 126.5\text{ ft/min}$

3. Mean fluid velocity relative to the casing: $v_{rel} = 126.5\text{ ft/min} + 60.0\text{ ft/min} = 186.5\text{ ft/min}$

The drilling mud is forced to accelerate upward through the narrow $0.75\text{"}$ radial gap at more than twice the speed the rig crew is lowering the pipe, and its mean velocity relative to the pipe is more than three times the running speed. This continuity calculation illustrates the restriction; it is not a local wall shear-rate or surge-pressure calculation. Predict pressure with the actual rheology, geometry, pipe motion and boundary conditions.

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Drilling Fluid Rheology, Viscous Drag and Bingham Plastic Mechanics

The magnitude of the surge pressure generated by this annular bypass velocity depends heavily on the rheological properties of the drilling fluid. Most drilling fluids are non-Newtonian, pseudoplastic, or Bingham plastic slurries. In the Bingham Plastic Model, the frictional pressure drop is determined by two key parameters:

1. Yield Point (YP): The electro-chemical attractive forces between suspended clay and polymer particles that must be overcome before fluid movement can occur (measured in $\text{lbf}/100\text{ ft}^2$).
2. Plastic Viscosity (PV): The mechanical friction resulting from solids-to-solids and solids-to-liquid contact as the fluid shears (measured in $\text{cP}$).

For the Bingham model, shear stress after yielding is $\tau=YP+PV\dot\gamma$. YP is the threshold/intercept and PV is the post-yield slope. Elevated YP, PV and developed gels can increase the pressure needed to move fluid through a restricted annulus; there is no universal 25 lbf/100 ft² threshold or exponential surge law. Use the appropriate rheological model and measured properties at the relevant conditions.

The Static Gel Strength Spike (Breaking Gels)

Even more hazardous than steady-state viscous flow is the thixotropic gel strength of the drilling mud. When casing running is paused on the rig floor to stab, make up, and torque a new casing connection (a process typically taking 2 to 5 minutes), the mud column becomes static.

During this static pause, the bentonite platelets and polymeric viscosifiers form a rigid, interlocking gel matrix (reflected in the 10-second and 10-minute gel strength readings). When the casing string is lowered back into the wellbore after completing the connection, the static gel structure across the entire length of the wellbore must be sheared and broken. This requires a sudden, large burst of mechanical force.

DYNAMIC PRESSURE PROFILE DURING CASING RUNNING CYCLE

 Pressure (psi) ▲
                │                     [Peak Gel Breaking Spike]
                │                                 ▲
  LOT Margin ───┼─────────────────────────────────┼───────────────────────── (Fracture Limit)
                │                                ╱ ╲
                │                               ╱   ╲────── Steady Dynamic Surge
                │                              ╱     
  Static Hyd ───┼─────────────────────────────╱─────────────────────────────
                │       Static Connection    │    Lowering Joint in Hole   │
                │       (Mud Gelling Up)     │    (Gel Broken, Mud Bypassing)│
                └────────────────────────────┴─────────────────────────────► Time

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Downhole Surge Impact on Formation Fracture Limits and Losses

The total dynamic bottomhole pressure ($BHP_{\text{surge}}$) experienced by the open hole while running casing is the sum of the static hydrostatic head and the dynamic surge pressure transient:

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

To evaluate this against the formation integrity limits established during the prior drilling phase, petroleum engineers convert this dynamic pressure to an Equivalent Circulating Density under surge ($ECD_{\text{surge}}$):

$ECD_{\text{surge}} = \text{Mud Weight (ppg)} + \frac{\Delta P_{\text{surge}} (\text{psi})}{0.052 \times TVD (\text{ft})}$

$\text{In SI Metric units: } ECD_{\text{surge}} (\text{SG}) = \text{Mud Density (SG)} + \frac{\Delta P_{\text{surge}} (\text{bar})}{0.0981 \times TVD (\text{m})}$

Compare the pressure or equivalent density at each limiting zone with that zone's integrity limit and the required operating margin. A shoe LOT is not automatically the limit at every depth.

1. Surge beyond the formation-integrity window can initiate losses.
2. If the hole cannot be kept full, the falling fluid level reduces hydrostatic support.
3. If BHP falls below an exposed permeable formation's pressure, an influx can enter; losses do not invariably produce a kick.
4. Respond using the casing-operation contingency plan, with the correct fill, circulation and shut-in equipment ready.

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Swab Pressures and Pipe Reciprocation Hazards

While downward pipe movement produces positive surge pressure, upward casing movement generates negative swab pressure ($-\Delta P_{\text{swab}}$):

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

Casing running operations frequently require upward pipe movement:

• Picking up out of the slips to disengage spider slips.
• Working tight hole or sticky bridges encountered in swelling shales.
• Reciprocating casing while circulating or conditioning mud prior to cementing.

Because of the extreme diametrical restriction, swabbing with casing is vastly more severe than swabbing with drillpipe. Pulling casing too rapidly creates an acute suction effect beneath the casing shoe. If $BHP_{\text{swab}}$ drops below the pore pressure ($P_{\text{pore}}$) of an exposed formation, formation fluids (gas, oil, or water) are swabbed directly into the annulus. Swabbed gas migrates up the narrow annulus, expanding rapidly as it nears the surface and displacing large volumes of mud.

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Establishing Maximum Running Speed Schedules and Supervisor Controls

To prevent both induced formation fracturing from surge and reservoir swabbing from reciprocation, the drilling supervisor must establish and rigorously enforce a Maximum Casing Running Speed Schedule.

Prior to the casing run, specialized hydraulics software models the wellbore geometry, casing centralization, mud rheology (PV, YP, gels), and formation fracture limits (from the LOT). Use the model to prepare an approved depth-dependent running and pickup/acceleration schedule. Check the actual joint lengths and observed pressure/return response, and revise the programme if conditions differ from its inputs. The following supplied rates illustrate time conversion only; they are not recommended operating limits.

Supervisor Rig-Floor Implementation Rules

1. Verify Actual Running Motion: Assign responsibility for monitoring speed, acceleration and return volumes against the approved schedule. Use actual joint lengths when convertingft/min toseconds/joint; elapsed joint time alone can conceal a brief overspeed.
2. Controlled Acceleration and Deceleration: Driller must avoid sudden brake snatching. Lowering must begin gently to gradually break static mud gels, achieve steady running speed, and decelerate smoothly before setting in slips.
3. Casing Centralization Considerations: Centralizers optimize cement standoff but create localized flow restrictions that increase surge pressures. Centralizer blade design (rigid vs spiral vs bow-spring) must be accounted for in hydraulic surge models.
4. Pre-Casing Mud Conditioning: Before pulling the drilling assembly to run casing, circulate and condition the drilling mud to lower plastic viscosity and yield point to the lowest practical levels consistent with hole cleaning and cutting suspension.