Swabbing and Surging During Tripping Operations

Swabbing and Surging During Tripping Operations

Tripping the drill string—either pulling out of the hole (POOH) or running into the hole (RIH)—can introduce significant dynamic pressure changes in the wellbore. These pressure fluctuations are known as swabbing and surging, and they pose significant risks to primary well control, and require attention to pressure margin as well as pipe-handling tasks.

The Mechanics of Swabbing and Surging

Swabbing is the reduction in bottomhole pressure (BHP) caused by the upward movement of the drill string. As the pipe is pulled, fluid must flow downward through the annular space to fill the void left below the bit. The viscous drag of the fluid moving against the pipe and the wellbore walls creates a frictional pressure loss, reducing the pressure below the moving assembly; the dynamic pressure change is separate from the static hydrostatic head. If the swab pressure exceeds the overbalance margin, formation fluids will be drawn into the wellbore.

Surging is the exact opposite. It is the increase in BHP caused by the downward movement of the drill string. As the pipe is lowered, it displaces fluid, forcing it to flow upward through the annulus at high velocity. This creates a positive frictional pressure, adding to the hydrostatic pressure at the bottom of the hole. Severe surging can easily exceed the formation fracture gradient, leading to induced fractures, severe lost circulation, and the subsequent loss of hydrostatic head.

Physics and the Piston Effect

The severity of swabbing and surging is governed by the 'piston effect,' which depends on several interrelated mechanical and rheological factors evaluated under the Bingham Plastic or Power Law fluid models:

Calculating Swab and Surge Pressure Loss

During a tripping operation, the effective Bottomhole Pressure while pulling is calculated as:

$$BHP = HP - \Delta P_{\text{swab}}$$

During running in hole, the effective Bottomhole Pressure is:

$$BHP = HP + \Delta P_{\text{surge}}$$

For example, assume a well has a True Vertical Depth (TVD) of 12,000 ft with a mud weight of 11.5 ppg. The static Hydrostatic Pressure (HP) is:

$$HP = 0.052 \times 11.5 \times 12,000 = 7,176 \text{ psi}$$

If advanced dynamic rheology models (such as Bingham-Plastic or Herschel-Bulkley) determine that pulling the BHA at 90 ft/min generates a swab pressure ($\Delta P_{\text{swab}}$) of 350 psi, the effective BHP while pulling becomes:

$$BHP = 7,176 - 350 = 6,826 \text{ psi}$$

If the formation pore pressure at this depth is 7,000 psi, the static mud column is overbalanced by 176 psi. However, during the pipe movement, the effective BHP falls 174 psi below the pore pressure. An exposed permeable formation can supply an influx during this underbalance. Its rate depends on the pressure difference and formation flow characteristics; the calculation does not establish that a fixed influx volume must enter.

Mitigation Practices for Safe Tripping

To prevent swabbing an influx or surging the formation, drillers must employ stringent, mathematically sound mitigation practices:

Condition the hole and mud at the points specified in the programme rather than a universal stand interval. Pumping out can reduce swab risk only if verified output fills the increasing space below the bit and the planned pressure support is sufficient. Rotation or circulation does not guarantee zero swab pressure. Stop movement on unexpected drag, fill or flow behaviour, communicate and follow the approved evaluation and influx response.

Use the margin as a limit, not a speed prescription

In the example, the static overbalance is 176 psi. A supplied swab estimate of 100 psi would leave 76 psi overbalance, whereas the 350 psi estimate creates 174 psi underbalance. Neither result establishes an authorised tripping speed: use the actual model, uncertainty, geometry and approved limit. A tight interval or balled assembly can change the pressure response at a previously acceptable speed. Pipe speed alone cannot establish safety without these conditions.

For the opposite movement, suppose the supplied surge estimate is 300 psi. The estimated moving BHP is 7,176 + 300 = 7,476 psi. If the applicable weakest-point allowance for this simplified example is 7,400 psi at the same reference depth, that limit is exceeded by 76 psi. Check the actual pressure at each exposed weak interval in a real well; a bottom-depth comparison cannot replace the complete pressure profile. Surge-induced losses can later reduce static head if fluid level falls.

Measure fill and returns while controlling movement. Unexpected drag, a restricted flow path or an unexplained volume difference requires the approved evaluation and response even if the last model predicted a safe margin. Pumping out changes the fluid balance and pressure support but does not remove the need to monitor both. Record what moved, the fill expected, the volume observed and any rate or drag change so the supervisor can distinguish a geometric change from a possible influx.

Measured depth, horizontal intervals and vessel movement

A long measured flow path can produce significant displacement friction even where its added vertical head is small. Horizontal geometry, eccentric pipe, cuttings beds and restricted BHA clearance can worsen the flow restriction. TVD still sets the simple static head; MD and geometry influence the dynamic flow path. Use the actual tripping assessment rather than treating a shallow TVD as proof of low swab risk.

On a floating rig, vessel motion can move the string relative to the well even without an intended trip. Inadequate motion compensation or an unsuitable fixed support condition can produce repeated upward and downward movement, adding swab/surge transients and confusing volume observations. Confirm the applicable compensation, motion limits and monitoring arrangement with the supervisor. Do not interpret a heave-related volume oscillation as proof that every persistent gain is harmless. Record the motion pattern and distinguish reversible fluctuations from an unexplained cumulative change.