16.2 Plugged Drillpipe Nozzles, Float Failures & Drillstring Washouts

Plugged Drillpipe Nozzles, Float Failures & Drillstring Washouts

During a well kill, surface pressures depend on actual flow, fluid properties and positions, flow-path restrictions and annular backpressure. When downhole mechanical components fail—such as bit nozzles plugging with debris, the drillpipe parting or washing out, or the bit float valve failing to indicate shut-in pressure—surface gauge readings diverge abruptly from pre-calculated kill sheets.

The supervisor compares deviations with the expected kill-phase pressure and volume trends, checks instruments and actual flow, and applies the contingency procedure while preserving BHP. A gauge pattern is a lead to investigate, not an instant unique diagnosis.

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Plugged Bit Nozzles: Hydraulic Mechanics and Schedule Adjustment

Bit nozzles are engineered orifices designed to accelerate drilling fluid into high-velocity jets. The pressure drop across the bit nozzles increases with fluid density and the square of flow rate, and decreases with the square of total flow area for unchanged discharge behaviour:

$\Delta P_{bit}\propto\frac{\rho Q^2}{TFA^2}$

Here $Q$ is flow rate, $\rho$ is mud density and $TFA$ is the sum of the open nozzle areas. For unchanged flow, density and discharge coefficient:

$\frac{\Delta P_{bit,2}}{\Delta P_{bit,1}}=\left(\frac{TFA_1}{TFA_2}\right)^2$

Reducing TFA from 0.45 to 0.30 square inches gives a pressure-loss ratio of 2.25; an original 400 psi bit loss becomes 900 psi. Use the applicable nozzle model and units for an absolute pressure-loss calculation.

                  PLUGGED BIT NOZZLE HYDRAULICS

   Normal Circulation:               One Nozzle Plugged:
   ┌───────────────┐                 ┌───────────────┐
   │ TFA = 0.45 sq │                 │ TFA = 0.30 sq │ (Reduced Area)
   └───────┬───────┘                 └───────┬───────┘
           ▼                                 ▼
   ΔP_bit = 400 psi                  ΔP_bit = 900 psi (ΔP_plug = +500 psi)
           │                                 │
           ▼                                 ▼
   ICP = 1,150 psi                   ICP_new = 1,650 psi (STEP INCREASE)
   Casing P = 600 psi (CONSTANT)     Casing P = 600 psi (NO CHANGE!)

Diagnostic Signature of a Plugged Nozzle

At unchanged actual flow and fluid conditions, a sudden drillpipe-pressure rise without a corresponding annulus-pressure rise suggests an added restriction inside the string. Partial nozzle plugging is one possible cause. Confirm pump output, gauges, fluid fronts and returns; constantSPM alone does not prove constant flow. Complete blockage can stop circulation and isolate the drillpipe gauge from the annulus.

The Fatal Error: Throttling the Choke

When drillpipe pressure suddenly spikes by $300\text{ to }500\text{ psi}$, an inexperienced driller or choke operator may instinctively open the hydraulic choke to bring drillpipe pressure back down to the target value on the kill sheet graph.

Re-establishing the Circulating Schedule

Make a controlled shutdown when required to diagnose the restriction and preserve pressure limits. Check whether the string still communicates with the well; a completely plugged string cannot supply normal static SIDPP or a conventional circulating kill path.

For a partial restriction that permits safe circulation, establish a new circulating reference at the chosen actual flow while maintaining the appropriate BHP reference during startup. Rebuild the remaining pressure schedule for the current fluid fronts, density and rate, including subsea CLF compensation where applicable.

At an unchanged flow and density, an additional measured restriction loss can be added to the corresponding current target. It is not automatically a constant addition to all later targets: nozzle loss changes with density and flow. Monitor for the plug clearing, which would invalidate the increased target again.

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Drillstring Washouts: Recognition, Hazards, and Emergency Isolation

A drillstring washout occurs when drilling mud erodes a cavity through a tool joint connection, pin-box thread, or cracked drillpipe body, creating an unintended flow communication path between the inside of the drillstring and the annulus.

                    DRILLSTRING WASHOUT MECHANICS

                      [Standpipe Manifold]
                                │
                                ▼
                      [Drillpipe Bore]
                                │
                         WASHOUT HOLE
                 ┌──────────────┴──────────────┐
                 ▼                             ▼
       [Flow Escapes into Annulus]    [Reduced Flow to Bit]
                 │                             │
                 ▼                             ▼
        Drillpipe Pressure             Bit Pressure Drop
        DROPS STEADILY                 COLLAPSES
                 │                             │
                 └──────────────┬──────────────┘
                                │
                                ▼
           [Catastrophic Twist-Off Threat under Tension]

Diagnostic Signature of a Washout

At unchanged actual flow and fluid conditions, an unexplained drillpipe-pressure decline without a corresponding casing-pressure decline suggests reduced drillstring/bit resistance. A pipe washout, nozzle erosion or another restriction change can produce this pattern. Normal kill-mud displacement can also reduce drillpipe pressure, so compare the reading with the current method phase and fluid-front position.

Pipe-Parting Risk and Response

A pipe washout can enlarge under abrasive flow and weaken a connection or pipe body. Continued circulation may lead to parting; the rate of damage and remaining strength are not known from the surface pressure decline. Losing the lower string can remove access to the bit and constrain the available kill methods.

1. Make a controlled pump shutdown and shut in under the established procedure, preserving well support while friction pressure decays.
2. Check instruments, actual pump output and fluid-front position. Distinguish a possible pipe washout from nozzle erosion or a normal scheduled pressure decline.
3. Assess string integrity and loads. Hang off only if required by the approved contingency and within the actual ram, pipe, tooljoint and load ratings; it is not an automatic step on every floating rig.
4. Determine whether the suspected hole lies above or below the influx and whether SIDPP still represents the bottomhole pressure. Pressure readings and fluid profiles may constrain its location but do not uniquely locate it; any further diagnostic intervention requires its own planned pressure-control arrangement.
5. Reassess the kill method. A leak above the influx can invalidate conventional DP-pressure control of BHP. Use the appropriate off-bottom/migration contingency when communication is unsuitable. Do not resume merely because the gauges are stable.

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Bit Float Valve Diagnostics: Obtaining SIDPP

A drillstring float is a check valve that restricts reverse flow. An unported closed float can isolate the standpipe gauge, leaving zero or a trapped nonzero reading. Neither is automatically true SIDPP. A float not sealing may allow reverse communication, so use the known valve type and observed behaviour rather than assuming every installed float holds.

CLOSED UNPORTED FLOAT -> standpipe gauge may be isolated
    -> use approved measurement method
    -> record the pressure reference and validity checks

One method uses a recent SCR measurement for the same pump, actual flow, fluid and string configuration:

1. Verify equipment alignment, suitable communicating gauges and stabilized casing-pressure history.
2. Start circulation cautiously, coordinating the choke to preserve BHP. The surface-stack approximation holds the initial casing reference when annular friction is negligible; subsea choke returns require compensation for developing CLF.
3. At the selected recorded low flow, estimate SIDPP as stabilized circulating standpipe pressure minus the corresponding original-mud SCR pressure.
4. Shut down in a controlled manner while preserving well support, and record the result and method. The gauge may become isolated again as the float closes.

Where appropriate, use the approved slow bump/breakback procedure instead. A change of slope can help identify float opening, but it is not by itself an exact static SIDPP: opening resistance, fluid compression and dynamic losses need the method's checks. Do not prescribe a universal 0.10–0.25 bpm rate, quarter-barrel strokes or 100–150 psi spring correction. Confirm pump pressure rating and controllable output; an ordinary trip-tank pump is not automatically suitable for high-pressure injection.

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Worked Scenario: Partial Nozzle Restriction During the Driller's Method

TVD 11200 ft; MD 16500 ft; OMW 13.2 ppg; verified SIDPP 450 psi.
Recorded SCR at the selected actual flow:650 psi; ICP=450+650=1100 psi.
Calculated KMW=13.2+450/(0.052 x 11200)=13.973 ppg; planned density 14.0 ppg.
Original FCP estimate=650 x 14.0/13.2=689 psi, before specified rounding/margins.

During the FIRST circulation, all string fluid remains OMW.
DP pressure rises 1100->1480 psi while the confirmed actual flow,
annulus pressure and returns show no corresponding unexpected change.
A partial nozzle restriction is confirmed; equipment limits permit continuation.

Extra current restriction loss=1480-1100=380 psi.
Re-established OMW circulating loss at that flow=650+380=1030 psi.
The current first-circulation DP target is 1480 psi.
At 14.0 ppg throughout the system, the density-scaled loss estimate is:
FCP_new=1030 x 14.0/13.2=1092 psi.

Do not force DP pressure down to 1100 psi by opening the choke. Use the confirmed revised reference and watch for the obstruction clearing. Maintain the first Driller's circulation DP target while removing the influx; casing pressure varies with annular conditions. After gas removal is verified, the second circulation follows its normal phases: preserve the casing-pressure reference while kill mud displaces the string, then use the revised final circulating DP reference once kill mud reaches the bit. Rebuild the transition schedule and margins for actual conditions rather than adding 380 psi to every future target.