7.4 Well Control Complications: Plugged Nozzles, Washouts & Pump Failure

Executing a constant bottomhole pressure kill requires the drilling supervisor to continuously interpret surface pressure gauges. When mechanical equipment suffers downhole degradation or surface failure, gauge responses change instantly. Misinterpreting these anomalies leads to catastrophic operational blunders—such as opening the choke on a plugged nozzle or closing the choke on a drillpipe washout. Mastery of well control complication diagnostics is a core competency tested at IWCF Level 4.

---

Systematic Diagnostics of Downhole and Surface Complications

At fixed gauge locations, the circulating pressure balance is: $P_{\text{SPP}}=P_{\text{choke}}+(H_{\text{ann}}-H_{\text{dp}})+F_{\text{surface}}+F_{\text{pipe}}+F_{\text{bit}}+F_{\text{ann}}+F_{\text{return}}$ Here H denotes hydrostatic head and F denotes the corresponding flowing pressure loss. Include only the equipment between the actual gauge points. A casing gauge measures pressure at its own tapping; hydrostatic head and return friction relate that local reading to pressure downhole.

A partial nozzle restriction can raise drillpipe pressure without changing casing pressure at constant flow. A choke restriction commonly raises both. These are diagnostic leads, not unique proof. Check actual delivery (spm alone is insufficient), expected fluid-front changes, gauge/valve communication, returns and losses before acting on the pattern.

---

Bit Nozzle Plugging: Symptoms, Diagnostic Traps & Management

Downhole Mechanics

During kill circulation, drilling fluid carrying dried pipe scale, lost circulation material (LCM), or downhole debris can bridge across one or more tungsten carbide bit nozzle orifices, suddenly reducing total flow area (TFA).

Typical Partial-Restriction Signature at Verified Constant Flow

Assume unchanged fluid properties/front position and a communicating pressure path.

• Drillpipe Standpipe Pressure: A sudden rise from added restriction; its size depends on the restriction and flow.
• Casing Pressure: Remains completely constant.
• Pump Speed (SPM): Remains constant.
• Pit Volume Returns: Remain steady.

The Fatal Operator Trap

A novice choke operator observing the standpipe pressure spike mistakenly assumes that bottomhole pressure has increased or that an overbalanced pressure surge is occurring. The operator opens the hydraulic choke to force drillpipe pressure back down to the target schedule.

Supervisor Response

1. Do not open the choke simply to remove the standpipe-pressure rise. Coordinate shutdown while preserving BHP, including CLF compensation where required.
2. Check static pressures and communication. A partial nozzle restriction has no flowing loss when stopped; a completely plugged string can isolate the drillpipe gauge, so its static reading is not automatically valid SIDPP.
3. If circulation can safely resume, establish the new pressure reference at the selected actual flow. For the same fluid and flow, the measured excess is added hydraulic loss.
4. If kill mud has not reached the bit, rebuild the remaining schedule from that new reference and fluid-front position. Do not carry a fixed offset unchanged through different fluids/rates. Watch for the obstruction clearing and the reference changing again.

---

Drillstring and Bit Nozzle Washouts: Identification & Response

Downhole Mechanics

A washout occurs when high-velocity, abrasive drilling mud erodes a leak path through a bit nozzle insert, a tool joint thread seal, or a fatigue crack in the drillpipe body.

Possible Washout Signature at Verified Constant Flow

First exclude normal pressure changes from displacement, density or pump delivery.

• Drillpipe Standpipe Pressure: An unexplained decline as the hydraulic path changes; timing and magnitude alone do not establish the fault.
• Casing Pressure: Remains completely constant.
• Pump Speed (SPM): Remains constant.

The Fatal Operator Trap

The choke operator assumes bottomhole pressure is dropping and pinches the choke inward to force standpipe pressure back up to the schedule.

Supervisor Response

1. Coordinate shutdown and secure the well, preserving BHP as flowing losses disappear. Check actual flow, returns, gauges and expected pressure changes from fluid displacement.
2. Distinguish nozzle erosion from a hole in the string. A hole above the influx can make drillpipe pressure communicate with the annulus at that higher point; apparently normal static readings do not prove bottomhole control.
3. Assess the pipe-parting hazard and the available pressure path before further circulation. A confirmed nozzle washout may permit continued circulation after re-establishing its hydraulic reference and remaining schedule.
4. A pipe washout or loss of reliable bottomhole communication requires the appropriate well-specific contingency. Do not keep circulating a damaged string merely by subtracting the old pressure difference from every target.

---

Complete Rig Mud Pump Failure: Emergency Protocols

If the active kill pump suffers a catastrophic mechanical failure (tripped drive motor, fractured crankshaft, or blown fluid end valve), circulation terminates instantaneously.

Immediate Rig Crew Actions:

1. Immediate Shut-In Coordination: The Driller immediately alerts the Choke Operator. The Choke Operator promptly closes the choke to secure the well, accounting for disappearing return-path friction in the approved shutdown response and monitoring the resulting pressures.
2. Isolate the Drillstring: Close the standpipe manifold valve and, if necessary, close the drillpipe safety valve (Full Opening Safety Valve, FOSV, or Lower Kelly Cock) to prevent backflow.
3. Record Stabilized Pressures: Monitor and log the static shut-in pressures ($\text{SIDPP}$ and $\text{SICP}$).
4. Switch to Standby Pump: Switch the pump suction and discharge lines on the rig manifold to the secondary standby pump (Pump 2 or Pump 3).
5. Establish the Standby Flow and Pressure Reference:
   • Use the standby pump's verified output, not the failed pump's spm. For example, 30 spm at 0.120 bbl/stroke delivers 3.60 bbl/min; a 0.100 bbl/stroke standby pump needs 36 spm for that flow.
   • Update remaining displacement volumes and the counter conversion for the new pump.
   • Bring it to the selected flow while preserving BHP with the appropriate casing/CLF reference. Stabilize and check the new drillpipe reference for the current fluids and front positions.
   • Recalculate the remaining schedule as required; the original pump's targets and strokes are not automatically transferable.

---

Choke Manifold Complications: Washouts and Plugging

Because the choke manifold handles high-velocity mixtures of gas, liquid mud, and abrasive formation cuttings, chokes are vulnerable to severe wear and blockage.

1. Choke Washout (Erosion of Choke Trim)

• Symptom: Casing pressure begins to drop steadily. The Choke Operator pushes the hydraulic control to close the choke. The choke position indicator shows the choke moving from 20% -> 10% -> 5% -> 0% (fully closed), yet casing pressure continues to fall, and drillpipe pressure drops simultaneously.
• Cause: High-velocity abrasive fluid has cut a channel through the tungsten carbide seat or disc.

2. Choke Plugging (Debris or Hydrates)

• Symptom: Casing pressure and drillpipe pressure spike upward rapidly and simultaneously. The Choke Operator opens the choke to 30% -> 50% -> 80%, but pressures continue climbing.
• Cause: Large formation cavings, lost circulation material, or methane gas hydrate crystals have bridged the choke orifice.

Emergency Choke Switching Protocol:

Use the installed manifold configuration and applicable installation requirements, including API Standard 53 where specified. API Spec 16C covers equipment design and manufacture; it does not make one remote plus one manual choke suitable for every pressure class:

1. Alert the crew and confirm the installed manifold's approved switching lineup and standby choke/control readiness.
2. Preposition the standby choke as required for a controlled transfer; verify its downstream return route before opening the branch isolations.
3. Transfer flow in a coordinated way, manipulating the standby choke to maintain the planned pressure reference while isolating the failed branch. If control cannot be maintained, secure the well using the approved response.
4. Verify the failed branch is isolated from all pressure sources. Release trapped pressure through the designated controlled bleed route and confirm isolation/zero energy before maintenance.

---

Comprehensive IWCF Well Control Complications Diagnostic Matrix