1. Drilling Fluid Properties Not Meeting Requirements
Excessive viscosity and gel strength can lead to bit balling and swab pressure during tripping out, reducing bottom hole pressure and causing a blowout. Additionally, high viscosity and gel strength may result in excessive surge pressure during tripping in or high pump pressure during startup, which can fracture the formation and trigger a blowout.
Prevention:
Adjust drilling fluid properties before entering oil, gas, or water zones.
Ensure drilling fluid density meets design specifications.
Under the premise of effective cuttings transport, use the lowest feasible viscosity and gel strength to minimize bit balling and reduce swab/surge pressures during tripping operations.
2. Bit Balling and Piston-Effect During Tripping Out
Bit balling during tripping out creates a piston effect, preventing annular fluid replenishment and generating high swab pressure, which reduces bottom hole pressure. Additionally, the rapid drop in fluid level within the drill string during piston-effect tripping can lead to insufficient internal fluid column pressure to balance formation pressure, potentially causing an internal blowout.
Prevention:
Adjust drilling fluid properties before tripping: Reduce viscosity and gel strength, and remove poor-quality solids.
Monitor and control tripping speed: Closely observe tripping operations. If piston-effect symptoms occur (e.g., tripping resistance, inability to fill the annulus, fluid movement with the drill string, rapid fluid level drop in the drill string):Immediately connect the kelly to circulate and back-ream the hole.
Retrieve the drill string incrementally (e.g., one joint at a time).
Ensure the annulus is fully filled with fluid before pulling stands.
Strictly prohibit aggressive pipe movement without circulation if piston effects are observed.
3. Aggressive Pipe Movement Without Circulation in Open Hydrocarbon Zones
Conducting aggressive up/down pipe movement in open hydrocarbon zones without circulation generates swab pressure. If the hydrostatic pressure drops below the formation pore pressure, hydrocarbons will invade the wellbore.
Prevention:
If tripping is not feasible due to equipment issues:
Connect the kelly to circulate.
If circulation is impossible, prioritize rotating the drill string over vertical movement. Control tripping speeds strictly (per well control regulations: ≤0.5 m/s in hydrocarbon zones and within 300m above them).
After equipment repairs:
Resume circulation immediately.
If the well exhibits active hydrocarbons or downhole complexity, run back to bottom, circulate thoroughly to condition the drilling fluid, and then resume tripping.
4. Insufficient Circulation Time Before Tripping
The lag time required for fluid circulation from the bottom to the surface is ** minutes. Inadequate circulation time before tripping prevents timely detection of gas-cut fluid or overflow indicators. During tripping, unavoidable swab pressure, delayed fluid replenishment, or gas migration further reduce bottom hole pressure, leading to a kick.
Prevention:
Ensure the following conditions are met before tripping:
Adjust drilling fluid properties and circulate at least 2 hole volumes to homogenize fluid density, ensuring the inlet/outlet density difference ≤0.02 g/cm³.
Total gas content must be <10% with a declining trend.
Stop pumps and observe fluid return for 15 minutes to confirm no overflow.
5. Improper Handling of Lost Circulation During Drilling
When lost circulation occurs, hastily tripping out after merely filling the hole-without verifying loss volumes, replenishment rates, or observing annular fluid level changes-ignores the blowout risks from exposed hydrocarbon zones (e.g., shallow gas). Overemphasis on static well control and preventing pipe sticking due to hole collapse overlooks critical well control priorities.
Prevention:
If lost circulation occurs in a drilled hydrocarbon zone:
Pull off bottom and position the kelly above the rotary table.
Stop circulation and implement timed, quantified annular fluid replenishment to maintain hydrostatic pressure balance with the formation, preventing influx.
Avoid disconnecting the kelly for tripping until well conditions are fully stabilized and understood.
6. Excessive/Uneven Oil/Water Addition During Fluid Treatment
- Over-mixing oil/water reduces fluid density, causing bottom hole pressure imbalance.
- Prevention: Control fluid density during treatment; monitor inlet/outlet density during oil/water addition.
7. Failure to Promptly Degas Severely Gas-Cut Drilling Fluid
When drilling through high-pressure hydrocarbon zones, drilling fluid inevitably becomes gas-cut (via cuttings, displacement, diffusion, or gas influx), reducing its density. If untreated gas-cut fluid is recirculated, it further decreases the hydrostatic pressure, increasing well control risks.
Prevention:
Continuously monitor fluid density during drilling.
Immediately activate degassers and apply defoamers upon detecting gas invasion.
Adjust fluid density promptly to prevent recirculation of gas-cut fluid.
For highly active gas zones, perform staged circulation during tripping-in to prevent gas expansion and migration from causing well influx.
8. Failure to Shut Off or Bleed Down Injection Wells
In mature fields with complex injection networks, prolonged water/gas injection has altered original formation pressures, creating significant inter-layer pressure variations. This makes accurate mud weight determination challenging during drilling, often leading to well control incidents such as kicks.
Prevention:
Per oil and gas drilling regulations:
Shut off adjacent water/gas injection wells and bleed down pressure to specified levels before penetrating hydrocarbon zones.
Survey surrounding injection wells prior to reservoir penetration.
Prohibit drilling into hydrocarbon zones until injection wells are confirmed shut off and pressure-bleeded to required thresholds.
9. Improper Kick Response or Failed Well Kill
Errors in handling kicks include:
Delaying shut-in to continue observing the kick.
Attempting to increase mud weight while drilling.
Connecting the kelly during tripping-induced influx.
Hard shut-in (abruptly closing BOPs without proper procedures).
Closing pipe rams before the annular preventer.
Exceeding maximum allowable shut-in casing pressure (MAASP) without bleeding.
Premature pressure bleeding below MAASP.
Failing to kill the well post-shut-in.
Using kill fluid with incorrect density (too high or low).
Poorly designed kill procedures.
Prevention:
Adhere to the principle:"Shut in immediately upon kick detection; shut in for suspected kicks."
Execute shut-in per standard protocols upon kick signs. After shut-in, promptly obtain shut-in drill pipe pressure (SIDPP), shut-in casing pressure (SICP), and influx volume.
During tripping, urgently install a check valve or safety valve if a kick occurs.
Never exceed MAASP under any circumstances. Avoid bleeding within the allowable pressure range.
Never leave gas kicks untreated during prolonged shut-in due to gas migration risks.
Conduct detailed kill calculations and designs, ensuring appropriate kill fluid density. Assign dedicated personnel to monitor casing pressure during kills.
Strictly prohibit increasing mud weight while drilling without shut-in.
10. Non-compliant BOP Configuration, Installation, or Pressure Testing
Improper installation or pressure testing of blowout preventers (BOPs) may result in failed well control (e.g., leaking rams, insecure connections, insufficient pressure ratings, incorrect valve positions, failure of remote control systems), ultimately leading to uncontrolled blowouts.
Prevention:
Design and selection: Base BOP selection on the anticipated maximum surface pressure derived from geological and wellbore design.
Install high-pressure-rated BOP systems for wells with mud density ≥1.50 g/cm³, ultra-deep wells, exploratory wells, or environmentally sensitive areas.
Equip regional exploratory wells and high-risk wells (HTHP) with shear rams.
Installation and testing: Install and pressure-test BOPs strictly per regulations to ensure reliability.
Pre-drilling checks: Before penetrating hydrocarbon zones, thoroughly inspect all drilling equipment and BOP systems to eliminate potential failures.
11. Drilling into Shallow Gas Zones
Causes:
Geological designs fail to highlight shallow gas risks, or crews neglect hazards during operations in known shallow gas areas.
Characteristics of Shallow Gas Blowouts:
Sudden onset: Shallow gas reservoirs are small, localized, and unpredictable. Due to shallow depth, gas influx reaches the surface rapidly, making blowouts nearly inevitable once influx occurs.
Formation fracturing risk: Shallow formations are soft and weak, fracturing at pressures as low as 2 MPa. Even with good surface casing cementing, hard shut-in during a blowout may cause external leaks, risking rig subsidence.
Prevention:
Pre-spud preparation: Conduct technical and safety briefings by engineers to emphasize shallow gas risks.
For anticipated shallow gas zones: Install diverter systems to redirect gas safely.
Minimize stabilizers in bottom hole assemblies (BHAs) to reduce bit balling and swab pressure risks.
Equip drill strings with internal blowout preventers (IBOPs) to seal the string during tripping.
Rigorously install and test BOPs; monitor casing pressure post-shut-in to avoid formation fracture.
Use adequate drilling fluid density to offset swab effects and maintain hydrostatic balance.
12. Unmanned Monitoring Leading to Undetected Kicks
When hydrocarbons invade the wellbore, a kick occurs. Failure to detect it promptly allows the influx volume to increase, continuously reducing hydrostatic pressure until a blowout is triggered.
Prevention:
Enforce responsibility protocols: Implement 24/7 manned monitoring of wellbore and fluid dynamics.
Continuous observation: From the moment hydrocarbon zones are penetrated, assign dedicated personnel to monitor wellhead returns and drilling fluid pit levels during all operations (drilling, tripping, logging, maintenance, standby).
Immediate action: Activate emergency protocols (e.g., shut-in procedures) instantly upon detecting abnormal fluid returns or pit level changes.
13. Inadequate Casing Design (Shallow Setting Depth)
Causes:
Excessively shallow casing setting depth prevents the casing shoe formation from withstanding high shut-in pressures during a blowout, forcing crews to either avoid shutting in the well or risk fracturing the formation, escalating to an uncontrolled blowout.
Prevention:
Design casing programs based on:
Formation pore pressure, fracture pressure, and collapse pressure profiles.
Avoid overlapping zones with extreme pressure differentials (e.g., co-existing lost circulation and kick zones) in a single open hole section.
For wells without intermediate casing:
Ensure surface casing depth provides sufficient fracture pressure gradient at the casing shoe to exceed the target zone's pore pressure gradient.
Account for operational duration and casing wear to maintain casing internal pressure resistance for well control requirements by the completion phase.
14. Insufficient Weighted Drilling Fluid Reserves
Causes:
Inadequate reserves of weighted drilling fluid delay the preparation of kill-weight fluid, missing critical timing for well control.
Prevention:
Before drilling into hydrocarbon zones:
Stockpile weighted drilling fluid equivalent to the hole volume and sufficient weighting agents.
For sour (H₂S-containing) wells, stockpile 0.5–2 times the hole volume of drilling fluid with a density **≥0.1 g/cm³ higher than the active fluid.
15. Failure to Perform Short Trips
Causes:
During near-balanced drilling, annular friction pressure loss during circulation helps balance formation pressure. When circulation stops or during tripping, the loss of this friction pressure can reduce bottom hole pressure below formation pressure, triggering a kick.
Prevention:
Verify pressure balance before tripping:
Perform a short test trip (pull 10–15 stands of drill pipe).
Run back to bottom and circulate for at least one full cycle.
Monitor returns: If no gas/oil invasion is detected and gas migration rates are acceptable, proceed with tripping.
If gas/oil invasion or excessive migration is observed, continue circulating to condition the fluid and adjust drilling fluid density appropriately to prevent kicks during tripping.
Mandatory Short Trip Scenarios:
Before first tripping after penetrating a hydrocarbon zone.
After killing a kick and before resuming tripping.
After lost circulation in a hydrocarbon zone (even if not fully sealed) and before tripping.
Before tripping if severe gas/oil invasion occurred during drilling (without a kick).
When prolonged bit-on-bottom operations require tripping to ream/clean the hole.
Before tripping for extended non-circulation activities (e.g., logging, casing runs).
16. Well Kick During Extended Non-Circulation Periods (e.g., Logging or Casing Runs)
After penetrating hydrocarbon zones, gas from the formation continuously migrates into the wellbore. Prolonged static periods (e.g., logging, casing runs) allow gas to rise, reducing hydrostatic pressure and leading to a blowout.
Prevention:
Prohibit equipment maintenance with an empty wellbore.
For long open-hole sections (prone to permeability losses): Implement scheduled fluid replenishment during extended downtime.
Conduct equipment maintenance only after positioning the drill string at the technical casing shoe for emergency control.
For planned long non-circulation periods (e.g., logging): Pull the drill string into the casing shoe or a stable interval.
Observe for one trip cycle or equivalent static time after stopping pumps.
Run back to bottom, circulate one full cycle, and check returns for gas/oil invasion. If invasion is detected: Adjust and treat the drilling fluid.
If no invasion: Proceed with tripping.
Assign dedicated personnel to monitor fluid returns and pit levels, documenting anomalies and responding immediately.
For extended logging/casing operations: Add reaming runs to maintain hole stability.
In gas wells, perform intermediate circulation during prolonged casing runs to vent accumulated gas.
17. Formation Fracture During Tripping-In (Caused by Excessive Surge Pressure)
Causes:
Excessive tripping-in speed generates surge pressure exceeding formation strength.
Poor drilling fluid properties (e.g., high viscosity, inadequate gel strength) amplify surge effects.
Aggressive pump startup (high pump pressure spikes) fractures weak or depleted zones.
Prevention:
Tripping speed control:
Limit tripping-in speed to **<0.5 m/s** in open-hole hydrocarbon zones to minimize surge pressure.
Staged pump activation:
Break circulation in segments during tripping-in, avoiding direct startup across known lost circulation zones.
Gradual pump ramp-up: Use a slow, controlled pump rate to prevent pressure spikes.
Gas migration management:
In penetrated hydrocarbon zones, perform staged circulation during tripping-in to vent gas pockets and stabilize hydrostatic pressure.
Fluid property optimization:
Maintain low viscosity and gel strength (while ensuring adequate hole cleaning) to reduce surge pressure risks.
Key Operational Notes:
Monitor real-time ECD (Equivalent Circulating Density) to ensure surge pressure remains below formation fracture gradient.
Prioritize soft formations or depleted zones for staged circulation and slower tripping speeds.
18. Blowout During Cementing Operations
The causes of blowouts during cementing are: the density of the spacer fluid is lower than that of the drilling fluid and its usage is excessive; the hydrostatic pressure of the mud + spacer fluid + cement slurry column is less than the formation pressure; lost circulation occurs during cementing, failing to isolate the upper hydrocarbon zones; and insufficient annular hydrostatic pressure due to cement slurry weight loss during the waiting-on-cement (WOC) period. These causes will reduce the drilling fluid column pressure, destabilizing the reservoir and gradually inducing hydrocarbon influx, leading to a blowout.
Prevention: During cementing, well control technical measures for the completion process should be in place to ensure the safety of the entire well. Post-cementing monitoring duties must be strictly implemented. Emergency response plans must be established and promptly activated if casing-annulus flow or surface leaks are detected.
19. Manipulating Drill Pipe Under Shut-In Conditions
Causes:
After shutting in the well, concerns about stuck pipe may lead to attempts to manipulate the drill string under pressurized conditions, risking damage to the ram packer elements and subsequent uncontrolled blowouts.
Prevention:
Conditions for safe pipe movement: A reliable BOP system with backup rams must be available.
Reduce control hydraulic pressure appropriately while maintaining effective well shut-in.
Operational guidelines: Avoid pipe manipulation if the BOP system lacks redundancy or reliability.
Priority: Preserve wellhead integrity. An uncontrolled blowout poses far greater risks than stuck pipe.
Regulatory compliance (per Oil & Gas Drilling Well Control Technical Specifications): With annular or ram BOPs closed and shut-in casing pressure ≤14 MPa: Vertical movement of drill pipe is permitted at speeds **≤0.2 m/s**.
Rotation or tool joint passage through packer elements is strictly prohibited.
Critical Notes:
Risk assessment: Weigh blowout risks against stuck pipe mitigation.
Real-time monitoring: Track hydraulic pressure and wellhead status during any manipulation.
Training: Rig crews must be drilled in shut-in protocols and BOP limitations.
20. Formation Fracture Due to Excessive Shut-In Pressure
Causes:
Uncontrolled shut-in pressure: Lack of knowledge about the maximum allowable shut-in casing pressure leads to excessive bottom hole pressure during shut-in, fracturing the formation and causing lost circulation followed by a blowout.
Unmonitored gas migration: Failure to observe casing pressure changes during/after shut-in allows gas to migrate upward, escalating casing pressure until it fractures the formation or damages well control equipment, resulting in loss of control.
Prevention:
Formation integrity testing: After running surface or intermediate casing, conduct a formation fracture pressure test in the first drilled sandstone interval to determine the fracture pressure gradient. This data guides maximum safe shut-in casing pressure limits during blowout scenarios.
Real-time pressure monitoring: Assign dedicated personnel to monitor shut-in casing pressure continuously. Ensure pressure never exceeds the maximum allowable value calculated from the drilling fluid density and formation fracture gradient.
Emergency response protocol: If casing pressure approaches critical levels, implement controlled pressure release or bullheading to prevent formation fracture.
Key Technical References:
Maximum allowable shut-in casing pressure (MAASP): MAASP=(Fracture Pressure Gradient−Current Mud Gradient)×Casing Shoe TVDMAASP = (Fracture\ Pressure\ Gradient - Current\ Mud\ Gradient) \times Casing\ Shoe\ TVDMAASP=(Fracture Pressure Gradient−Current Mud Gradient)×Casing Shoe TVD
Critical actions: Update MAASP after any mud density change or casing shoe integrity test.
For gas influx, account for gas migration rate (typically 150–300 m/h) when estimating pressure escalation.