Jetting (Nudging) Top-Hole Sections - Advantages, Challenges, and Best Practices
Jetting is a high‐flow, slide-based technique used to kick off shallow hole sections in very soft formations. The goal of jetting is to wash away a pocket of formation on one side and then direct the bit into that pocket by sliding. It is commonly used on offshore platforms with many nearby wells where anti-collision risks exist at shallow depth.
Typically, one large nozzle and two smaller nozzles (or one large and one blanked) are used in a tricone jet-bit. The large jet creates the side force when oriented correctly, while sliding or rotating controls the directional response. Steerable motors or RSS are used for more predictable steering and smoother hole quality.
When to Use Jetting Your Comments
Soft Near-Surface Formations: Jetting is effective only in soft, unconsolidated formations. If the surface soils are firm (hard chalk, boulders, etc.) or poorly known, jetting is not advised.
High Collision Risk / Tight Slots: Jetting is used to avoid collisions with offset wells/conductors at shallow depths. On multi-well platforms with dozens of slots, anti-collision planning is mandatory. Jetting can “nudge” the path away from a hazard, then return to vertical after passing it.
Limited Kickoff Depth: When kickoff must occur very close to the mudline (e.g., <200–300 m TVD) and the formation is too weak for a conventional motor, jetting (or jetting+RSS) can kick off the well at a short distance.
Deepwater Conductors: In deepwater/conductor installation, jetting is routinely used to drive conductors in place (piling by fluid) when seabed sediment is soft.
Advantages of Jetting Your Comments
Jetting has some unique advantages in these niche cases:
Simplicity and Low Cost: Jetting uses standard rotary equipment (no downhole motor), often just a normal tri-cone or jet bit. No special downhole power source is needed, so the capital cost is low.
Near-Bit Survey Placement: The survey instrument (MWD or gyro) can be located very close behind the bit (near-bit sub), so survey readings reflect the bit’s position almost in real time. This reduces uncertainty in wellbore position when clearance is tight.
Controlled Deflection: The operator can roughly control dogleg severity by choosing how many feet to jet before drilling on. A shorter jet yields less deflection, longer washes yield more. This provides some surface control over build rate.
Collision “Softness”: Because the bit isn’t mud-powered and drilling energy is low, if it contacts a casing, the rate of penetration is much slower than with a motor. This can reduce damage if a minor collision occurs.
Challenges and Limitations of Jetting Your Comments
Jetting has significant downsides that must be considered:
Unpredictable Steering Response: The directional build is achieved by breaking formation, which can result in erratic steering. Small changes in formation hardness can yield significant differences in dogleg. The path tends to be “stepped” rather than smoothly curved.
High Dogleg Severity: Jetting often creates severe local doglegs (e.g., 5–20°/30 m or more). Unless an undergauge hole is jetted and later reamed, the hole geometry will have sharp kinks. Such doglegs strain casing and drillpipe and can cause accelerated wear. Industry practice is to jet a pilot of small diameter and then open up with a hole-opener to smooth the geometry.
Depth/Lithology Limits: Jetting is effective only in very weak formations, typically at shallow depths. It is not effective in competent rock or deep, hard shale.
Risk of Stuck Pipe or Packoff: The jet washes cuttings into a pocket around the bit, which can pack off the collar or stabilizer. Proper hole cleaning (circulating, reciprocating) is essential.
Best Practices for Safe and Controlled Jetting Near Offset Wells Your Comments
Jetting near offset wells demands high precision and careful planning due to the risk of wellbore collisions and unplanned trajectory changes. The guidelines below provide a detailed approach to safely conducting jetting operations when other wells are in close proximity.
1. Anti-Collision and Pre-Job Planning
Start with a detailed and approved anti-collision plan that includes all nearby well paths and their respective positional uncertainties. These should be represented as ellipsoids to visualize possible spatial variation. If possible, validate the positions of offset wells using magnetic or acoustic ranging tools. For any live adjacent well, shut-in procedures should be executed, and if applicable, use sensors like hydrophones or accelerometers placed on the casing or conductor to detect contact sounds during jetting.
2. Frequent and Accurate Surveying
High-frequency directional surveys using gyro or MWD tools are essential before, during, and immediately after jetting. This allows early detection of any unexpected curvature or trajectory deviation. Gyro-MWD tools are particularly useful near the surface or on platform structures where magnetic interference is common and can affect MWD readings.
3. Controlled Sliding to Prevent Doglegs
Avoid long, continuous sliding, as it can lead to excessive and uncontrolled dogleg severity, especially in soft, unconsolidated formations near offset wells. After sliding for a short interval, rotate the drill string to smooth out the wellbore trajectory and reduce localized curvature buildup. This alternating slide-and-rotate technique helps maintain directional control and prevents sharp doglegs.
4. Weight and Flow Management
After the initial jet cut is made, reduce pump rates to about 40–50% of the jetting flow and begin applying high weight on bit (WOB) with low RPM to drive the bit into the wash pocket. This technique encourages the bit to bend into the washed area and build an angle. Avoid excessive pump rates or low WOB, which can wash out the hole without initiating the desired build.
5. Effective Hole Cleaning
Jetting can generate cuttings that settle in the enlarged wash zone. Regular wiper trips or pipe reciprocation help remove these cuttings. If only sliding is performed, ensure circulation through the bit or rotate off-bottom occasionally to keep the hole clean. Poor hole cleaning increases the risk of a stuck pipe.
6. Monitor Dogleg Severity
Before jetting, calculate the maximum dogleg severity the surface casing can handle. Monitor real-time survey data and, if doglegs exceed acceptable limits, consider reaming the section to smooth it out. The casing and drillpipe should be designed to accommodate higher doglegs if necessary. Casing protectors like WWTs should be kept ready in case severe bending occurs.
7. Manage String Weight and Tension
The applied WOB should be enough to promote bending into the wash pocket, but not so high that the pipe risks buckling off-bottom. Maintain axial tension close to, but below, the neutral point to ensure stable drilling and pipe integrity.
8. Offshore Monitoring and Controls
In offshore settings with platforms or risers, use ROVs to monitor the casing and riser for leaks or signs of movement during jetting. Mark depth measurements on the casing and drillpipe so operators can track the bit position. This helps confirm that the string is not swinging excessively or packing off.
9. Pumping and Fluid Handling
Use water or thin mud for jetting to minimize resistance and improve nozzle performance. Start pumping at a low rate to clear any debris in the nozzles, then gradually increase to operational levels. Prepare high-viscosity sweeps to break gel and help transport cuttings. During conductor jetting at the seabed, increase the pump rates in stages, starting at around 300 gpm and increasing through 500, 800, up to 1000 gpm while monitoring for signs of side-flow or losses.
10. BHA Configuration for Controlled Jetting
The bottomhole assembly (BHA) should include a full-gauge near-bit stabilizer to act as a fulcrum, with one or two additional stabilizers above the motor or bent sub to enhance stiffness. Install a gyro (e.g., UBHO or GWD) above the near-bit stabilizer for continuous trajectory monitoring. Use heavy drill collars and HWDP close to the bit.
11. Bit Selection and Nozzling
Select a bit suitable for jetting, such as one with a dominant extended nozzle. Typical setups include tricone bits with one large jet (e.g., 26/32") and two smaller ones (e.g., 8/32"), or bits with one nozzle blanked and the remaining two active. The large, open nozzle should be aligned to the high side when sliding, to maximize side cutting action.
12. Jetting and Spudding Technique
Align toolface to the desired direction, place the bit on the bottom, and begin jetting at full flow. Lift the bit 5–10 feet and let it fall under controlled brake to enhance jet action and initiate a clean pocket.
13. Jet-Drill Transition and Build Control
After jetting 1–3 meters, reduce the flow rate and begin rotating the string at low RPM with high WOB to drill forward into the jetted pocket. Use alternating cycles of sliding (for building) and rotating (for cleaning and drilling ahead), and survey after each cycle to verify the trajectory. Continue this cycle until the desired build or clearance from the offset well is achieved.
14. Post-Jetting Operations and Trajectory Smoothing
Once the target dogleg is achieved or the hazard is cleared, evaluate whether to continue with the current jetting BHA or switch to a motor or RSS for regular drilling. If a sharp bend remains in the well path, consider reaming the section to reduce torque, drag, and casing wear before running pipe.
15. Contingency and Failure Management
Maintain a contingency plan throughout the operation. If the jetting fails to penetrate or results in an undesirable path, operations should pause for evaluation. Alternatives include reorienting the toolface, pumping cement to plug the section, or sidetracking. Unexpected pressure changes or fluid loss should be investigated immediately as potential signs of offset well communication.
Special Considerations for Offshore Platforms vs Single Wells Your Comments
Platform / Multi-Well Pads: On jacket platforms or pads with many slots, an anti-collision policy is paramount. Everyone on the drilling team (supervisor, driller, surveyor) must be aware of collision criteria. Use the tightest survey program allowable (gyro in mud, PMR for ranging) and consider shutting in adjacent wells during jetting. It is wise to proceed gradually: jet maybe a couple of meters at a time, then rotate, then survey. If any unusual increase in surface tension is noted, listen for any collision indications. ROVs or downhole sensors should watch for flow behind the conductor.
Single Wells (Shallow Onshore or Deepwater): If no nearby wells, jetting is usually not necessary for anti-collision. A single well in shallow water or onshore with plenty of clearance can often use a mud motor to kick off. In deepwater, conductors are often jetted anyway to avoid driving piles, but the directional “nudging” step is typically done by a motor or RSS a bit deeper. However, if the seabed sediments are extremely soft (e.g. fine sand/mud), a pilot jet can create a clean hole to begin drilling; otherwise, normal drilling is acceptable. Still, the same jetting precautions (short slides, survey) apply if jetting is used at all.
Recent Technologies: Modern steerable systems have largely taken over jetting’s role. Rotary Steerables (RSS), especially hybrid RSS tools, can build several degrees per 10 m without stopping rotation. Recent field cases have combined RSS with directional jetting, achieving ~3°/30 m builds in soft shallow sections. These hybrid systems give the high-angle capability of jetting while still rotating. Also, automated motors can hold more precise tool faces than human-drilled slides, reducing dogleg severity. If formation allows, these technologies are preferred over pure jetting for predictable steering. Jetting today is truly a “specialty” method for when nothing else will work to keep us safe from a collision.