Vibration Table [PDF]

Zitiervorschau

Vibration Table MECHANISMS

PRIMARY MODE

SECOND ARY MODE

Stick-Slip DDS-2, DDSr Drill Saver III TEM

Torsional

Axial

Torsional Resonance Torsional

Lateral

DDS, DDS-2, DDSr,

Bit Chatter DDS, DDS-2, DDSr,

Lateral

Torsional

Bit Whirl (BHA Whirl) Lateral DDS, DDS-2, DDSr, SVSS, IVSS

Torsional

DESCRIPTION Non-uniform bit rotation in which the bit stops rotating momentarily at regular intervals, which causes the string to torque up periodically and then spin free. This mechanism sets up the primary torsional vibrations in the string.

TYPICAL ENVIROMENT High angle and deep wells, hard formations or salt, use of aggressive PDC bits with high WOB.

CONSECUENCES Surface torque fluctuation > 15% of average. Stick-slip can cause PDC bit damage, lower ROP, connection overtorque, back-off, and drillstring twist-offs. Interference with mud pulse telemetry, wear on stabilizer and bit gauge.

It is most damaging at higher rotational speeds where higher amplitude resonance at harmonics of the collars natural frequency can occur. Impact damage can occur to downhole equipment.

RESPONSES TOOL DDS Responses: Avg X – Avg Y > 1 g. Low to medium Peak X and Peak Y. DDSr Response: SSI > 100%. DDS2-M5: Increased delta RPM along with other surface indicators. DDS Response:

This is specifically drill collar torsional resonance as a natural torsional frequency of the drill collars that is being excited. It is thought to be caused by impacts of individual cutters or by localized excessive side forces in the BHA generating a juddering motion. The change in RPM is very small and the frequency of the vibration is high.

This specific type of vibration occurs predominantly in very hard rocks when drilled with a PDC bit.

This is the high-frequency resonance of the bit and BHA. The excitation is caused by slightly eccentric bit rotation where there is cutter interference with the bottom hole cutting pattern. The cutters ride up on to the ridge between previously cut grooves and then drop back into the grove.

PDC bits drilling in high compressive strength rocks will create this vibration where each cutter is impacted on the formation.

Bit cutter impact damage. High-frequency vibration can cause failure of electronic equipment due to vibration of electronic components and solder joints. This bit dysfunction can lead to bit whirl.

DDS Response:

Eccentric rotation of the bit about a point other than its geometric center caused by bit/wellbore gearing (analogous to a planetary gear). The mechanism induces high-frequency lateral vibration of the bit and drillstring.

Aggressive sidecutting bit (normally PDC bit) in softer (suaves o lavadas) rock, vertical wells.

Bit cutter impact damage, overgauge hole, BHA connection failures, and MWD component failures.

DDS Responses: DDS should be placed as close to the bit as possible.

Avg Y – Avg X > 1 g. Low Average X, High Average Y, Low Peak X, High Peak Y (occasional).

High Peak Y Medium to High Avg X and Avg Y Peak X and Peak Y.

High Peak X and Peak Y

ACTIONS RECOMMENDED

OTHER SOLUTIONS (POST RUN)

Increase RPM and/or Decrease WOB.

Consider using less aggressive PDC bit or a torque feedback system (i.e., a “soft torque”). Reduce stabilizer rotational drag (change blade design or number of blades, non-rotating stabilizer or roller reamer). Smooth well profile.

If the stick-slip persists, stop the rotary and restart drilling under a higher RPM and/or lower WOB.

Adjust RPM to move away from the excitation frequency, typically 10%. If vibration persists, stop rotating and restart drilling with a different RPM.

 

20 350 HZ

Adjust RPM up or down to a region away from the RPM being used. Adjust the WOB if necessary to remove the condition. If vibration persists, stop rotating and restart drilling with modified parameters. It may be necessary to break the bit in to reestablish a cutting pattern. Reduce RPM. If vibration persists, stop the rotary and restart drilling under a lower RPM.

Modified bit design or bit selection.

20 250 HZ

Consider changing the bit (flatter profile, anti-whirl PDC bit or a roller cone bit), using stabilized BHA with full gauge near-bit stabilizer.

10 - 50 HZ

Medium to high Avg X ≈ Avg Y

Mirror X-Y

Number of Blades*RPM Mirror X-Y Frequency analysis of the burst data can show a dominant peak (between 5 and 100 Hz) of large magnitude (>1 g2/Hz).

FREQ (Sourc M ADT DDS) 0.1 - 5 HZ

More Blades of PDC >> Higher Freq.

BHA Whirl (Bit Whirl) Lateral

Torsional

DDS, DDS-2, DDSr, SVSS, IVSS

Lateral

 

DDS, DDS-2, DDSr, SVSS, IVSS

Parametric Resonance Axial Lateral

 

Bit Bounce DDS, DDS-2, DDSr, SVSS

Modal Coupling DDS, DDS-2, DDSr Drill Saver III

Vertical or nearvertical wells, pendulum, or unstabilized BHA. Induced by mass imbalance of the BHA or through lateral vibration induced by the BHA resonating at a critical rotary speed.

MWD component failures (motor, MWD tool, etc.), localized tool joint and/or stabilizer wear, washouts or twistoffs due to connection fatigue cracks, increased average torque.

The BHA moves sideways or sometimes whirls forward and backwards randomly (chaos). Unlike backward whirl, this chaotic motion often results in medium/high peak lateral accelerations but low average accelerations of the DDS data. Lateral shocks have also been linked to many MWD and downhole tool connection failures. Lateral shocks of the BHA can be induced from either bit whirl or from rotating an unbalanced drillstring. Severe lateral vibration induced as a result of axial excitations caused by bit/formation interaction. The dynamic component of axial load is primarily caused by bit/formation interaction, which results in fluctuations of weight on bit. Axial fluctuations at a specific frequency will cause lateral deflection of the drillstring through the small lateral displacements that are already occurring (i.e., the small bends that already exist will be magnified due to the wave traveling through them). Axial or longitudinal motion of the drillstring resulting in large WOB fluctuations causing the bit to repeatedly lift-off and impact the formation.

Hard rock and unbalanced or long unstabilized drillstring. Lateral shocks can be induced from bit whirl or lateral movements caused when the drillstring moves sideways during bit bounce.

MWD component failures (motor, MWD tool, etc.) localized tool joint and/or stabilizer wear, washouts or twistoffs due to connection fatigue cracks, increased average torque.

Interbedded formations, undergauge hole.

Severe lateral vibration can induce accelerated failure in the drillstring. It can also create the opportunity for borehole enlargement, which may lead to poor directional control and also lead on to whirl and other mechanisms of vibration.

DDS Response:

DDS Responses:

A coupling motion among axial, torsional, and lateral vibrations. The coupling motion creates axial and torque oscillations and high lateral shocks of the BHA. The motion is similar to a chaos so the DDS’s average data will not be very high.

Vertical or near vertical wells, pendulum or unstabilized BHA, and hard rock.

The impact loading will damage the drill bit cutting structure, bearings, and seals. The drillstring can sustain damage from the axial shocks and lateral shocks induced by the string flexing. Hoisting equipment may be damaged in shallow wells. MWD component failures, bit cutter impact damage, collar and stabilizer wear, washouts and twist-offs due to connection fatigue cracks.

Mirror X-Y

Lateral Shocks

DDS, DDS-2, DDSr,

Similar to bit whirl, the BHA gears around the borehole and results in severe lateral shocks between the BHA and the wellbore. BHA whirl has been proven as the major cause of many drillstring and MWD component failures. BHA whirl can also occur while rotating/ reaming off-bottom. Whirl can occur in a forward or backward motion.

Axial

Torsional Lateral Axial

Vertical wells, roller cone bits in hard rock, undergauge hole, ledges, and stringers.

Torsional

 

DDS Responses: Similar to that of Bit Whirl High Peak X and Peak Y

Reduce RPM. If vibration persists, stop rotating and restart drilling with a lower RPM.

Use largest practical drill collar size and/or packed hole assembly with full gauge stabilizers, Reduce stabilizer drag (blade design, nonrotating). In very hard and abrasive formations, consider using a downhole mud motor.

0 - 20 HZ

Reduce RPM to reduce the drillstring energy. If vibration persists, stop rotating and restart drilling with a lower RPM.

Use largest practical drill collar size and/or a packed hole assembly with full gauge stabilizers. Reduce eccentricity of the drillstring. In very hard formations, avoid using an aggressive PDC bit.

Irregular impacts

Increase WOB

Modify bit design or use shock sub to dampen axial motion.

0.1 - 10 HZ

Consider using a less aggressive roller cone bit and/or a shock sub.

1 - 10 HZ

Consider changing bit style and/or modifying BHA (packed hole assembly). Reduce stabilizer drag (blade design, non-rotating). Use a torque feedback system. Consider using the downhole mud motor.

0.1 - 20 HZ

Medium to high Avg X ≈ Avg Y Mirror X-Y Frequency analysis of the burst data can show a dominant peak (between 5 and 100 Hz) of large magnitude (>1 g2/Hz). DDS Responses: Medium to High Peak X ≈ Peak Y But Low Avg X and Avg Y There will be no dominant peaks in the frequency plots of the burst data.

High Peak X and Peak Y High Avg X and Avg Y May have Low peak Z accelerations.

High peak Z acceleration.

and Decrease RPM by 10%. If vibration persists, stop rotating and restart drilling with modified parameters, RPM first.

Increase WOB and/or Decrease RPM. If vibration persists, stop the rotation, and then restart drilling under a lower WOB and/or lower RPM.

DDS Responses: High Peak X, Y, Z Low to medium Avg X and Avg Y May be: Avg X > Avg Y.

Stop rotating and pick up off bottom. Resume drilling with modified WOB and RPM. Attempt a lower RPM first.