PDC Bit Run Guidelines and Troubleshooting 

Solids Control Equipment

Poor solids control equipment can cause the following problems-

  • Ineffective or too few shakers can limit the speed at which cuttings can be removed from the mud system. If this is the case penetration rate may need to be limited.
  • If the solids are not removed from the mud effectively the mud can become very erosive. Erosive mud can reduce bit and downhole tool life resulting in shorter run lengths.
  • If the solids content becomes too high this can reduce the effectiveness of the mud, eg shale inhibition with water based mud systems.

Evaluate the following equipment-

• Shale shaker specification

  • Number
  • Type 
  • Screen/mesh size
  • Centrifuge equipment


Mud Pumps

Mud pumps drive the mud around the drilling system. Depending on liner size availability they can be set up to provide high pressure and low flow rate, or low pressure and high flow rate. Analysis of the application and running the Drill Bits hydraulics program will indicate which liners to recommend. Finding the specification of the mud pumps allows flow rate to be calculated from pump stroke rate, SPM. Information required-

  • Pump manufacturer
  • Number of pumps
  • Liner size and gallons per revolution


Mud Condition

Drilling mud has two fundamental functions. The primary function is to keep the well bore in good condition by managing the formations, eg: balancing pore pressure, inhibiting shale reaction, etc. The secondary function is

to aid the drilling process, eg: transporting cuttings to surface, cleaning and cooling the drilling bit, etc. For maximum drilling performance the mud system must be maintained in good condition.

Minimum information required- 
  • Type (OBM, WBM, POBM, Silicate, etc)
  • Weight
  • Solids content
  • PV/YP

Lost Circulation Material

Lost circulation material is frequently required to plug fractures in the well bore. If these fractures are not plugged a significant volume of mud can be lost to the formation. Mud is expensive and losses must be minimized. Lost circulation material comes in various sizes and types, eg: nut plug, cottonseed hulls, cellophane, etc. LCM as well as plugging holes in the well bore can plug nozzles in a drill bit. If determined that lost circulation material will be required, ensure that the size and type is known so that drill bit nozzles can be selected that will allow LCM to pass through with a minimal risk of plugging.

Drill Bit TFA (Total Flow Area) Calculation

System hydraulics can greatly affect drilling performance, eg: HSI and cuttings removal for high RoP, cutter cooling for drill bit life, etc. It is important that both the nozzle and pump liner size are selected to optimize the hydraulics for that application. The limiting factor may be available rig power. The drilling rig motor that drives the mud pumps, combined with the pump liners sets the maximum stand pipe pressure and flow rate available.
  • Flow is the critical medium that cleans, cools and lubricates the cutting structure and bit, (critical for unsealed roller cone bits). In some applications, drilling with minimal flow rate will cause rapid degradation of the drill bit cutting structure.
  • HSI is a primary factor for maximizing RoP. HSI is the energy at the bit that transports the cuttings from the bit face into the annulus.
  • Flow rate is another important factor. High flow rate helps lift the cuttings to surface.
  • Turbulent flow is generally achieved around the drill bit.
  • Laminar flow is generally preferred around the drill string to prevent hole damage.
  • If there is the possibility of pumping lost circulation material, small jet sizes should not be run as the risk of plugging them is high. As a general rule, nozzle sizes under 12/32nds should not be run.
  • Calculation of expected pressure change if one of the nozzles becomes plugged or is lost.

Drilling Out the Wiper Plugs, Cement, Shoe and Float Assemblies
Natural diamond impregnated and surface set diamond drill bits will take 25-50% longer than PDC drill bits to drill out casing shoe assemblies.

  • Ensure there is no metal or junk in the hole.
  • Do not use Automatic Driller.
  • Wash and ream to bottom with maximum flow rate at least 30’ above where the cement is expected.
  • Use 50-60rpm with a rotary assembly and 20-40rpm with a motor assembly.
  • Tag bottom slowly with 4,000lbs maximum weight on bit and look out for green/wet cement.
  •  If the bit does not drill off, reciprocate the drill pipe. Do not stay on bottom if bit is not drilling.
  •  Use as little weight as possible, do not exceed maximum recommended weight on bit.
  • If the wiper plugs begin to rotate, it may be necessary to tag bottom without rotation and increase weight on bit slowly. Do not spud the bit into the float equipment. Once sufficient weight on bit (start with 6-8klbs and increase as necessary) is applied, slowly increase rotary to 60-80rpm. Repeat as necessary to drill through the remainder of the plugs.
  • Monitor penetration rates and adjust weight on bit as necessary.
  • In difficult drill out applications allow the weight to reduce/drill off naturally and evaluate penetration rate. Repeat this process until a more consistent drilling pattern is established.
  •  Raise the bit 2 feet off bottom and circulate once the plugs are drilled and midway through drilling the float collar assembly, (repeat as often as dictated by hole conditions/bit performance).
  •  Reducing or stopping the flow rate may cause the bit junk slots to pack-off. Use extreme caution when reducing flow rates during drill out
  • On semi-submersible and drill ships where the rig may heave, use the compensator to prevent spudding the bit. Rig heave can complicate a successful drill out and can cause bit balling.

 Bedding / Breaking the Bit In
  • Approach bottom with maximum flow rate. 
  • Slowly set the bit on the hole bottom with no more than 4,000 lbs weight and 40-60 RPM to establish the bottom home pattern. 
  • Extra care should be taken following a coring run due to the possible “stump” left on the bottom of the hole. 
  • If the bit does not drill ahead increase weight until it does. 
  • Maintain as low weight as possible until the bit has drilled at least its own length. Until the bit has cut its own bottom hole pattern only some of the cutters will be in contact with formation so if weight is added too quickly, particularly, in hard formations, these cutters may be overloaded and fail. 
  • Increase weight on bit to target weight, (do not exceed recommended maximum for the bit.) As a general rule, the optimum weight for a PDC is less than half of that used for a roller cone bit. 
  • Increase rotary speed up to target RPM.

Making Connections and Restarting Drilling 

  • Maintain full flow as bit is raised off bottom.
  • Return to bottom with 50% of the target drilling rotary speed and full flow rate to wash and clean the hole.
  • Return to bottom gently. Dropping the string too rapidly can cause the bit to tag bottom violently and damage the cutting structure.
  • Increase weight on bit to target weight on bit taking care to avoid stick-slip or other detrimental vibrations.
  • Increase RPM to target RPM.

General Drilling Parameters for ‘Clean’ Formation 

Clean formation refers to a homogenous formation that is not interbedded and is 100% one lithology type. These types of formations are rare as some shales for example include a certain sand and limestone content. However, selecting parameters that suit the primary lithology will generally optimize drilling performance.


Soft clean shales
  • Increasing rotary speed generally improves penetration rate, (usually RPM has a greater effect on RoP than WoB).
  • There is minimal risk of damaging the cutting structure in this lithology.
Hard clean chalk/limestones
  • Penetration rate is maximized by increasing cutter point loading to fracture the formation. High
  • weight is recommended with low rotary speed to allow the cutters to bite into the formation.
  • Bits may suffer impact damage. If the formation is clean (ie: no sand content) the cutters should suffer minimal abrasive wear.
Hard sandstones
  • Penetration rate is maximized by increasing cutter point loading so high weight is recommended.
  • To ensure the cutters can get a bite, low rotary speeds are preferred.
  • Bits may suffer both impact damage and abrasive wear. Low RPMs will reduce abrasive wear.
  • Low rotary speeds will also reduce penetration rate so a reasonable compromise must be reached. 

Fundamental Parameter Discussion

Torque

• Rotary torque is an indicator of what is happening at the drill bit. For example-
  • PDC high torque -the bit is likely to be digging or if there is low RoP the torque could be being generated from the BHA and not the bit.
  • PDC low torque -the bit could be skidding in a hard formation, the cutting structure could be dull or the bit could be balled 
  •  In soft formations torque may indicate the bit is on bottom before the weight on bit gauge does. In such formations the torque gauge may be the best surface measurement by which to drill.
  • The torque could be considered to be too high when it starts to slow down surface rotary speed.
  • The torque is too high when it stalls the motor, rotary table or the top-drive.
  • Homogenous formations should produce a smooth constant torque signal.
  • Interbedded formations will produce torque changes as the bit and/or the BHA moves in and out of formation beds that have different rock strength and 'drillability'.
  • If downhole torque measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore.


Weight

• As a drill bit cutting structure wears more weight will be required to achieve the same RoP in a homogenous formation.

• PDC wear flats, worn inserts and worn milled tooth teeth will make the bit drill less efficiently.

• Increase weight in increments of 2,000lbs approx.• In general, weight should be applied before excessive rotary speed so that the cutting structure maintains a significant depth of cut to stabilize the bit and prevent whirl.

  • If downhole weight measurements are available they can be used in combination with surface measurements to gain a more accurate representation of what is happening in the well bore.



Rotary Speed

• Total bit rotary speed is equal to the surface rotary speed plus the down hole motor/turbine rotary speed.

• Rotary speed is not limited when running PDC drill bits.

• High rotary speed should be avoided in abrasive formations to prevent rapid abrasive wear.

• High rotary speed should be avoided if the drill bit starts to whirl.

• Rotary speed may be limited due to drill pipe or drive limitations.

• Some rotary speeds can initiate drill string resonance (high levels of vibration) and should be avoided.

Either increase or decrease RPM to avoid operating in drill string harmonic frequencies.

• High rotary speeds in hard formations may reduce RoP as the cutters are unable to ‘dig in’.

  • The rotary speed that maximizes RoP without causing other drilling problems is likely to be the ‘right’ one.



Flow Rate

  • Flow rate greatly effects hole cleaning. Generally high flow rates provide better hole cleaning than low flow rates as they are better able to return cuttings to surface due to increased annular velocity.
  • Flow rate greatly effects bit cleaning. Generally high flow rates provide better bit cleaning than low flow rates by increasing hydraulic energy at the bit.
  • High flow rates can cause formation damage especially in highly fractured formations so excessive flow rates must be avoided.



Factors Related to a Bit Run Termination




Worn Cutting Structure

  • Cutting structures wear out, (PDC/insert/milled/impreg/diamond).
  • A worn cutting structure requires more weight to achieve the same penetration rate as a new/green cutting structure, ie: RoP generally decreases.
  • If the gauge area of the cutting structure wears first the bit can become a ‘wedge shaped plug’ that fits tightly in the hole. This can cause high on-bottom torque even with low weight on bit, very low penetration rate and often accompanied by an increase in SPP. Under gauge bits can also cause the stabilizers to hang up and cause general BHA damage.
  • As an impregnated or surface set diamond bit wears the standpipe pressure will increase due to a reduction of the flow area. This is due to a reduction in blade height due to wear.
  • As a PDC bit wears, for a given weight on bit, torque generally reduces as the cutting structure is no longer as aggressive.
  • Severe PDC wear can result in the blades being worn down to the bit body/nozzles. Consequently, a significant increase in SPP will be seen as the flow is restricted due to contact of the bit face and the formation.



Bit Balling

  • Usually occurs when drilling soft sticky formations with WBM.
  • Some formations, predominantly shales react with water swelling considerably and becoming sticky.
  • Montmorillonite content is the most significant factor with respect to formation hydration and bit balling.
  • Montmorillonite changes to illite with time and temperature.
  • Kaolinite does not hydrate and react with water.
  • The order of claystones with greatest to least balling tendency iso
  • Montmorillonite
  • Mixed layer, montmorillonite and illite
  • Illite
  • Kaolinite
  • Swollen and sticky cuttings can adhere to the bit clogging up waterways, junk slots, individual cones and possibly the entire bit.
  • Severe balling results in total clogging up of the cutting structure so that the string weight is transmitted to the formation via the balling material rather than the cutting structure. Consequently, penetration rate is dramatically reduced.
    • Balled formation can also plug the annulus so that no cuttings can be returned to surface. This results in an increase in SPP and possible risk of losing mud into the formation.
    • Balled bits are generally characterized by- 
    • Reduced rotary torque
    • Reduced penetration rate
    • Increased SPP
• If it is thought a bit is balling up lift off bottom immediately. Drilling with a balled bit can only exacerbate the problem by forcing more material to plug the bit or annulus further. This tightens/compresses the material and makes it heavier and more difficult to transport back to surface.

• Methods for un-balling a bit are-

  • Increase flow rate to the maximum for at least 5mins.
  • Spin the bit as fast as possible to ‘fling’ the material off.
  • Lift and drop the string rapidly to ‘shake’ the formation off, (take care not to surge the hole and damage the formation or drop the bit on bottom and damage the cutting structure).
  • Pump a pill, (eg: Nut Plug) to try and wash the material off.
  • A combination of the above.
  • When returning to bottom after un-balling a bit use maximum flow rate and high rotary speed. Tag bottom gently as there may be huge chunks of balled material that need to be cut up. If weight is added too quickly the bit may just push into the balled material and become immediately balled again.
  • Where balling is expected the risk of occurrence can be reduced by limiting penetration rate. This means that a reduced and more manageable amount of cuttings can be transported away from the bit face and annulus to surface.



Plugged (Blocked) Nozzle

  • Nozzles can be plugged by a variety of materials. Some examples are-
  • Formation
  • Lost circulation material
  • Motor stator rubber
• A plugged nozzle will result in increased SPP.

• If penetration rate is not significantly reduced drilling can continue.

• If multiple nozzles are plugged and there is a severe deterioration in RoP it should be attempted to un-plug the nozzles or pull the bit out of hole.

• Methods for un-plugging a bit are-

  • Increase flow rate to the maximum for at least 5mins.
  • Lift and drop the string to ‘shake and surge’ the plugging material free, (take care not to surge the hole and damage the formation or drop the bit on bottom and damage the cutting structure).
  • A bit with plugged nozzles has an increased probability of balling in softer formations and accelerating cutter wear in abrasive formations.