What are the best practices for preventing premature wear of PDC bits in directional drilling?

In highly interbedded formations, hard limestone stringer used to slow down PDC bits and without changing the parameters eventually destroy them quickly. However in the same hard limestone but homogenous, PDC bits are able to survive longer. These days PDC bits are stronger in both interbedded and hard homogenous formations due to the shaped geometry PDC cutters available in the market, however formation evaluation is still important to select which PDC cutter characteristics that will be installed to the bit, more impact, wear or heat resistant.

Analyze the geotech investigation report of the area,so you will be aware of the strata of the drilling area.it will help you to evaluate what kind of drilling bit requires. As we know we are having different strata bits,like soft strata bit,hard starta bit, medium hard strata bit. After analysis of the geotech report we will know what kind of strata we are going to face,same strength, Hardness drill bit is needed. Secondly we have to use the best quality Bentonite+Additives+soda ash+Fresh water, drilling mud that will help to reduce the wearing of tools. If our Drilling fluids quality is good it will help to cool the bits, also remove the all cuttings from the hole so full thrust will reach on the drill bit to cut the formation.

Explore modelos de desgaste para antecipar e mitigar os custos associados ao desgaste da broca PDC (polycrystalline diamond compact). Fozer o monitoramento regular da broca, evitar desvios excessivos durante a perfura??o e aprofunde a compreens?o do comportamento da broca PDC por meio de análises experimentais.

I'd focus on optimizing drilling parameters like WOB, RPM, and flow rate to prevent PDC bit wear. Balancing these parameters is key. While increasing WOB can improve ROP, it also risks cutter fracture and thermal damage. Higher RPM enhances cutting but may cause more vibrations and wear. A balanced combination of WOB and RPM is essential for maximizing ROP without compromising bit durability. Additionally, maintaining a sufficient flow rate is vital for cooling, cleaning the bit, and preventing bit balling and clogging.

Step tests are a convenient operational workflow that can be used to optimize parameters and decrease bit wear in real time as well as plan the next run via post mortem. To perform a step test in a given formation the driller should hold bit RPM constant and increase WOB. The effect of this step should be evaluated in real time based on the MSE response. If MSE increases the system has become less efficient and WOB should be stepped the other way (decrease). If MSE stays the same or decreases the systems efficiency has either remained static or increased and the driller should continue increasing WOB in steps. The same can be performed holding WOB constant and stepping bit RPM either by increasing surface RPMs or flow rate.

It is important to ensure that the cutting structure is constantly engaged with the rock and fails it effectively with the WOB available (key bit design objective). Inability of the cutting structure to engage with rock consistently translates to vibration and heat (energy must go somewhere). If the bit dulls prematurely in hard rock, increasing cutter count can and will exacerbate the issue. Durability through efficiency is an alien concept but must be embraced. Implementation of this concept is only possible with competent cutting structure model (physics-based modelling) and contemporary cutter grades. Smaller cutters are not necessary more durable, and larger cutters are not necessarily more aggressive (I have reached the words limit :)

I would emphasize that PDC bit design is crucial for reducing wear and improving directional drilling. Important design features include cutter shape, size, density, orientation, quality, bit profile, gauge, and junk slots. Tailoring the bit design to specific formation and drilling conditions, as well as the desired directional response, is key. Utilizing smaller or more cutters can lessen contact stress and wear, while larger or fewer cutters enhance aggressiveness and steerability. Different cutter orientations, like back-raked for stability or side-raked for steerability, significantly impact cutting forces and bit direction.

Very often, even with 'best practices' on a well, conditions will be present that can destroy a bit in unexpected ways. It has been observed that if those unexpected events could be properly be measured, steps could be taken to mitigate damage at a very early stage. However, the quality of today's PDC bits is such that they will continue to drill even as they are being destroyed. One such indicator can be obtained from a good mud logging company...use a Mass Spec to see indications of Hydrogen and Ethane that indicate high spot temp that can destroy a bit. IM me for more info.

Depth of cut control features have become an important part of PDC bit design over the last decade or so. They can be used to alter the torque response of the bit for a given set of WOB and bit RPM parameters as well as widen the range of safe operating parameters to avoid drilling dysfunction. Since dysfunction is often the leading cause of premature bit wear this can be used to extend the life of the bit when designed and applied appropriately.

As a directional driller, steerability is a key factor to consider when choosing what bit to use. The cutter size and orientation plays a huge role in achieving this. Ofcourse other factors like the bit guage and cutter number also have significant impact on the durability of the PDC bit during a drilling operation.

Aggressive build rates (particularly in the land market) in the well design lead to bigger motor bends, which in turn results in "Point Loading" on the bit. The bigger the bend, the more point loading your going to have on the bit, resulting in the shoulder rows being dulled quicker, and directional DLS performance is quickly lost. Taking a step back (this will go against what geology and production want) and designing the wells with less aggressive build rates will lessen the need for larger motor bends, and help reduce bit wear.

Stack max weight off the hop to condition it for that. If you add all that weight further down the line it don’t be ready for it ??

The inclusiveness of a competent, comprehensive and proven drilling fluids application provider for your particular scenario IS KEY TO MEDIATING >85% of the considerations discussed as influences of bit wear and destruction. From immediately sealing the wellbore while maintaining cuttings integrity through evacuation and lubricity coefficients that allow control of rheological characteristics to technically proven and modeled torque and drag factors to set guidelines of drilling parameters and maintain a temperature profile through proper flow rate and ECD modeling while minimizing the accumulation of colloidal solids build up. All of which, as mentioned, can be provided in a comprehensive drilling fluids application design.

Some peoples are giving the reasons for premature failure is heat chunking, we can add as well. One of the well, we seen obviously premature failure and Bit experts reasoned it heat chunking, Bit was completely worn out