Drilling procedures, drilling fluids program, cementing program, drilling hazards—These are some of the most common considerations for a drilling engineer when designing a drilling program. As boreholes have gotten deeper and lithologies harder and more complex, however, controlling the costs of these operations has become increasingly challenging. The often-sidelined drilling optimization process plays a vital role in helping companies minimize the cost of complex operations and mitigating certain risks that cannot be overlooked.
At its core, drilling optimization is about drilling in the most efficient way possible; to meet all drilling objectives while minimizing overall drilling costs. With rig rates running upwards of a million dollars a day for some operations, shaving even a few minutes off the drilling time can result in tens of thousands of dollars in savings. One of the fundamental ways a drilling engineer can achieve this is through selection of a proper drill bit.
As the primary piece of equipment performing the mechanical work of rock drilling, the type of drill bit used plays an essential role in the drilling operation’s overall efficiency. Thousands of drill bit designs exist in the industry, each designed to best drill under a certain scenario. Attention to detail is crucial, as a small design tweak can cause an unintended and undesirable impact on the overall costs and objectives of the well. It is therefore critical that the drilling engineer understands the interrelatedness of drill bit design and common drilling objectives. In this article, we will discuss some of the main objectives of proper drill bit selection and relevant drill bit designs. We mainly discuss polycrystalline diamond compact (PDC) fixed-cutter drill bits due to their prevalence in modern drilling programs.
Rate of Penetration
The rate of penetration (ROP) is a key performance indicator for the overall efficiency of the drilling operation. When compared to similar “offset” runs drilling through comparable formations and application, a higher ROP signifies that the formation is being drilled at a faster rate, saving on rig time and thus indicating a more efficient operation. However, one must be careful to distinguish between a high “instantaneous” and high “overall” ROP. Blazingly fast instantaneous ROP on the dial may not be the optimal way to drill simply because such high instantaneous ROP may not be sustainable.
The trade-off in pushing the drill bit to its limit by drilling as fast as possible through increasing the weight on bit (WOB) and rotations per minute (RPM) manifests itself in the degradation of penetration rates due to worn cutters. This is especially true for more challenging applications such as abrasive sands and volcanic formations, which tend to wear out the cutters on the bit very quickly. The relationship between cutter condition and instantaneous ROP is not linear, with instantaneous ROP dropping exponentially with dulling cutters due to vastly reduced point loading and distribution of WOB. Even worse, if instantaneous ROP drops to a very low rate, even grinding to a halt, a costly trip may become necessary. Nothing is more frustrating than being meters away from the intended end of the section and needing to trip out and change out the bit just to drill the tiny section that remains. It is thus in the drilling engineer’s best interest to preserve the cutting structure of the drill bit as best as possible in the vast majority of cases.
Drill bit design elements to consider when drilling through abrasive formations include increasing the number of blades on the PDC drill bit, resulting in increased protective diamond volume from a higher number of cutters. Looking at mainly applications off the North West Shelf region of Western Australia and Browse basin north of Australia as a guideline, six to seven blades is a good base to start with for moderately abrasive sandstone formations. Highly abrasive formations, usually coupled with high confined-compressive-strength (CCS) rock strengths such as sandstones, granites, and other igneous formations require upwards of eight blades to ensure sufficient protection for an acceptable overall ROP. Pay attention to the number of blades running to center, as not all blades will do due to space constraints on the bit design. Four blades running to centre is recommended in highly abrasive formations to ensure that the cone of the drill bit does not give in, often referred to as a core out.
The drilling engineer should be careful not to select a drill bit that is too heavy. For one, a more durable drill bit costs substantially more than a lighter one, Secondly, a heavier, less-aggressive design generally entails a greater distribution of force across all its blades, resulting in lower point loading for a given amount of WOB.
Minimizing BHA Damage through Downhole Vibrations
One of the most catastrophic events that can happen to a drilling operation occurs when the drillstring twists off under extreme dynamic conditions, resulting in a potential loss of downhole equipment and the need to carry out costly fishing or sidetracking operations. This can happen due to energy that goes into the system being reflected back into the drillstring in the form of destructive downhole vibrations. Instead of the efficient transmission of WOB and RPM from the drive system into the work of drilling rock through the drill bit, this energy manifests itself in many types of vibrations one of which is the stick/slip vibration.
Stick/slip vibrations occur when excessive torque is experienced. This is characterized by repeating cycles of slowdown in bottomhole assembly (BHA) RPM as the drillstring winds up to accommodate the torsional force being applied onto a defiantly resistant hard rock, followed by sudden increases of RPM from the release of this energy when the buildup in the drillstring exceeds a certain amount. This drilling dynamic is far from ideal. Not only does stick/slip cause a great deal of fatigue on the repeated twisting and release of the drillstring, it can also result in damage to downhole tools and the cutting structure of the drill bit from high impact velocities.
The cause of stick/slip vibrations in PDC fixed cutters is mostly due to the over-engagement of cutters into the formation, causing excessive torque. If the amount of reactive torque seen on the drill bit can be better controlled, stick/slip vibrations can be reduced or eliminated. A drilling engineer looking at the potential impact of drill bit design in this area might explore selecting a drill bit with higher blade count for a greater distribution of force across the drill bit. This would result in lower cutter engagement for a given WOB applied.
The use of a design with backup rows of cutters can be an interesting solution depending on the application because the backup rows of cutters are typically underexposed to the main cutters. When using a six-blade PDC with six rows of backup cutters, for instance, the drill bit behaves like a six-bladed bit until the depth of cut reaches where the backup rows of cutters engage, thus causing the bit to behave like a much less aggressive 12-bladed bit. This is especially useful in formations with softer rock interbedded with medium CCS rock, or when drilling through a hole section that starts with non-abrasive rock, allowing for drilling at higher RPM, and finishing off with harder and more abrasive formations, requiring the backup row of cutters to engage.
The use of depth-of-cut control elements works in much the same way as the backup cutters except that it puts a physical limit to the depth that the cutters on the drill bit can engage. This is useful for hard but shorter hole sections where a trip is to be expected before the cutters wear down to the depth-of-cut limit imposed by the control elements.
Directional Performance
Whether the wellbore is designed to be vertical or directional, maintaining the intended trajectory of the well is a key requirement for all drilling programs. While it is true that the primary consideration in directional performance stems from the drive system that the drilling engineer chooses, the drill bit chosen to work with in tandem plays an important role, too.
The simplest of well profiles is the vertical well. With a simple BHA, PDC drill bit design should consider gauge length, which should ideally be on the longer side—typically 3 to 4 in. and above. A long gauge length provides greater stability to the drill bit and ensures that it is minimally responsive to any side forces that may be applied. The gauge should also ideally not be undergauge if it can be avoided for the same reasoning. The drill bit profile is another important factor, as selecting a drill bit with a deeper profile lets the cone of the drill bit provide stabilization by resisting side forces applied.
Directional well profiles and sections require almost the complete opposite when it comes to drill bit design. The higher the rate of angle building or dropping required, also known as the dogleg severity (DLS), the more responsive to applied side forces and thus laterally aggressive the drill bit needs to be to satisfy the trajectory requirements. Hence a shorter gauge is preferred with most BHA systems, such as mud motors or push-the-bit rotary steerable systems (RSS). RSS that rely on a point-the-bit mechanism still prefer a longer gauge length due to its unique mechanism of utilizing a fulcrum point to orient the toolface, which usually rests on the gauge of the PDC drill bit.
In all drive systems, maintaining toolface orientation is vital to maintaining control of the well direction. This is difficult to achieve when the drill bit is experiencing erratic torque with similar mechanisms to the stick/slip dynamic discussed above. Thus, the idea is to minimize this kind of torque response when building or dropping angle, especially in applications with high DLS. Drill bit design factors such as higher blade count and using depth-of-cut controllers will help the directional driller maintain toolface control. Drill bit vendors will typically be able to carry out drilling simulations to model torque response based on the drill bit design paired with different BHA systems and under specific drilling parameters, along with whether the DLS required can be achieved.
Hydraulics and Hole Cleaning
A drilling system with poor bottomhole cleaning and hydraulics loses efficiency because drill cuttings not evacuated are effectively re-grinded by the drill bit. Cuttings should be cleared away as soon as they are sheared off by the PDC drill bit so that the energy put into the system can be used to drill new rock.. It is the drilling engineer’s responsibility to ensure that there is sufficient hydraulic energy when the drilling fluid exits the drill bit nozzles to clean the bottom hole.
The key measurement often used to measure hydraulic energy is the hydraulic power per square inch at the bit, or the HSI, which is a function of the flow rate, frictional pressure losses at the drill bit, and hole size. If the BHA design utilizes downhole equipment that require hydraulic power to operate, such as mud motors or certain types of reamers, the drilling engineer must consider the energy requirements of powering these tools and ensure that there is sufficient hydraulic energy left to clean the bottomhole.
Through the frictional losses that occur at the drill bit, the drilling engineer can control the HSI using the nozzle configurations of the drill bit design. If a higher HSI is required, a smaller total flow area can be employed.
There also needs to be sufficient space on the drill bit to allow for the drill cuttings to evacuate. This is often referred to as the junk slot area of the bit, which is mainly dependent upon the type of material the drill bit is made of and the bit’s design; a higher blade count, for example, leaves a smaller amount of space for evacuating drill cuttings. This is also one of the reasons why a lower blade count is recommended for higher ROP applications where cuttings are generated at a higher rate. Computational fluid dynamics can be used to model the fluid flow with specific parameters and drill bit design, if more precise analysis is required.
When drilling through formations containing swellable shales such as claystone, bit balling is a potential risk. Bit balling occurs when the rock comes in contact with water, causing it to swell. These shales can stick to the drill bit and effectively gum up the bit’s cutting structure, preventing efficient drilling. In such applications, a steel-bodied bit is recommended. As opposed to matrix-bodied bits, steel-bodied PDC bits have the advantage of a higher junk slot area, owing to the ability of the material to achieve a higher blade standoff without compromising the integrity of the blades. Many drill bit vendors can also apply specific coatings on steel-bodied bits that serve to repel the shales. Finally, steel-bodied bits have the advantage of being more cost-effective than their matrix-bodied counterparts.
Final Thoughts
For many drilling engineers, the complexity of their project requires them to delicately balance many competing objectives in a way that best suits their goals. Drill bit selection, for the purposes of optimizing the drilling process, falls under one of these objectives and is, in and of itself, a delicate balancing act of many different competing requirements. Drilling physics is fascinatingly complex, and the choice of an unsuitable drill bit amidst the chaotic downhole environment, even if for just a minor design factor, can lead to undesirable results. Investing more attention to the selection of a drill bit design that most closely aligns with the unique application and objective of the section can pay off substantial dividends.
