Success in unconventional reservoirs depends on efficiency. The speed at which operators and service providers can safely drill, complete and begin production on these assets is the measure by which many are judged. They are always looking for inventive solutions to loosen the next bottleneck and the one after that. This mindset, coupled with the fast pace of development in unconventional plays, has spawned a rapid succession of new technologies that are ever competing to set the next field record. Efficiency is connected to drilling power, where the pump package has always been a central ingredient—as much so as the drawworks, the top-drive system or any other core component. Mud pumps not only circulate drilling fluid, they deliver power to the drilling assembly.
Mud pumps supply the drilling fluid that is required to operate the downhole mud motor—driving bit rotation and rate of penetration (ROP). This affects average ROP through the ability to slide and build angle as well as instantaneous ROP when rotating the drill string and drilling ahead. Another critical means of power delivery is through the bit itself. As the mud pumps jet the drilling fluid through nozzles in the bit, a force is created that greatly increases bit effectiveness. In both of these examples, the mud pumps are delivering drilling power, not just drilling fluid. In addition to the mud pumps’ importance in drilling power, they are critical in cuttings removal. In configuring the overall drilling package, pressure allocation (and associated power delivery) must be balanced with the ability to remove the drilled cuttings. This balance manifests in the inherit tradeoff between volume and pressure. For a given volume of output, the pressure rating has to be sufficient to power the mud motor and bit and overcome pressure consumers, such as the friction encountered in the drillstring and annulus. Pressure ratings can be increased with reductions in volume, but that limits fluid velocity in the annulus, which is critical for cuttings removal, or hole cleaning. Without effective hole cleaning, any short-term gains in drilling power will be lost in nonproductive time because of additional reaming, stuck pipe or other problems associated with cuttings buildup. We refer to the interdependent work done by the mud pumps and drilling fluid as the hydraulics system, which is a critical aspect of well planning and construction.
In seeking a solution to the volume/pressure tradeoff, operators and well service providers could consider more powerful pump packages or reducing drillstring friction by choosing a larger drillpipe. Although those may be options worth considering for some applications, they are not necessarily the most efficient solutions. If operators and service providers do not choose the most efficient option for any particular field, they should prepare to be left at home during the next project.
Then Versus Now
To tackle the issue of efficiency in the hydraulics system, the evolution of drilling technology and methods in unconventional plays must be examined. Historically, the approach has included:
- Considering the minimum flow rate required to achieve hole cleaning
- Calculating how much pressure is lost through nonproductive consumers (such as inside the drillpipe or annulus)
- Putting any remaining pressure capacity to use by decreasing bit nozzles for improved bit performance
If the bit or any given tool required a specific minimum pressure or flow rate allocation, then the parameters would be adjusted to fit. For example, if a bit required more pressure loss, the bit’s total flow area (TFA) could be decreased to accommodate its need for power, but that would reduce the mud pumps’ capacity for flow rate. This reduction would require adjusting the drilling fluid, which would increase the cuttings carrying capacity, or other tradeoffs would be required, such as generating fewer cuttings by reducing the ROP. Changes to the generic approach above have coincided with changes in drilling conditions because of shifts from drilling conventional wells to unconventional. Some of these changes include the following:
- Length of the drill string—Increasingly long lateral sections mean increasingly long drillstrings. This has an impact on many aspects of the rig equipment. In the hydraulics system, it means more nonproductive pressure consumption and more friction for the mud pumps to overcome before reaching the drilling assembly. Likewise, longer hole sections mean that fluid must be returned to the surface through longer annuli, another nonproductive pressure consumer.
- The role of the mud motor—Given the importance of sliding rates, the motor efficiency has taken an increased role in the average ROP. Motor efficiency, and therefore overall drilling efficiency, is heavily dependent upon the flow rate rather than an allocated amount of pressure drop because this affects motor engagement and performance (though this does not escape an expenditure of pressure). This applies to other directional tools as well, such as rotary steerable systems, which can have a huge impact on overall efficiency.
- Drilling fluid type—Previously, pressure loss at the bit was largely controlled through nozzle constriction, or TFA. This not only improved the bit’s ability to cut the formation, but it prevented bit balling or cuttings accretion that is sometimes associated with the use of standard water-based mud (WBM). Though high-performance WBM has improved many of these hazards, oil-based mud (OBM) inherently requires much less horsepower per square inch (HSI) than WBM. In addition, OBM is highly lubricious and minimizes rotational torque, and OBM becomes the preferred mud type for many basins. Again, this has many implications for the overall operation, but in terms of the hydraulics system it means that less TFA is required for a given level of bit performance, especially with breakthroughs in bit technology. Pressure drop at the bit is still important for bit hydraulics, but this can be achieved by increasing flow rate rather than constricting TFA.
- Hole cleaning environment—Because wellbores are drilled farther out horizontally than down, less density is required for formation pressure containment. Though this can be beneficial for many reasons—such as reducing barite costs and fluid friction attributed to additional solids—less density also means less buoyancy for the cuttings. The closer the fluid is in density to the cuttings’ density, the easier cleaning the hole is because the cuttings literally float up with the fluid. As the density gap between the fluid and the cuttings widens, more lifting burden is placed on the fluid through the flow rate. This challenge is further exaggerated because deviated wellbores also present a more challenging hole cleaning geometry than vertical wells.
To summarize from the example points above, the impact on the hydraulics system has shifted toward more pressure being consumed inside the drillpipe and in the annulus, more flow rate being required for the motor and bit and more flow rate being required for hole cleaning. With all else being equal, each of these factors can be connected directly to increased demand from the mud pumps.
Building on Lessons Learned
Unconventional plays teach operators something new almost every day, and that is one of the most rewarding aspects of this demanding business. These daily lessons culminate into a trend of accelerating efficiency. In terms of the hydraulics system, flow rate has proven to be a key lesson in drilling efficiency because it increases torque output from the mud motor, rock crushing power to the bit and cuttings transport velocity for better hole cleaning. However, if operators want more flow rate, they must consider the tradeoffs between flow volume and pressure capacity. Mud pumps have a direct impact on flow rate, but operators also need to consider the role of the drilling fluid, especially how it contributes to the nonproductive pressure consumption inside the drillstring. If pressure management inside the drillstring is improved, more power is available for constructive purposes. Fluid inside the drillstring moves at a relatively high shear rate. To understand the implications that this has on the drilling fluid, consider the basic behavior of fluid under shear.
For each increase in flow rate, or more accurately, shear rate, there is an increase in resistance to flow or shear stress (see Figure 1). In Newtonian fluids, the relationship of shear rate to shear stress is linear. Most drilling fluids, however, are non-Newtonian because, for each increment of shear rate, the fluid has a smaller increment of shear stress. This is shear thinning, and it is a desirable attribute of the mud system. In fact, this is a critical aspect in determining the amount of pressure consumed inside the drill string. Improving pressure is a central design aspect of a newly introduced invert emulsion system. This system uses a suite of new products, each developed to provide the stability associated with conventional OBM while reducing the amount of pressure consuming viscosity under high-shear conditions. Simultaneously, it provides elevated low shear-rate viscosity for improved hole cleaning and rapid-set/easy-break gels for improved cuttings suspension in the curve and lateral sections. When looking for solutions to current drilling bottlenecks (and the next ones), operators must remember that mud pumps and drilling fluid are partners in the hydraulics system. No matter what the application, improved pressure management pushes drilling efficiency, and efficiency is paramount in the oilfield.