PDC bit performance in the build section of directional wellbores is complicated by many factors, including the formation, wellbore geometry, the bottomhole assembly (BHA) design and how the curve is drilled. Effectively managing these dynamics to address the specifics of each drilling application is key to optimizing steerability and efficiency.
In Canada and Oklahoma, customized directional bits that deliver consistent yield by closely managing toolface control and side-cutting capabilities are successfully drilling build sections to reliably reach objectives at significantly higher penetration rates. The first use of MARKSMAN Directional PDC Drill Bits more than doubled the average rate achieved with offset hybrid bits.
The directional bits developed by Varel Oil & Gas Drill Bits are based on a highly adaptive design methodology that closely manages toolface control and side-cutting capability to achieve performance objectives for a very specific set of application factors. The bits incorporate multiple features including a stepped gauge to complement motor bend, custom cone geometry for toolface control and high-density cutting structure for side cutting.
Varel builds on design experience and directional drilling knowledge to understand the application and collaborates with operators and directional drillers. Proprietary software is used to quickly and precisely explore options, identify the optimal solution and put a higher performance bit in the field faster.
Directional bit design is broadly focused on optimizing ROP and steerability to drill the curve section as quickly and consistently as possible. Cutting structure aggressiveness, steady torque, directional control and dynamic stability are key factors in the equation, along with durability to reduce bit costs and increase time between trips.
The MARKSMAN bit design process involves understanding how cutter size, blade profile, gauge length and other factors influence efficiency and steerability in a given wellbore geometry and geology. Efficiency gains depend on how effectively this knowledge can be applied. These bit considerations must complement the BHA design to maximize performance while drilling the build section.
Performance-based MARKSMAN bit methodology enhances efficiency by optimizing two key aspects of steerability: toolface control and side-cutting capability. Modifications to benefit bit and BHA performance may include precise variations in cutter orientation, cutter size, cutter density and the bit profile.
A passive toolface for greater steerability is achieved by reducing the aggressiveness of the cone area toward the center of the bit. The design features a shallow cone angle and progressively lower cutter aggressiveness from the shoulder to the center of the cone. A less aggressive, higher angle cutter back rake toward the center of the bit minimizes reactive torque and increases steering response. The transition to a more aggressive cutter orientation on the shoulder enhances side-cutting capability and makes the bit easier to steer.
The software used in developing MARKSMAN bit variations enables a fast, accurate response to specific applications. PDC Designer cutting structure design software simulates scenarios based on actual lithology. The interpreted data are used to assess performance such as lateral stability, durability and aggressiveness. The finished data are directly imported into computer-assisted drafting (CAD) software. DIG-IT software uses the data for in-depth analysis. The application runs drillbit simulations in complex drilling scenarios such as directional applications. It allows engineers to use 3-D CAD bit models to simulate rock interactions such as gauge or blade-top contacts.
The flexibility of the directional PDC bit design approach is illustrated by initial drilling applications in Canada and Oklahoma. The Canadian bits are six-bladed with 11-mm cutters (611); in Oklahoma, they are typically 513 or 613 variations.
First field use
In the first MARKSMAN application, a 6.25-in., 611 bit more than doubled build section ROP compared to 11 offset hole sections drilled with PDC/roller cone hybrid bits (Figure 1). A similar improvement was achieved in a second Canadian field for the same operator.
INTERVAL DRILLED vs. ROP
The lithology in the curve sections of these wellbores is a mix of hard sandstone and shale. The long-running drilling program typically builds an angle from zero to 90 degrees in about 305 m (1,000 ft).
The directional PDC bits were built specifically for the application with premium cutters and a low depth of cut. Collaboration with the operator led to a BHA change to a higher rpm motor. Smaller cutters reduce torque for better toolface control. The cutters allow a higher cutter density that more broadly distributes the point load among more cutters to manage depth of cut. Along with a less aggressive cutter back rake, the design minimizes reactive torque to allow the use of a high-speed motor. Premium cutters addressed the heat generated by the greater rpm.
The January run in the Sundance Field drilled the curve section of 500 m (1,640 ft) at 24 m/hr (79 ft/hr) ROP, building from 16 degrees to 90 degrees. In field offsets drilled in 2018, the average for the field-standard hybrid bits was 11 m/hr (38 ft/h) over a 320-m (1,050-ft) curve section. The Varel bit was pulled for a BHA change and showed little wear with all cutters in a reusable condition.
In March a second run in the Kakwa Field (a slightly tougher drilling area) used the same design bit to build the 341-m (1,118-ft), 0-degree to 89-degree curve at 13.9 m/hr (45.7 ft/hr) ROP. The offset average using the hybrid bit was 384 m (1,262 ft) at 8.8 m/hr (29.1 ft/hr). The Varel bit dull was in excellent condition.
Operators in Oklahoma’s Stack and Merge plays are also successfully using specially designed directional bits in the build sections of wells. The applications generally build from 0 degrees to 90 degrees in 183 m to 213 m (600 ft to 700 ft), with build and turn curves adding 30 m to 61 m (100 ft to 200 ft). The lithology of the Stack and the Merge may vary in the curve sections, and drilling typically encounters variable compressive strengths and some intervals that are not conducive to toolface control.
The Oklahoma bits apply MARKSMAN design fundamentals of toolface control and side-cutting capability. However, the different lithology and operator drilling parameters result in different bit configurations compared to the Canadian applications. There are two primary designs being used in the field: an 8¾-in. 513 and 613.
The first run in March was in the Merge play and drilled the 209-m (687-ft) build section from 15 degrees to 90 degrees in 15 hours for an overall ROP of 14 m/hr (47 ft/hr). When Merge runs of two identical bits were compared to competitor averages, the directional PDC bit design drilled 19% faster (Figure 2).
INTERVAL DRILLED vs. ROP
Drilling build sections quickly and consistently is key to directional drilling performance. By customizing toolface control and side-cutting capabilities to the application, Varel’s MARKSMAN Directional PDC Drill Bits optimize steerability and efficiency to dependably complete directional targets across a broad scope of wells and lithologies.
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