With continuing advances in PCD cutter technology and improved bit body stability, PDC bits have become the dominant force in the worldwide drilling theater, practically replacing the venerable roller cone product. Their high ROP potential and unparalleled durability make PDC bits the tool of choice in both high- and low-cost environments. Even in the toughest applications traditionally reserved for roller cones, PDCs have virtually eliminated the situations where operators are forced to fall back on these types of bits. Today’s PDC bit technologies will positively impact performance and drive down the real cost/ft.
DEPTH-OF-CUT CONTROL ELEMENT
Halliburton’s Cruzer rolling element refines depth-of-cut control and yields multiple performance benefits, Fig. 1. The new PDC bit design technology improves depth-of-cut control (DOCC) and reduces the energy loss by the element to enhance drilling performance. It helps maximize ROP while delivering better tool-face control, to consistently provide on-target intervals.
It’s long been recognized that maintaining constant engagement of PDC cutters while drilling helps minimize torque fluctuations, vibration, and impact-induced cutter damage. While these DOCC elements do help reduce changes in cutter engagement and resultant drilling dysfunction, they do so at the expense of energy available for shearing rock.
Because the new DOCC element rolls, it reduces over-engagement, due to formation changes or vibration without compromising cutting energy. Because of its rolling nature, the diamond-and-carbide bearing lowers the coefficient of friction, ensuring low heat and reduced torque generation. As a result, most of the torque available to shear rock can be used by the cutters for more efficient drilling, while tool-face control is enhanced by the consistent depth-of-cut.
The roller bearing design is packaged with a novel retaining mechanism to keep the element in position for the entire run, and provide consistent depth-of-cut control without impeding its rolling action. In addition to its enhanced wear resistance, Cruzer is also easily repairable, so a bit can be reused multiple times for greater cost-effectiveness. A small package size allows the element to be incorporated into both existing and new bit designs, according to application requirements.
To determine the right technology for a given application, Halliburton’s design at the customer interface (DatCI) process begins with input from the operator to guide development. Using an extensive assortment of analytical tools that include simulation, analysis and software programs, the design team can then apply the appropriate technology to help achieve the operator’s specific goals. The continuous improvement nature of the process enables application experts to continually enhance drilling efficiency and lower costs, even in well-developed areas.
Williston basin case study
In North Dakota, the local DatCI team determined that incorporating the rolling DOCC element into a new bit design would resolve directional control issues presented by a challenging curve interval of 935 ft, including 100 ft of vertical section. The drilling engineer was particularly concerned with optimizing performance through the curve, because it was his first attempt at constructing a 3D curve.
Halliburton’s multi-feature bit solution combined the DOCC rolling element with an 8?-in. MMD55MU MegaForce PDC bit. Using a controlled ROP of 46 ft/hr, the bit drilled the entire 1,035 ft of vertical and curve intervals, and successfully achieved all directional requirements of the complex wellbore design.
At the end of the run, dull grading revealed only minor wear on the DOCC compared to traditional elements that were considerably worn. Field engineers graded the cutting structure 1-1-WT-S-X-I-NO-TD, indicating that the addition of the DOCC element had enabled the bit to retain the aggressiveness of a sharp cutting structure, even after drilling 100 ft of vertical section.
CUTTERS FOR INTERBEDDED FORMATIONS
Operators have continued to seek reductions in cost and increases in efficiency while drilling through multiple formation layers. Advances in cutter technology have enabled operators to drill longer laterals than previously possible. Despite these advances, formations with highly interbedded rock of varying UCS still present a challenge for many cutter technologies. Softer shales, when interbedded with harder sandstones, can cause abrasive wear, while hard dolomite and chert cause excess bit vibration and increases in impact damage. To address the challenges, National Oilwell Varco (NOV) developed ION cutter technology to complement their Tektonic line of PDC bits.
ION cutter technology consists of a high-performance range of PCD cutters that have been designed specifically to overcome critical failure modes in highly interbedded formations. Refined diamond feeds and increased sintering pressures provide a more durable, abrasion-resistant cutter that maintains thermal stability using deep-leach technology. The new cutter underwent extensive testing to obtain performance metrics, with results indicating that the cutters can drill much farther than comparable products, with minimal wear scarring, under difficult drilling conditions. Maintaining the cutting edge provides higher ROP while maintaining durability for the section. Cutter geometry was also optimized using modeled FEA before testing on rock formations under pressure, leading to reductions in drilling torque and MSE, and increases in ROP for the same WOB.
Case studies
In Stephens County, Okla., an operator needed to drill an 8?-in. lateral section, as quickly as possible, without sacrificing bit durability. After studying the formations, it was determined that the bit frame would need to balance efficiency with performance and that the cutters would need high thermal stability. NOV paired a TK63 bit with the ION cutters to increase ROP. The bit was run, and it drilled 3,967 ft at an average ROP of 90.2 ft/hr. Additionally, the ION-equipped bit exhibited approximately 50% less dulling than the offset average. The previous bit made just 3,329 ft of hole at a much-lower ROP of 31.4 ft/hr.
In the Williston basin, an operator needed to drill a horizontal well from surface casing to TD with a total of five BHAs. ION cutters were paired with the drill bits used to drill the tophole vertical, bottomhole vertical, and horizontal sections. In the horizontal section, performance was exceptional, and the operator drilled 9,715 ft at 196 ft/hr and completed the section in just 49.6 IADC hr, Fig. 2. The run set a record for the fastest lateral drilled by the client. The operator also set a record entry-to-TD time, drilling the well in only 8.18 days. Excluding trip time, the entire well was drilled in 5.04 days, almost 20% faster than the average offset.
COMBINATION CUTTING STRUCTURE
Smith Bits, a Schlumberger company, introduced a new type of PDC bit that incorporates ONYX 360 rolling cutters and Stinger conical diamond elements. The design was developed, using the IDEAS integrated dynamic design and analysis platform to optimize the cutting structure to withstand the toughest formations and downhole conditions.
Incorporating ONYX 360 into the cutting structure substantially increases bit durability, because the cutter revolves 360°, enabling the entire diamond edge to contribute to drilling formation. Stinger elements, which have a pointed shape and a thick diamond layer, provide superior impact resistance, compared to conventional PDC cutters. When placed in a position trailing the primary cutting structure of a PDC bit, the elements protect the PDC cutters from impact damage, Fig. 3. By combining the unique cutting elements, Smith Bits was able to develop a unique PDC bit optimized for abrasive/hard and interbedded formations. The combination and strategic placement of these novel cutters maximizes footage and increases ROP.
Egyptian case study. While drilling in Egypt’s Kharita formation, an operator encountered abrasive sandstone interbedded with shale. Unconfined compressive strength in the formation ranged between 18,000 and 25,000 psi, reaching 30,000 psi in some intervals. During a previous run, a PDC bit was able to drill 97 m, but the operator was forced to trip for a diamond-impregnated bit to drill the remaining interval. As a result, the operator developed an initial well plan that called for a rolling-cutter PDC bit to drill 150 m, and then run-in a diamond-impregnated bit to complete the section.
However, Smith Bits designed a specialized PDC by incorporating rolling cutters and conical diamond elements into the cutting structure. The custom-designed PDC was run, and it achieved a record length of 288 m, with ROP averaging 3.7 m/h at an inclination ranging between 5.75° and 1.78°. The bit drilled the hole section to TD in one run, eliminating the trip for a diamond-impregnated bit to finish the hole section. The client saved approximately $30,000 and achieved the lowest cost/meter, compared to offset wells.
石油圈
