Operators of Gulf of Mexico (GOM) wells frequently reported overtorque issue of bottomhole assembly (BHA) connections when drilling the 26-in. section through salt. Such overtorque often leads to costly tool damage beyond repair (DBR), additional trips, and high nonproductive time (NPT). The average DBR cost per BHA can be as high as USD 1 million. Combined with a complete BHA roundtrip, it can easily cost more than USD 3 million for operators if such failure happens. This has been a problem for several years and has caused significant damage: In 2014, of 15 26-in. PDC bit runs in salt, 40% had overtorque connections and 20% led to DBR. This paper discusses how an integrated multidisciplinary team identified the root cause of and the solution to the overtorque problem. Torsional vibration was believed to be the cause of such failure. Comprehensive drilling dynamics simulation software that is based on empirical bit design knowledge was used to design a new bit to reduce the vibration. A newly developed high frequency downhole recording tool used in the 26-in. section recorded high-frequency torque, acceleration, and RPM fluctuation downhole. This dataset became the key to understanding the downhole vibration in detail because it provided information that cannot be acquired by a traditional MWD tool. Field-recorded data were fed into drilling dynamics simulations to accurately calibrate the drilling dynamics model. The simulations resembled downhole drilling conditions and clearly identified the root cause. The simulations precisely predicted the torque along the entire drillstring and identified why overtorque is present in only a certain part of the drillstring. The calibrated model was used to compare old and new bit designs. The newly designed bit showed much lower torque amplitude with similar torsional vibration frequencies. The simulation indicated that the newly designed bit can significantly alleviate the overtorque issue. Implementation of the new bit mitigated the overtorque issue immediately. As of May 2016, there have been 18 runs with the new bit. Only one run had a slight overtorque issue whereas the rest showed no sign of overtorque connections. DBR and NPT related to overtorque were eliminated. As a byproduct, the average on-bottom rate of penetration increased by 9%. This case demonstrates the effectiveness of the integrated approach to solving drilling challenges.

A fixed PDC cutting element creates an inherent limitation because only a small portion of the diamond table contacts formation and as the cutter wears/chips, drilling efficiency declines. It is well documented that wear flats generate a high degree of frictional heat which breaks down the diamond bond and in extreme cases can even convert synthetic diamond back to graphite.To solve the issue a research initiative was launched to investigate different methods to enable a PDC shearing element to fully rotate while drilling to increase overall cutting efficiency and bit life. Engineers investigated different retention methods and cutting structure designs to create the optimal driving force to accomplish the objective. Several designs were implemented that hold the cutter securely in place and allow full cutter rotation. These assemblies were modeled using an FEA-based system and then tested in the laboratory to evaluate function and strength. Experiments confirmed the new rolling cutter (RC) was able to shear an extended section of rock with a consistent force level (lbs). Conversely, the traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency.The recent introduction of a new rolling cutter PDC bit that utilizes the entire 360° of diamond edge has delivered positive results in field trials. Initial testing was targeted at the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. Application challenges include low ROP and premature tripping for a new bit. A six-bladed prototype PDC bit was manufactured with rolling cutters strategically positioned in the shoulder area. The bit was run on a steerable motor through the horizontal interval with good results increasing total footage and ROP capabilities.In the central USA the rolling cutter has been run more than 70 times and has increased average footage totals by 56% compared to 450 offsets drilled with conventional fixed cutter PDC bits from various manufacturers. The authors will present results of field tests and two case studies that document performance improvement in these challenging drilling environments. They will also outline plans for future development.

Extended footage capabilities and high rate of penetration give PDC bits a distinct advantage over rollercone bits in many applications. However, the fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts the formation, and as the cutters wear/chip drilling efficiency declines. The industry requires new technology that can effectively utilize the entire 360° diamond cutting edge to reduce frictional heat/wear while increasing drilling efficiency and bit life. A plan was initiated to rotate the cutter while drilling and engineers investigated different retention methods and cutting structure designs to create the optimal driving force to accomplish the objective. Several designs were implemented that hold the cutter securely in place and allow full cutter rotation. These assemblies were extensively modeled using FEA and laboratory tested to evaluate function and strength. In a test apparatus, the new shearing element (rolling cutter/RC) was able to cut an extended section of rock with a consistent force level (lbs). Conversely, the traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency. Initial field testing targeted the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. Application challenges include slow ROP and premature tripping for a new bit. A six-bladed prototype PDC bit was manufactured with three rolling cutters positioned in the shoulder area. The bit was run on a steerable motor through the horizontal interval with good results. The next prototype was equipped with additional RCs and drilled more footage compared to offset average. Additional experiments are being conducted with RCs which will continue to increase performance. The authors will present several case studies which will document performance improvement in challenging drilling environments.

A fixed PDC element creates an inherent limitation because only a small portion of the cutter contacts formation and as the cutter wears/chips drilling efficiency declines. It is well documented that wear flats generate a high degree of frictional heat which breaks the diamond bond. To solve the issue an R&D initiative was launched to investigate different methods to enable a PDC shearing element to rotate while drilling to increase overall cutting efficiency and bit life. Engineers investigated different retention methods to create the optimal driving force and allow full cutter rotation. The assemblies were modeled using an FEA based engineering system and then tested in the laboratory to evaluate function and strength. Experiments confirmed the new rolling cutter (RC) was able to shear an extended section of rock with a consistent force level (lbs). A traditional fixed-cutter assembly required steadily increased force to drive the cutter the same distance. Examination of the rolling cutter's dull condition clearly indicated significantly improved durability and cutting efficiency. The recent introduction of a new rolling cutter PDC bit that utilizes the entire 360° of diamond edge has delivered positive results in field trials. Initial testing was targeted at the highly abrasive Granite Wash formation in Western Oklahoma/Texas Panhandle where cutter wear is the predominant failure mechanism. A six-bladed prototype PDC bit, with three rolling cutters positioned in the shoulder area was run on PDM and increased total footage capabilities compared to conventional PDC. The next prototypes were equipped with a smaller, yet more robust generation-3 retaining device. Starting in Q4 2012, the total RC count/bit was progressively increased on five/six bladed designs from 3, 5, 7, 10 and then 12. The 13mm designs are consistently exceeding footage totals compared to offsets in central USA, North Dakota and Canada. In central USA, which contains the largest data set (13 RC runs) the rolling cutter has increased average footage totals by 34.4% compared to offsets drilled with standard PDC from various manufacturers. Case studies will document performance improvement in these challenging drilling environments. The authors will discuss plans to develop a rolling cutter bit to extend lateral run length in an abrasive Middle East formation.

As drilling activity in conventional land-based plays continue to decline, technology focus is shifting to the unconventional shale gas prospects (Haynesville, Marcellus, Eagle Ford). Efficient and repeatable drilling practices, along with costeffective technologies, are paramount to economically exploit the known hydrocarbon reserves because of the large number of horizontal wells required to develop the vast acreage plays. The drilling challenges include high bottom hole temperatures, high mud weights and hole/bit cleaning issues. The key to reducing field development costs and improving project economics is increasing rate of penetration (ROP) in the lateral interval that typically extends 3000 to 6000ft after completing the build section.To solve the penetration rate and hole cleaning challenges, an engineering team analyzed the latest polycrystalline diamond compact (PDC) technologies and best drilling practices to achieve the operator's ROP optimization goals. An FEA-based engineering software system was utilized to predict the dynamic behavior of the bit and BHA components in lithologies comparable to the specific field application. To ensure proper utilization of the available hydraulic energy, engineers used computational fluids dynamics (CFD) to ensure appropriate nozzle placement and orientation to effectively clean the bit face and hole bottom. Conclusions from the dual analysis were instrumental in developing new steel body PDC bit designs specifically engineered for emerging North American shale plays.The new steel body PDC design and the associated bit technologies and updated operating practices have been run in the Bossier City, Louisiana and Tyler, Texas areas with outstanding results. The new PDC technology has increased lateral interval ROP by as much as 80%-100% compared to conventional matrix bodied PDC bits. The authors will present several case studies that document the significant cost savings.