The operator is active in drilling deepwater (DW) exploratory, appraisal, and development wells in the central and western areas of the Gulf of Mexico (GOM) where water depths exceed 4,000 ft. In this demanding application, a key step to a successful well is achieving high performance in the large-diameter surface sections of the well. This important segment can start a well ahead of the authorization for expenditure (AFE) or create setbacks and added unplanned costs. Increasing the rate of penetration (ROP) and improving wellbore quality are two essential components for reducing cost of the riserless sections of any deepwater well. Verticality must be maintained throughout the 26-in. large-diameter section to reduce casing wear and to ensure torque and drag remains minimal while drilling to deeper depths. The 26-in. hole section is drilled riserless and a high ROP generate additional savings by lowering the drilling fluid cost. The higher percentage of cuttings provides the additional equivalent mud weight so pump and dump (PAD) mud is not required. The increased ROP needs to be achieved with low vibration levels to avoid any bottom hole assembly (BHA) component failure that would necessitate an avoidable and costly round trip. The operator has previously drilled with 18⅛-in. hybrid bits in salt and sub-salt formations and has recognized the potential of hybrid bits and their ability to drill fast with stable drilling conditions. Several drilling records have been set in this hole size. Encouraged by the performance gains and better drilling efficiency of initial hybrid bit runs, the operator planned to reduce cost of their riserless drilling section in a batch drilling program in GOM. The 26-in. hybrid bit was implemented to batch drill three hole sections, each approximately 3,400 feet long. The operator was able to optimize the drilling parameters for each successive well due to growing confidence in the stable drilling environment. This enabled the drillers to increase the ROP and greatly improve time savings. The three intervals were drilled at ROP of 255, 308, and 379 ft./hr., respectively; breaking GOM field ROP records for each consecutive run with this operator. All three penetration rates have also surpassed the current world record ROP for this hole size. Subsequent 26-in. hybrid bit runs have established consistently higher ROP and have proven to be a significantly better solution when compared to polycrystalline diamond compact (PDC) bits. This paper presents the details of the performance improvements achieved through the use of large-diameter hybrid bits, compares the drilling efficiency of large-diameter PDC and hybrid bits, and discusses some important design aspects of the hybrid bit that deliver stability and steerability.

Deepwater wells routinely use concentric reaming devices in the bottomhole assembly (BHA) to lower the equivalent circulating density (ECD). In Gulf of Mexico (GOM) applications, concentric reamers are frequently used and are positioned approximately 100 to 150 feet behind the pilot bit to address formation evaluation and other operational constraints. This distance between a drill bit and the concentric reamer poses bit–reamer synchronization challenges, especially while drilling interbedded formations, where the bit could drill a softer formation while the reamer is placed in a harder formation or vice versa. This situation causes fluctuations in the compressive load at the bit and reamer. Cutting element damage often results from overloading, leading to a premature and costly trip. In many cases, the pilot bit or reamer could be deprived of the optimal compressive load to cut the formation, resulting in lower-than-expected penetration rates. Inadequate and fluctuating compressive loads at the bit or reamer often trigger unsustainable vibrations. Efforts to address the bit-reamer matching issue are ongoing in the industry, and managing the aggressiveness of pilot bit and reamer is frequently used as a potential solution. Although modelling programs are extensively used during the well planning process, a lack of specific guidelines continues to exist in the industry. Hybrid bits, which combine polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) rolling cutter elements, have been widely and successfully used in GOM. These bits offer higher drilling efficiency because of their dual cutting elements and balanced aggressiveness. The results of 18⅛-in. hybrid drill bit usage with a concentric reamer provided encouraging results and offered a potential solution to the bit-reamer synchronization issue. Using real-time downhole data, this paper evaluates and compares bit and reamer load distribution, drilling mechanics of PDC and hybrid bits, and provides valuable analytical insights on successful application of hybrid bits to address the issue of bit-reamer synchronization.

Drilling interbedded formations can induce torsional vibrations that result in inefficient drilling and damage to drillstring components. A common bit choice for these applications is a standard polycrystalline diamond compact (PDC) drill bit; however, PDC bits due to its shearing action often exhibit some level of torsional dysfunction. Historically, the most effective method to mitigate torsional vibrations in PDC bits is to use fixed depth-of-cut (DOC) control technology that restricts the PDC bit formation engagement at a pre-determined ratio of rate of penetration (ROP) and drillstring RPM. The challenge with using fixed DOC control is finding a compromise between limiting vibrations through targeted sections without limiting ROP in others. To address this, a self-adaptive DOC technology was developed. The self-adaptive DOC technology automatically adjusts the DOC engagement threshold as drilling conditions change, eliminating manual parameter adjustment required at surface to manage torsional dysfunctions. This paper will cover self-adaptive bit runs from deepwater Gulf of Mexico wells. In a recent run, a 12¼-in. bit drilled past 30,000ft measured depth (MD) in an abrasive and interbedded section. The self-adaptive bit delivered a 48-percent improvement in ROP over the best offset, saving 23 drilling hours while exhibiting 97-percent smooth drilling concerning stick-slip and 100-percent smooth drilling to axial and lateral vibrations. Another application yielded excellent results in a section featuring bottom-hole coring work. In three separate runs, the self-adaptive bit drilled a sand/shale formation with 98-percent smooth drilling concerning lateral vibrations, axial vibrations, and whirl. It also exhibited 97-percent smooth drilling concerning stick-slip. The self-adjusting technology helped to return to drilling despite the coring disrupting the bottom-hole pattern. Real-time drilling dynamics data measured downhole is used for demonstrating the effectiveness of self-adaptive DOC control technology for sustained drilling performance improvement in deepwater wells.