Pilot Bit and Reamer Matching: Real-Time Downhole Data Differentiates Hybrid Drill Bit’s Suitability with Concentric Reamer in Deepwater, Gulf of Mexico Application
- Ashabikash Roy Chowdhury (Baker Hughes, a GE Company) | Ralph Serrano (Baker Hughes, a GE Company) | Wayne Rodrigue (Baker Hughes, a GE Company)
- Document ID
- Society of Petroleum Engineers
- SPE/IADC International Drilling Conference and Exhibition, 5-7 March, The Hague, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2019. SPE/IADC Drilling Conference and Exhibition
- 1.5 drill Bits, 5.3.4 Integration of geomechanics in models, 1.8 Formation Damage, 5 Reservoir Desciption & Dynamics, 1.6 Drilling Operations, 1.10 Drilling Equipment, 5.3 Reservoir Fluid Dynamics, 1.1 Well Planning, 1.6.1 Drill String Components and Drilling Tools (tubulars, jars, subs, stabilisers, reamers, etc)
- Concentric reamer, Drilling efficiency and stability, Hybrid bits, Bit-reamer synchronization, Balanced aggressiveness
- 2 in the last 30 days
- 179 since 2007
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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.
|File Size||1 MB||Number of Pages||9|
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