Bit Selection Using Mathematically Modeled Indices
- Karen Bybee (JPT Assistant Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 2009
- Document Type
- Journal Paper
- 59 - 60
- 2009. Offshore Technology Conference
- 1 in the last 30 days
- 112 since 2007
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This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19915, "Bit Selection Using Mathematically Modeled Indices Deliver Significant Improvement in Directional-Drilling Performance," by Steve Barton, SPE, Kirk Card, SPE, and David Nwachukwu, SPE, NOV ReedHycalog; Bertrand Cozon, SPE, and Cristina Marinho, Schlumberger; and Adebowale Solarin, SPE, ADDAX, originally prepared for the 2009 Offshore Technology Conference, Houston, 4-7 May. The paper has not been peer reviewed.
Despite the development of models describing fixed-cutter (FC) bit performance, selection still is made on the basis of visible geometric features. Optimal selection is complicated further by the large variation in characteristics of cutting structures, in combination with a diverse range of gauge lengths and geometries. The full-length paper presents a set of performance indices for FC bits that are derived from a sophisticated mathematical model and describe performance in terms of rate of penetration (ROP), durability, stability, and steerability.
Offshore drilling in West Africa poses several drilling challenges that have limited drilling performance and build-rate capabilities in directional applications. The extremely soft sandstone and shale lithologies in the vertical intermediate section are prone to erosion and hole enlargement with high hydraulic energy. Hole enlargement reduces deflection forces for commercial rotary-steerable (RS) tools as well as mud motors, which significantly decreases build-rate capabilities and limits directional plans and capabilities. The associated hole enlargement in the vertical section creates a drilling environment that is subject to increased risk of lateral vibration (bit whirl), which even in soft formations is capable of catastrophic damage to bottomhole-assembly (BHA) components and the bit cutting structure.
Compromising mud flow and hydraulic energy in these soft and fast drilling sections increases risk of loading the hole with cuttings, of increased equivalent circulating density (ECD), and of stuck pipe. As depth increases, formation integrity increases, which helps to improve directional response because the increased weight on bit (WOB) provides flex to the BHA and improves control. However, in many of these applications, high hole angle, limited drilling parameters, and interbedded lithologies (with high compressive-strength variability) combine to increase risk of torsional vibration. Aside from mechanical damage to the components of the BHA, this also will lead to unpredictable directional response and reduced directional capabilities. As such, it is extremely important to select a drill bit that is matched to the specific requirements of the system, thus maximizing directional efficiency. Unfortunately, the ideal design can be difficult to identify visually.
|File Size||129 KB||Number of Pages||2|