Analysis of Drilling-Dynamics Data Solves Severe Vibration Issues
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 122051, "In-Depth Analysis of Drilling-Dynamics Data Solves Severe Vibration Issues Drilling Interbedded Sand/Shale Sequences in 3D-Directional Well Profiles," by J.E. Armour and R. Sankar, BP Trinidad and Tobago, and I. Thomson, SPE, D. Ramchune, and M. Sas, Baker Hughes, originally prepared for the 2009 SPE Latin American and Caribbean Petroleum Engineering Con fer ence, Cartagena, Colombia, 31 May-3 June. The paper has not been peer reviewed.
The main concern in the 17½-in. section is the vibration experienced while drilling through the interbedded sand and shale formations. This section is drilled with a rotary-steerable system (RSS), and thus vibration control is very important. To provide a better understanding of the dynamics involved during the drilling of the 17½-in. sections, a downhole drilling-dynamics tool was used to capture in-depth vibration data while drilling.

Introduction
The Cashima field was discovered offshore southeast Trinidad in 2001. The field is approximately 45 miles east of Galeota Point, in water depths of approximately 270 ft.
The geology of the Cashima field is characterized by sequences of inner-to-outer-shelf deltaic sandstone reservoirs.
The 17½-in. sections typically are drilled from a start depth of 2,800 ft to a total depth (TD) at measured depth (MD) of 9,800 to 12,500 ft. The 17½-in. section is drilled directionally, though the level of deviation varies from well to well, depending on the target reservoir.
The main concern in the 17½-in. section is the vibration experienced while drilling through the interbedded sand and shale formations.

Project Background and Operator Expectations
Six development wells were drilled during the major Cashima development campaign. The six wells were comparable in terms of profile and lithology encountered. During the drilling of the six wells studied, downhole-tool failures were experienced on Well 2, Well 3, and during Run 1 of Well 4. The three wells where failures were recorded were drilled with the same type of polycrystalline diamond compact (PDC) bit. The wells where no downhole-tool failures were experienced—Well 1, Run 2 of Well 4, Well 5, and Well 6—were drilled using a different PDC bit. Both bits had six blades and 19-mm cutters.
The six 17½-in. sections became the focus of a study to investigate changes made to the bit design with the objective of reducing the downhole vibration experienced during drilling. The ultimate objective was to protect the RSS from vibration-induced failure and drill the 17½-in. sections safely in one run.

Drilling Assembly
It is well known in the drilling industry that severe vibration is one of the main causes of catastrophic downhole-tool failures, poor borehole quality, and low drilling efficiency. When drilling large hole sizes with heavier and stiffer bottomhole-assembly (BHA) components, vibration hazards are maximized. To mitigate the risk of severe destructive vibration, a comprehensive downhole drilling-dynamics tool was placed on top of the RSS.