Understanding Downhole Vibration Transmission and Disruption in Gulf of Thailand
Authors: Marland Chris , Buchan John , Chen David C-K. , Dumrongthai Panurach , Bourke Andy 
Published: December 2007

Abstract
The identification of drillstring vibration transmission, attenuation, and interaction was important in several wells for ChevronTexaco where vibrations had damaged several MWD and BHA components at two offshore rigs in Gulf of Thailand. This paper presents a study on the investigation of vibration transmission, attenuation, and interactions based on data obtained from dual, downhole vibration sensors. The results of the study have been effective in reducing harmful vibrations and in improving the performance of BHA components.

Introduction
A single Drillstring Dynamics Sensor (DDS™) tool had been run on a number of wells over a period of time on two rigs operated by ChevronTexaco in the Gulf of Thailand. This tool had been used to identify vibration mechanisms believed to have damaged MWD, BHA, and other drillstring components. An additional DDS™ sensor was recently run and was located within a 3 1/2-in. HWDP, 835 ft from the bit and 745 ft above the last stabiliser (see Fig. 1). To the knowledge of the authors, this is the first time that a full tri-axial vibration sensor has been placed in a location far outside of the traditional BHA components. The paper is also believed to be the first report to provide detailed analyses of such data to determine vibration transmission.
Downhole vibration has long been recognized as a complex and costly problem that has often resulted in failures of MWD tools and BHA components and in poor drilling efficiency. Following a rash of vibration related component failures, this study set out to determine the mechanisms responsible for these failures. Various factors were examined, including BHA design, drilling parameters, bit types, and the formation. The well azimuth was also examined in an attempt to find out if azimuth had any influence on downhole vibration.
Various BHA configurations were run, with drill collar/HWDP configurations of 6/21, 9/15, 12/12 and 12/9 used. An Adjustable Gauge Stabiliser (AGS®) was run in all cases, with three different PDC bit types. Two DDS™ subs were run in the successive drilling the 6–1/8-in. production sections. The lower sub was made up to the MWD tool so that real-time data could be transmitted while drilling. It was located 21 ft from the bit. The upper DDS sub was placed three joints from the top of the HWDP (some 835 ft from the bit) as a stand-alone, record-only configuration. No appreciable increase or decrease in vibration levels was evident as a result of these changes in the BHA.
Drilling parameters were kept relatively constant while drilling the 6 1/8-in. sections. However, WOB and RPM were adjusted periodically, usually in response to high surface torque (which, as explained below) is found to correlate closely with stick-slip vibration). In wells where real-time vibration data was not transmitted, the surface torque was often the only indication that stick-slip was occurring.
While this study did not set out to examine the relative merits of various bit designs, it soon became apparent that higher magnitude vibration resulted from more aggressive bits. There is also a close correlation to vibration while drilling sandstone in many instances, although the more aggressive PDC bits exhibit vibration across mixed lithologies.
The Gulf of Thailand Basin, which includes the Benchamas and Tantawan fields, is bound by an elongated series of north-south and northwest-southeast trending Tertiary basins and collapse grabens, formed as a result of extensional tectonic stress. Wells are usually directionally drilled parallel to the trapping fault, and encounter multiple stacked reservoirs. A possible correlation between well azimuth and downhole vibration was found to be difficult because the majority of wells examined were drilled in the NW quadrant, due to the relative positions of the platform and the reservoirs.