Worldwide the costs associated with the exploration and production of oil have increased at a nearly exponential rate. This sharp rise in daily costs has also led to a new urgency from operators to find more reliable and efficient ways of doing business. Shock and vibration (S&V) are the leading cause of failure for measurements-while-drilling (MWD) and rotary steerable systems (RSS) today. These failures have a major impact on operators and service companies, costing millions of dollars in repairs and hours of rig time. A wide variety of service companies now offer lateral, axial, and transverse shock measurements, as well as downhole revolution per minute (RPM) readings to better understand downhole dynamics. These measurements in the best of cases offer a reactive method of drilling, and at the worst provide no help in solving the problem or preventing damages to the bottom hole assembly (BHA). For shock and vibration measurements to be effective, operators and service companies need to work together to create a comprehensive process to include each phase of drilling: planning, execution, and evaluation. A shock and vibration standard combined with increased client awareness and education have allowed a new level of success to be set at the rig site. Now, shock and vibration issues at the rig can be flagged in real-time and monitored remotely from an operations support center (OSC). This communication structure, coupled with pre-job planning and modeling and the capture of post run lessons learned, can be used to offer solutions when problems arise; thus preventing damage to the BHA, reducing rig non productive time (NPT), and improving the rate of penetration (ROP). Introduction In 1984, a concerted effort was made by service companies to improve the mean time between failures (MTBF) for MWD systems. Besides a tool redesign and improved repair and maintenance initiatives, service companies began using modeling techniques to improve BHA design and reduce downhole shocks and vibrations.1 The first real-time vibrations measurements sub was developed in 19892. Over the next few years, step change improvements in MWD transmission capabilities led to a better understanding of the downhole environment by use of the vibration subs at different intervals in the BHA. The increase in data and accurate modeling allowed for the first integrated shocks and vibration mitigation plans from operators to be developed in 1994.3 This approach showed significant savings by using all of the shock and vibration tools available at the time. The results of this study concluded that service companies would need to take the next step in developing and applying these techniques in the industry. Since 1994, many methods have been published to improve downhole drilling efficiency through the reduction of downhole vibrations. Dynamic modeling programs to identify ideal drilling parameters, advancements in bit design, and improved mud systems have played a key roll in reducing drilling problems in high risk environments. In spite of the vast amount of knowledge surrounding the subject, many operators still view these types of interactions as inevitable, attempting mitigation on a well-by-well basis as the problems occur. While there are no definitive, industry-wide statistics on the percentage of NPT associated with S&V, previous studies have shown that as much 75% of lost time drilling incidents lasting more than 6 hours were associated with drilling mechanics.4 Vibration-induced failures—washouts, twist-offs, downhole tool failures and uneven or excessive wear on tubulars—are severe and costly, amounting to millions of dollars in losses for the industry annually. Sustained high levels of vibration increase the rate of drill string and top-drive fatigue. S&V can also have a significant impact on drilling performance, affecting distance drilled, ROP, and downtime for repairs and maintenance. High levels of torsional vibration and stick/slip reduce the efficiency of rotary steerable systems, making it harder to achieve the desired directional response. Well bore integrity can also be affected. Lateral vibrations are a direct indication that the BHA collars are crashing into the wellbore, and even less dramatic vibrations can damage unstable formations.

Losing a bottom hole assembly (BHA) is one of the most costly unplanned drilling events that can occur for an operator. Time spent fishing for the lost assembly, the rig time wasted waiting on the mobilization of equipment and people, as well as the additional costs of whipstocks, cement, and directional tools significantly increase the cost of a well and often results in exceeding the approval for expenditure (AFE). The new well plan may also lead to any number of problems with tortuosity and torqueand-drag farther down the wellbore. Typically, these expenses are invoiced individually, obscuring the cumulative cost to reach the same true vertical depth (TVD) as the stuck assembly. This paper will analyze data and case studies in the Gulf of Mexico (GOM) to perform a risk analysis that includes the true cost of sidetracking a well, with and without additional LWD technology in the drill string providing key real-time measurements.