Unplanned sidetracks are low-frequency high-cost events that have meaningful negative impact on the economics of oil field development. While it is clearly desirable to reduce the frequency and severity of unplanned sidetracks, without a robust baseline for event frequency it can be difficult to estimate the value and efficacy of actions taken to mitigate sidetrack risk. For high volume drilling operations, there exists enough data to establish a meaningful baseline. This study aims to quantify the costs of unplanned sidetrack operations to drilling in North America by estimating the frequency of sidetracks, the reason the sidetrack was needed, typical amount of lost footage and time due to the sidetrack being required. With estimates of these values available a better cost-model for sidetracks maybe developed with which sidetrack mitigating technologies and techniques may be better evaluated for return on investment. A comprehensive set of approximately 6,500 North American wells drilled in a two-year timespan (2019-2020) by a variety of operators, drilling contractors, and directional service providers was analyzed for frequency of sidetrack operations. In each case where a sidetrack was performed, a review was conducted to determine whether the sidetrack was planned, and whether a reason for sidetrack was recorded. Lost footage and time were estimated from survey records the original holes and the sidetrack wellbores. Cases where there was an intervening well drilled before attempting a sidetrack were excluded from lost time analysis. Also reviewed were case where multiple sidetracks were ultimately required for successful drilling of each wellbore, and whether an initial sidetrack increases or decreases the risk additional sidetracks being required. There were over 450 wells that required at least one sidetrack. Most of these sidetracks were unplanned and fell into one of four major categories: Equipment lost in hole, directional drilling error, unplanned geology, and hole quality problems. These four categories accounted for nearly 95% of all unplanned sidetracks. The average footage lost due when sidetracking was 2750ft. The average lost time was greater than two days. For wells that have already performed an unplanned sidetrack, it was found that with each additional sidetrack in a well the risk of requiring an additional sidetrack increases further. This suggests that there is even more value in preventing the first sidetrack than there may first appear. By establishing baseline rates of unplanned sidetracks for several common causes an expected cost to operations can be estimated prior to embarking on a development campaign. In the future, by demonstrating improved results over these baseline values, new technologies and drilling practices can better estimate the value provided to a drilling operation by mitigate rare adverse events.

Appropriate selection of a bottom-hole assembly (BHA) is critical to the success of a drilling operation. In US Land drilling, these assemblies are often selected using local heuristics rather than rigorous analysis. These heuristics are frequently derived from the incentives of the directional contractor as opposed to incentives for the operator. Large motor bends enable more rotation though the curve and reduce the possibility of tripping for build rates. Unstabilized motors are believed to aid sliding and tool face control. Both of these practices lead to drilling a more tortuous wellbore and may cause problems later in the well’s life. This study quantifies the impact of these practices and proposes alternatives that can balance the needs of directional companies with the desire of operators for high-quality wellbores. Over 60 conventional motor assemblies used to drill curves in the Eagle Ford and Permian were analyzed for directional performance using commercial drillstring analysis software. The sliding and rotary tendencies were modelled through the curve across a range of potential drilling conditions. Expected build-rate models were validated by comparison to the maximum achieved doglegs in the directional surveys. When available, additional validation was performed using motor yields calculated from slide sheets. The validated models were compared to the dogleg severity requirements for each assembly’s respective well plan. Comparisons of slide ratios and slide/rotate tendencies of the BHAs were used to estimate the impact on wellbore quality using the tortuosity metric proposed by Jamieson (2019). Typical well plans for both basins had curves of 10 degrees/100ft with no well plan greater than 12 degrees/100ft. Typical bottom hole assemblies were capable of >15 degrees/100ft under normal sliding conditions, with some assemblies capable of >20 degrees/100ft of build. Predicted build rates were validated by slide sheets and observed dogleg severities. Common characteristics among assemblies with excess capacity were high bend angles (>=2 degrees) and minimal stabilization. These slick assemblies also had a strong drop tendency in rotation at low inclinations. The combination of high-build rate with rotary drop greatly increases tortuosity, particularly in the early stages of well. A minority of the assemblies used a lower motor bend angle (<2 degrees) combined with multiple stabilizers. These assemblies had a more consistent directional capability throughout the curve and held angle in rotation. The success of these assemblies confirms that a higher quality wellbore with an improved BHA design is technically achievable. As increasing attention is afforded to the topic of wellbore quality it is important to have methods available to technically achieve high-quality wellbores. In addition to the management of drilling practices, it is also important to have an appropriate BHA design that can enable those practices

Summary Appropriate selection of a bottomhole assembly (BHA) is critical to the success of a drilling operation. In US land drilling, these assemblies are often selected using local heuristics rather than rigorous analysis. These heuristics are frequently derived from the incentives of the directional contractor as opposed to incentives for the operator. Large motor bends enable more rotation through the curve and reduce the possibility of tripping for build rates. Unstabilized motors are believed to aid sliding and tool face control. Both of these practices lead to drilling a more tortuous wellbore and may cause problems later in the well’s life. This study quantifies the impact of these practices and proposes alternatives that can balance the needs of directional companies with the desire of operators for high-quality wellbores. More than 60 conventional motor assemblies used to drill curves in the Eagle Ford and Permian basins were analyzed for directional performance using commercial drillstring analysis software. The sliding and rotary tendencies were modeled through the curve across a range of potential drilling conditions. Expected build-rate models were validated by comparison to the maximum achieved doglegs in the directional surveys. When available, additional validation was performed using motor yields calculated from slide sheets. The validated models were compared to the dogleg severity (DLS) requirements for each assembly’s respective well plan. Comparisons of slide ratios and slide/rotate tendencies of the BHAs were used to estimate the impact on wellbore quality using the tortuosity metric proposed by Jamieson (2019). Typical well plans for both basins had curves of 10° per 100 ft with no well plan greater than 12° per 100 ft. Typical BHAs were capable of >15° per 100 ft under normal sliding conditions, with some assemblies capable of >20° per 100 ft of build. Predicted build rates were validated by slide sheets and observed DLSs. Common characteristics among assemblies with excess capacity were high-bend angles (≥2°) and minimal stabilization. These understabilized assemblies exhibited unstable rotary tendencies across a range of drilling parameters. The combination of high-build rates with rotary drop masks the true level of tortuosity in a wellbore, leading to an underestimation of unwanted curvature. A minority of the assemblies used a lower motor bend angle (<2°) combined with multiple stabilizers. These assemblies had a more consistent directional capability throughout the curve and exhibited stable behavior in rotation. The success of these assemblies confirms that there is potential for tailoring BHA designs to improve wellbore quality without compromising the technical objectives of the well. As increasing attention is afforded to the topic of wellbore quality, it is important to have methods available to technically achieve high-quality wellbores. In addition to the management of drilling practices, it is also important to have an appropriate BHA design that can enable those practices.