Rotary Steerable System Technology Case Studies in a High-Volume, Low-Cost Environment

Abstract

Abstract An efficient, safety-conscious wellbore drilling method features highly accurate wellbore placement, reduced drilling time, and improved safe drilling practices. Rotary steerable system (RSS) technology provided a cost-efficient solution in a high-volume environment for a US-based oil and gas exploration company drilling 80 to 100 wells per year in South Texas, USA. Although vertical drilling has been in practice since the birth of the industry, maintaining verticality is still challenging and requires alternative drilling strategies. Traditionally, downhole positive displacement motors (PDMs) have been used to control the wellbore vertically in this drilling environment. This drive system typically requires one or two additional bit runs to achieve the target objectives. A reduction of the weight on bit (WOB), or feathering, was also required to maintain a vertical wellbore. The combination of this drive system coupled with the lower-than-optimum WOB leads to a dramatic reduction in rate of penetration (ROP) when steering is required, which is neither cost-efficient nor desirable. The introduction of RSS technology has addressed both of these concerns by allowing the application of higher WOBs for faster ROP while maintaining high levels of wellbore placement accuracy. RSS technology in this environment increased the number of drillsites available as the surface location can be right on the "hard-line" of 467 ft from the lease-line required by the Texas Railroad Commission. Previously, fewer lease-line wells were drilled owing to the problems of keeping the accumulated displacement inside the lease dimensions. This paper presents field studies from 2004 to 2006 demonstrating RSS success in maintaining verticality where the bit tends to walk related to highly faulted, fractured, and dipping formations. The RSS system provided real-time response and a vertical wellbore. Instantaneous wellbore corrections reduced drilling time in some cases more than 40%. In both the vertical and deviated wellbores studied, total depth (TD) was reached ahead of schedule with reduced costs. Introduction In the South Texas region, USA, vertical wells that might drift close to the lease line and thus require corrective action were avoided owing to the expense of drilling them. However, as a result of recent increase in gas prices plus a need to more fully exploit existing leases, the decision was made in 2004 by a US-based oil and gas exploration company to drill more lease-line wells. These lease-line wells were initially drilled with conventional rotary assemblies, and if the well built angle, the first corrective action was to reduce WOB to get the bit to drop angle. However, this would significantly lower ROP and dramatically increase the time to drill a well. This has been exacerbated recently because current polycrystalline diamond compound (PDC) bit technology is progressing toward more aggressive, heavier-set bits for durability and to permit higher WOB to achieve higher ROP. If the lower WOB did not provide sufficient correction, a steerable motor assembly was run in the production hole interval to steer away from the lease line. But this was done with slimhole tools in oil-based mud in a hot-hole, so tool run-time posed a problem. Also, starting in 2004, availability of the high-temperature slimhole tools was becoming problematic, which led to the use of RSS tools in the intermediate hole section. The goal was to keep the well very vertical until reaching the intermediate casing point, thus keeping accumulative drift inside the lease-line. This allowed the operator to maintain high ROP in the intermediate- and production-hole intervals and to use conventional BHAs in the slimhole production interval. This scenario also provided a secondary benefit of mitigating depletion concerns in the Perdido Sand interval.