The Williston Basin has become one of the more lucrative oil reservoirs in North America over the past few years. The main reservoir occupies about 200,000 square miles of the subsurface of the Williston Basin, covering parts of Western North Dakota, Eastern Montana, and Southern Saskatchewan. The Bakken Formation was first discovered in 1951, but efforts to extract oil from it have historically been difficult. Efficient production of the Bakken has been achieved with long horizontal wells drilled through reservoirs at depths ranging from 8,000 ft to 10,500 ft (2,438 m to 3,200 m) true vertical depth (TVD). The target reservoir depths and the extended lateral wellbore lengths, require more powerful rigs to meet the operational demands of these well designs. The increased cost and tight economics associated with this play present a strong incentive to improve the drilling performance by reducing drilling time and cost. As a result, a strong focus was placed on improving drilling efficiency in the 9,000 ft to10,000 ft (2,743 m to 3,048 m) lateral wellbore sections, which have the largest impact on the overall well cost. This paper will introduce the challenges encountered when drilling these wellbore designs and outline the approach taken to optimize the drilling process. The usage of high-performance drilling motors, a review of previously used bottom hole assembly (BHA) concepts, and the benefits of gathering additional real-time downhole drilling data to validate or change best practices will all be discussed. The data presented has been gathered over the past 18 months, mainly in Dunn County of North Dakota, and will show rate of penetration (ROP) improvements of about 50% over this time period. This improvement in drilling efficiencies has proven to reduce the overall drilling time and has impacted the economics of this play significantly.
The demand for reduced AFEs for horizontal wells drilled in the Niobrara unconventional shale play increased the need for improved drilling efficiencies. Better efficiencies can be achieved by utilizing monobore well designs which maintain a single diameter hole size for the vertical, curve and lateral sections, eliminating the need for an intermediate casing string and the subsequent need to change out drilling assemblies for a reduced hole size. Positive displacement motors (PDM) with short bit-to-bend technology (SBTB) enable the well to be completed with a single conventional drilling assembly. To drill monobore wells in a single run, the following solutions were implemented: A positive displacement motor with SBTB and reduced adjustable kick-off (AKO) angle to achieve planned build-up rates and prevent component damage.Optimal motor output torque and speed for desired rate of penetration (ROP) and bit life.Drillstring and bottomhole assembly designed for improved drilling mechanics.Optimized drilling fluid program to maintain wellbore stability in challenging formations. Each solution enablesfor the monobore wells to be drilled in a single run, which decreases the days on well by reducing time spent running intermediate casing and tripping for drilling assemblies. This paper compares the monobore well design to the original well design utilizing multiple hole sizes by studying build-up rates (BUR), days on well, ROP and time spent tripping. The dataset used for this study comprises six single- conventional assembly monobore wells and six representative multiple-hole size wells. A consistent drilling efficiency improvement was apparent in the comparison. This paper shows in detail how short bit-to-bend motor technology is an innovative solution to drilling the Niobrara unconventional shale play with a single conventional assembly.
Economically exploiting the Bakken reservoir of the Williston Basin requires long horizontal wellbores through the drilling zones which continually change from sandstone to siltstone to shale with hard calcite cementation. Changes of formation within the drilling zone have caused numerous drilling challenges by creating dynamics issues, resulting in vibration problems and bit/bottom hole assembly deflections. These, in turn, result in high local doglegs that lead to a loss of drilling efficiency. Traditionally, a real-time downhole dynamics tool has been used occasionally within lower-cost drilling projects to accelerate learning about the downhole environment. This knowledge and real-time control of drilling parameters are essential. However, the value of these downhole tools may be underexploited, since they might not be considered economical for everyday use in the lower-cost drilling projects. Case history examples display the benefits due to the closer-to-the-bit steering control from bending moment and bending toolface data, and have made the use of this downhole dynamics tool a necessary choice. This paper will expand on the challenges encountered while drilling the long lateral sections in the Williston Basin, and show how the use of real-time downhole dynamics information helped optimize the drilling effort by saving time and increasing the percentage of successful one-run laterals. Furthermore, the paper expands on the practical use of the directional information from bending moment and bending toolface close to the bit thus allowing the directional driller to make better real-time decisions on whether a wellbore correction is really needed. The paper is supported with over 30 months of field examples and results.
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