Sudden growth of the Permian's Delaware Basin, exploiting multiple unconventional targets, has increased the number of drilling rigs in the area to well over 550. This rapid expansion of drilling rigs has diluted the pool of experienced drillers and operators in the region, which in turn has caused numerous drilling optimization problems such as poor penetration rates and accelerated wear on drillstring components. To enhance the learning curve and address these drilling practices, a number of operators have requested real-time downhole dynamics and mechanics information to improve drilling performance. Previously, a dedicated ‘down-hole drilling dynamics service’ was successfully deployed to the Permian for recording the down-hole drilling dynamics environment in memory mode. This service confirmed strong dynamic events occurring, and subsequently allowed adjustments to be made to the drill string components and operational parameters. However, the memory only approach meant a delayed improvement cycle, never reaching its full optimization potential or technical capabilities. Providing a ‘real-time down-hole drilling dynamics service’ delivered immediate improvements to performance through real-time drilling parameter adjustments, as well as enabling optimum bit and bottom hole assembly selection for subsequent wells. The continuous performance improvement loop highlighted the best drilling practices, permitting the development and implementation of refined drilling procedures, and further enhanced performance and safety. This paper addresses drilling dynamics challenges encountered and overcame while drilling vertical sections in six wells (on four rigs) by one operator in the Permian Basin. The data and examples presented in this paper provide an understanding of the benefits of managing drilling parameters in real-time and express the best drilling practices. Using a ‘real-time down-hole drilling dynamics service’ reduced overall operator costs by an average of 24% per well when compared to previous wells. Additionally, real-time down-hole weight on bit functionality offered an increased safety feature over a conventional drilling system, while the use of close-to-bit rotational inclination provided enhanced vertical control versus the standard survey system of a conventional straight-hole drilling 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.

There are many challenges to be overcome when drilling lateral sections in the Wolfcamp horizon of the Delaware Basin. These include wellbore instability, formation heterogeneity, low rate of penetration (ROP), poor weight transfer and drill bit damage. Downhole data was captured in order to provide insight into these challenges. A Downhole Dynamics Tool (DDT) was used to capture the data necessary to investigate the drilling performance challenges. The data collected was downhole weight on bit (DHWOB) and torque, downhole bending moments and tool face, annular and bore pressure readings, and downhole vibrations. The analysis of these data provided insights into the effectiveness of connection and WOB zeroing practices, clarity about recurrent bit nozzle plugging and bit damage, and a better understanding of wellbore tortuosity and effective WOB transfer. The DDT was used on multiple wells, in memory mode and in real-time. On the initial trial well, the tool was run in memory-only mode due to drilling system requirements; subsequently real-time data was additionally used to further optimize drilling performance. After retrieving the data and analyzing trends from the initial memory-only runs, the following could be highlighted: Using downhole pressure and WOB, it was shown that the bit was still on-bottom during connections. Pipe stretch calculations were performed and matched with downhole data in order to verify minimum stick up length required to effectively pick the bit off-bottom during connections. This allowed the development and adoption of a new standard for connection practices.The downhole bending moment data identified the presence of wellbore rugosity driven by several factors, including magnitude of the steering force from the rotary steerable system (RSS) steering unit.Downhole WOB data showed that weight transfer efficiency was not 100%. The loss of WOB is inferred to be caused by factors such as hole rugosity, inconsistently zeroed surface WOB and friction losses.The data obtained about the causes of bit plugging, bit coring damage, and wellbore rugosity, was used to redesign and optimize future bits to be used in lateral drilling operations. Some of the recommended enhancements included changes in nozzle orientation, improved impact resistance for inner cutting structure and improved gauge pad design. Use of downhole data identified factors affecting drilling performance which differed from what was initially believed. The use of downhole data enabled changes in operational practices, drill string and bottom hole assembly (BHA) design, bit design, and drilling parameter roadmaps. The lessons learned and best practices from the data analysis were successfully transferred and implemented across all development areas in the Permian Basin.

Longer wells and increasing complexity of the bottom-hole assembly (BHA) are causing drilling operations to become harder to achieve. Combined with strict timelines and the demand for higher rates of penetration (ROP), the entire drilling system operates at its physical (loads, bending moment, etc.) and operational (drilled formation, drilling parameters, well path, etc…) limits. Exceeding these limits can induce excessive drilling vibrations and dysfunctions like whirl that can be harmful for bit, bottomhole assembly, reaming device or drillpipe. Neglecting operational limits can therefore lead to damage, wear and tool failures that ultimately result in nonproductive time (NPT) and higher cost. Additionally, the number of reaming operations increases. The added challenge of complex reaming operations demands supplementary planning effort. In this paper, the authors focus on prejob and post-well analysis using simulation and modeling techniques. The result of the analysis leads to optimized reaming and drilling practices that are further elaborated following close interaction with field personnel. Applying the improved drilling practices result in best-in-class performance and lower nonproductive time. In-house dynamics simulation software is used to calculate the natural frequencies and corresponding mode shapes of the BHA. Differences in BHA setup are associated, critical excitation sources identified and forced response analysis results compared. Data from various deployments of a high-end rotary steerable system (RSS) BHA with a reaming device are analyzed and used to validate the simulation results. The data is derived exclusively from a massive salt section (similar formation being drilled) to lessen the formation’s influence on drillstring dynamics. Incorporation of sophisticated simulation tools plus the close cooperation of field personnel resulted in excellent operational and drilling performance. In today’s challenging drilling applications, the insights gained have highlighted further opportunities for delivering optimal performance, and further assuring bit, BHA, reaming device and drillstring integrity.

Poor drilling performance can lead to increased costs when enhanced drilling performance and extended reach are the main goals for oil operators. Service companies and operators can use the latest technology and several pre-well planning processes and methods to enhance drilling operations effectively and attain these goals. These processes include developing a thorough understanding and application of the geological structure and conducting a formal planning process that incorporates all aspects of drilling, well design, formation evaluation, bit selection and bottomhole assembly. In this dynamic market where companies are trying to minimize the cost and attain the objective, basic planning and execution using the latest advanced technology are not enough to provide significant performance improvements. Extensive job planning, including sensitivity analysis, is essential. During the execution phase, close monitoring of drilling parameters and continual testing against modeled data help identify hazards early. Enabling quick and informed decisions to ensure safe and efficient drilling in a challenging environment will be one of the main factors to improve performance. Using the right downhole optimization tool with highly experienced engineers enable the interaction with real-time parameters. That's the key factor to overcome extended-reach challenges such as Steering in different environmentsVibrationsTransfer of usable energyHole cleaning and quality indications Supporting downhole optimization with real-time geomechanics will influence the success rate to deliver the expected performance. The involvement of geomechanics in the planning stage and during execution enables faster and safer drilling and resolves many challenges in extend-reach wells such as Wellbore stabilityHole qualityHole cleaningPressure managementTorque and dragMud system and properties This paper highlights the importance of utilizing a downhole optimization tool and real-time geomechanics by describing a case study from the Middle East.