bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing and Testing a New Rotary Steerable System (RSS) for the Onshore Drilling Market
Authors: Gorrara Andrew , Grant Shona , Kvalvik Tore , Bakke Stig , Clark Peter 
Published: March 2015

Abstract
Whilst Rotary Steerable Systems (RSSs) have been used offshore and in high value directionally drilled wells for many years, their penetration into the land-based market has generally been slow. This is changing with the rise of unconventional shale drilling in North America. Here the small license/lease area combined with the need for as long a lateral as possible to boost productivity, is driving the market for improved rotary steerable tools than can build from a vertical to horizontal well profile in as short a radius of curvature as possible. The new tool discussed in this paper is a short RSS that is designed to deliver a 15 degrees per 100 foot build up rate (dogleg severity). It achieves this by the movement of two eccentric shafts relative to one another within the tool. These shafts are completely enclosed within a non-rotating stabilizer housing that maintains contact with the borehole wall and provides bit support. With this system the direction and inclination of the tool can be continuously adjusted as required, giving drillers a high level of control and maneuverability downhole.
The design philosophy is to make the tool as short and simple as possible to minimize potential failure mechanisms and hence deliver high reliability and lower drilling costs. The fully electric steering mechanism does not rely on externally moving pads or pistons. The tool also includes a unique sensor package that is located just behind the front stabilizer (and hence close to the bit), its own turbine generator, an innovative non-contact coupling for power and data transfer, and its own communications system that does not interfere with other Measurement-While-Drilling systems.
Three prototypes of the new RSS have been designed and tested so far. The first prototype (Prototype #A) successfully demonstrated 15 degrees per 100 foot dogleg severity capability. The second prototype (Prototype #B) was designed to evaluate the efficiency of the selected motor-gear design in moving the eccentric shafts when applying significant side loads. The third prototype (Prototype #C) was a complete rotary steerable tool that verified all aspects of the design, culminating in the drilling of directional holes in concrete blocks. This paper will describe the development of Prototype #C covering design, manufacture and the drill tests that verified the 15 degrees per 100 foot dogleg performance through concrete block drilling. The paper will also cover the subsequent design improvements made prior to manufacture of the field test prototypes (Prototype #D), and the planned environmental and endurance testing of Prototype #D prior to field testing. The field tests are planned for second quarter 2015.
Lubricants and Accelerated Test Methods for Expandable Tubular Application
Authors: Di Crescenzo Daniele , Shuster Mark , Petlyuk Alla , Ernens Dennis , Zijsling Djurre , Pasaribu Henry 
Published: March 2015

Tubular expansion for well construction is a process accomplished by pulling (or pushing) a mandrel through a pipe downhole. This can be described as a tribological system that consists of the pipe and mandrel surface, a lubricant layer and a fluid. A successful expansion requires a lubricant that, not only ensures manageable expansion forces, but also provides a robust solution for downhole application. The desired lubricant should separate the mandrel from the pipe during a downhole plastic deformation and be thermally stable, chemically compatible with drilling fluids and withstand a long shelf life in harsh environments.
This paper describes a process for optimal lubricant selection using accelerated testing with a dedicated setup that mimics demanding down hole conditions during expansion processes.
Three commercially available lubricants, commonly used in tubular expansion or other similarly demanding applications, and a novel solid lubricant, developed specifically for tubular expansion applications, were tested. The test campaign focused on the influence of drilling fluids and temperature on the friction, wear and lubrication efficiency.
The novel solid lubricant showed superior performance compared to conventional lubricants demonstrating lower friction factor with expansion forces between 13% and 49% lower than with conventional expandable tubular lubricants, outstanding resilience in coping with alien particles in the drilling fluid, ability to mitigate the onset of stick-slip phenomena and good corrosion protection for the expandable tubular. It was therefore selected and successfully used in field-trial applications.
The Drilling Optimization Benefits of Direct Drillstring Surface Measurements–Case Studies from Field Operations
Authors: Wylie Robert , Soukup Ian , Mata Henry , Cuff Sean , Ho Anthony 
Published: March 2015

Abstract
Correct information is crucial to drilling effectiveness and well construction success, with the greatest data accuracy achieved by measurement instruments applied as close as possible to the target load. Until recently, most drilling parameters were derived from load measurements taken on supporting structures or equipment related to the drillstring—but not actually a part of the string. The remote position of these classic sensors from the desired load often resulted in unacceptable error rates.
SPE/IADC 163475 proposed a direct measurement system, designed by integrating drilling instrumentation into a standard top drive internal blow out preventer (IBOP). The instrumented IBOP (IIBOP) makes direct-load measurements of drilling parameters along the drillstring—just below the main shaft of the top drive—thereby circumventing the errors of the traditional measurements. This provides the timely, directly measured data needed to characterize drillstring phenomena required for drilling and equipment optimization purposes, without the mechanical losses of the traveling system. The system's primary purpose is to provide early warning signs of system failure or well control situations and to enable better decision making with regards to well construction.
The previous paper presented examples of the data captured during initial field trials. Since that time, the sensor system has been run on multiple wells, achieving more than a year of cumulative data collected and analyzed by drilling experts. This paper reviews the extension, uptake, and applications of the technology, and presents case studies to demonstrate the use of direct drillstring data, with emphasis on lessons learned from high-speed data analysis for drillstring dynamics.
Initial results demonstrate that the improved measurements provide more accurate values for surface mechanical specific energy (MSE), which is used to optimize applied drilling parameters such as weight on bit (WOB) and top drive rotation speed in revolutions per minute (RPM) for increased rate of penetration (ROP) and reduced risk of equipment failures. Additionally, improved measurements permit better friction factor estimations for greater knowledge of torque and drag effects on the drilling process, allowing drillers to initiate remedial actions earlier, and safely deliver longer extended-reach wells. The system's high-speed torque data has been used to compare the makeup and breakout torque of individual drillpipe connections. It has also been used to indicate drilling dysfunctions such as stick-slip and improve the understanding of drillstring dynamics. Examples of drilling data will be presented, along with case histories illustrating how this technology improves real-time drilling operations.
Developing the Next Generation of Deepwater Drilling Rig: A Unique Collaboration in Design
Authors: Leary Michael J. , Rettie Stuart D. , Smidth Frederik 
Published: March 2015

Summary
BP and Maersk Drilling entered into a unique collaborative arrangement in early 2013 to develop the design for a deepwater drilling rig that is specifically aimed at conducting operations on wells with greater than 15,000 psi pressures. This paper describes how this collaborative effort was conducted. Operator and contractor each contributed expertise and information to the project and defined a joint vision of transforming how functional requirements are set and how the design of this rig would be developed. A set of relationship principles was agreed and a joint project team was formed in Houston with engineering support from contrator's technical organization in Copenhagen. An executive committee, with senior leadership from each organization, was established to provide guidance, challenge and governance. To start the design process, workflow during the well construction process was layered on top of the foundational requirements of operator's prospect inventory. Starting with a cleaner sheet of paper, the integrated team's conversations focused on inherently safer design and improving operability, efficiency, maintainability and reliability. The initial focus was on innovation and possibilities before driving toward agreement on the functional specification and rig design. The team strove to address challenges faced in the deepwater drilling industry today, at the same time continually testing their ideas for benefit. After more definition work, the opportunities were run through a detailed evaluation model to inform selection of design features and potential equipment suppliers.
Major equipment suppliers and operator service companies have assisted with the development of rig functional requirements and the shipyard specification. Operator and contractor contributed their learning from previous rig builds, intakes and operation including five and ten year re-certifications into the design. Supplier selection for long lead technology development and qualification of equipment commenced in 2013 and is expected to culminate with a yard selection in 2015.
As a result of this collaboration, operator and contractor better understand the needs and drivers of each other's business and have leveraged this knowledge into a more effective working relationship. Significant work remains to construct the rig and deliver it into operation. However, there is a strong belief this next generation deepwater drilling rig will provide enhanced capability, performance and value to both operator and contractor.
For Better or Worse: Applications of the Transfer Matrix Approach for Analyzing Axial and Torsional Vibration
Authors: Shor Roman J. , Dykstra Mark W. , Hoffmann Olivier J. , Coming Matthew 
Published: March 2015

Abstract
The response of the drilling system to axial and torsional vibration inputs has a significant impact on drilling performance. Usually the goal is to minimize dynamic response to limit the effects of potentially damaging phenomena in the low frequency range (e.g. bit bounce and torsional stick-slip) and high frequency range (e.g. axial chatter and torsional resonance). However, in some cases the goal is to maximize dynamic response, for example when introducing oscillation tools to overcome wellbore friction while directional drilling or to free stuck pipe. Whether the intention is to maximize or minimize, a suitable mathematical model is required. The model presented in this study uses the transfer matrix approach to predict how a harmonic vibration input propagates through the remainder of the drillstring. Novel features of the model include the ability to place the excitation source anywhere in the drillstring and to estimate damping effects due to Coulomb friction in directional wells.
Model inputs include drillstring and bottom hole assembly composition, well survey data, surface equipment and drilling parameters. Drillstring components are modeled as spring or beam elements and the surface equipment is modeled as a mass-spring system. Bit-formation interaction is modeled as a spring, the stiffness of which can be adjusted to provide a boundary condition ranging from fixed to free. Damping due to material hysteresis and interaction with the drilling fluid is modeled using a velocity-dependent term. Coulomb friction is modeled as an equivalent viscous damping coefficient. A harmonic excitation is specified at a given location in the drillstring and the responses at other locations in the system are computed via transfer matrices. This approach allows rapid characterization of the axial and torsional response of the drillstring in the frequency domain and may be applied to analyses of induced oscillation, such as from axial oscillation tools (AOTs), or unintended vibration, such as bit bounce.
Case studies show that predicted frequency responses in the axial and torsional domain compare favorably with high sampling rate downhole and surface measurements, respectively. Additional case studies demonstrate how the model has been successfully applied to diagnose and resolve severe axial vibrations while drilling with roller cone bits. Finally, model predictions are compared with downhole acceleration measurements to evaluate effectiveness of axial oscillation tools while drilling with steerable motor systems. Recommended practices for device placement and drillstring configuration are provided based on the findings from these studies.
Novel Workflows and Underreaming Measurements Reduce Risk by Supporting Decision Making
Authors: Rasheed Wajid , Thorogood John , Bernardini Jaime 
Published: March 2015

Abstract
This paper presents novel well construction work-flows and downhole measurements to improve the success rate with close tolerance casing and cementing operations. Drilling engineers routinely “flip the coin” and mentally take the risk of inferred underreaming. Considering the downtime that occurs across the industry such decisions are not sound. So why are they still taken? Routine decision-making shows a preference for riskier options even if safer options are available.
This paper details workflows and operational measurements that lead to safer and more efficient outcomes. The psychology of controlling risk in decision making is extensively discussed. A recommendation is made for a controlled workflow incorporating ‘gates’ to break routines. This supports the drilling engineer to consciously focus on a key operational gate that is a cause of downtime or operational risk. Critically, this ensures riskier decisions based on inferred underreaming are challenged and gated before sequential well construction activities occur. A further level of support is provided by new downhole measurements. Wellbore diameter is measured using callipers and the downhole status of the underreamer is tracked using magnetic position sensors. Preferential work-flows incorporate these measurements and consequently operations such as the following can be managed more effectively: Running casing/cementing. Check final underreamed wellbore diameter. This reduces the risk of casing getting stuck or an out-of-spec cement job.Underreaming across a section or a trouble zone subject to radial shrinkage or hard stringers. Check wellbore diameter and verify underreamer status. This can trigger a repeated cycle of expansion and check effective deployment of the cutters and the status of the cutters. If cutters have extended yet calliper is below gauge this can indicate a radially- shrinking formation with time or cutters worn or missing.Activating a near bit-reamer. Check wellbore diameter and verify underreamer status across the section to ensure satisfactory underreaming of the section. This ensures the rat-hole is enlarged only when the section is at the predetermined hole size or any remedial work has been completed. This reduces the risks associated with rat-hole enlargement.Activate a secondary redundant reamer. Check wellbore diameter and verify underreamer status. This saves a trip to replace a worn underreamer and avoids premature or unnecessary activation.If cutters are extended yet calliper data shows undergauge then the cutters are worn or missing. Operational parameters such as flow, torque, weight etc can also be monitored and correlated.
The paper concludes with a discussion and statistical analysis of risk factors that can be controlled using the work-flows and operational measurements.
Innovative Product Concepts and Drilling Practices Improve Bit and Reamer Performances in Harsh Drilling Environments
Authors: Mensa-Wilmot Graham , Gagneaux Jay , Woldtvedt Gust 
Published: March 2015

Abstract
Hole opening with bit and reamer, continues to receive attention in the drilling industry (Meyer-Heye, et al, 2010), due to the operation's numerous advantages. In comparison to conventional (single diameter) drilling, hole opening bottom hole assemblies (BHAs), are more complicated, in terms of their design and operation. The presence of two cutting tools, bit and reamer, in hole opening BHAs present additional drilling dynamics challenges (Heisig, et al, 1998). As a result of these issues, hole opening applications are commonly plagued by the following shortfalls – shorter BHA runs, excessive vibrations (Fear, et al, 1997), downhole tool failures, poor borehole quality, lower rate of penetration (ROP), and compromised directional performance (Mensa-Wilmot, et al 2014). These challenges, which have drastic negative effects on operational costs, amplify in harsh drilling environments (Mensa-Wilmot, et al, 2001).
The above issues must be addressed, to ensure cost trend reversals in hole opening applications. This objective requires solutions that focus on the challenges at their sources of initiation. Most important the solutions must ensure consistent and continuous gains in performance. This paper will present new concepts in hole opening, with regards to project analysis, planning, and execution. The discussions will identify and resolve specific hole opening challenges, with emphasis on harsh environment drilling applications. Field cases with supporting data, highlighting the impact of new solutions on project cost reductions, will also be presented.
Innovative Dual-Chamfer Edge Technology Leads to Performance Gains in PDC Bits
Authors: Izbinski Konrad , Patel Suresh G. , VanDeven Alex 
Published: March 2015

Abstract
The dual-chamfer diamond cutter is a new technology combining a primary chamfer with a secondary edge, enabling greater footage to be drilled without compromising rate of penetration (ROP). The average distance drilled in the Mississippi Lime formation was increased by 40% while maintaining comparable ROP to offsets and with significantly improved dull bit conditions, resulting in greater reliability. Since 2013, more than 1, 500 runs with bits utilizing dual-chamfer technology were performed in Oklahoma. The dull state was significantly improved, resulting in reduced incidence of ring outs, core outs and other deleterious bit damage.
The data presented in this paper are based on over 130 laboratory drilling tests. Chip flow analysis was conducted using a unique visual pressurized single-cutter test machine. Full-bit testing was carried out in a pressurized drilling simulator to compare drilling performance. Cutter wear life testing was conducted using an aggressive granite wear test protocol where a 100 to 200% increase in cutter life was documented by edge geometry changes.
Chamfering polycrystalline diamond compact (PDC) cutters has a significant positive effect on edge durability and overall longevity. This concept has not changed over several decades since the introduction of chamfered PDC cutters. Many investigations were conducted with either a singular change to the chamfer height or chamfer angle or with combined edge geometries. These investigations, however, showed only limited success.
The new geometry is based on a thorough understanding of historic investigations and failures observed on how diamond cutter wear flats are formed and degrade. Developments in the drilling sector with greater use of high-power directional motors results in more intermittent off-center drilling with high cutter edge loading. In addition, cutter developments now use leaching methods to reduce cutter wear and better control thermal cyclic loading. A leached diamond layer makes diamond cutters more susceptible to impact damage, resulting in greater premature and catastrophic failures.
For the customer, the improved cutter technology resulted in significant cost savings and more confidence in tool life, enabling greater endurance and durability. Ultimately, the new cutter technology enables lower drilling costs and opens more drilling frontiers that were previously unprofitable.
Achieving Zonal Isolation Using Three-Stage Cementing Systems (An Australian CSG First)
Authors: Zaman Mohammad , Ingram Colin , McLennan Rod , Watt Glenn 
Published: March 2015

Abstract
Regulatory requirements for Coal Seam Gas (CSG) wells in Queensland, Australia dictate that all surface casing strings must be cemented from shoe to surface and all aquifers must be isolated by casing and cement to ensure zonal isolation. A CSG operator drilled a well at an altitude of approximately 500 meters above sea level (m ASL). This altitude is considered high for the area and led to a hydrostatic overbalance across the exposed, permeable Precipice aquifer. The overbalance caused severe to total losses of drilling fluids during the drilling phase. A wide range of conventional lost circulation materials (LCM), light-weight cement formulations and two-stage cement operations were used to mitigate the lost circulation during cementing with limited success.
A three-stage cement job was designed for the 9 5/8 in. (244.5 mm) casing inside 12 1/4 in. (311.1 mm) drilled hole to bring cement around the shoe up to surface across the permeable formations. The casing program utilised 9 5/8 in. (244.5 mm) inflatable casing annulus packers, compatible hydraulic and mechanical stage tools and standard float equipment to create a cement base and cementing flow paths to perform the cementing operations.
This paper will present actual case histories where a three-stage cementing system has been deployed in CSG applications. Proper pre-job planning, detailed procedures and careful attention during on-site execution were key to the success of the multi-stage operation.
By providing a custom solution, the objectives of the operator, the regulatory agencies and the well contractors were met, where other conventional methods had not been successful. We understand this was the first time this application has been applied to Australian CSG wells.
Norg Wells: An Evolutionary Step in Pipe Shearing Technology
Authors: Horstketter R. , Egeraat S. van 
Published: March 2015

Abstract
The capability to produce 12 million m3/day of natural gas requires either multiple conventional wells or two large bore wells using 9-5/8 in. completions. Conventional wells can use a 13-5/8 in. 10, 000 psi BOP Stack. Large bore wells normally require an 18-3/4 in. 10, 000 psi BOP Stack, and a drilling rig of sufficient size to accommodate it. This results in a significant difference in cost per well between drilling conventional wells and drilling large bore wells.
In the summer of 2013, a 13-5/8 in. 10, 000 psi BOP shearing system was in development with tandem piston hydraulic actuators that can utilize up to 5, 000-psi hydraulic operating pressure, generating over one million pounds of shearing force, and shear rams designed for more efficient and robust shearing. A shear-only version of the system could be available in March 2014, provided that the system met the equirements for the Norg wells. For evaluation purposes, a shearing demonstration was conducted on the most challenging pipe sizes planned for the Norg wells.
The exercise demonstrated that the system is capable of meeting the pipe shearing requirements. Accordingly, well control protocols were developed based on the capabilities and limitations of the shear-only system. Through knowledge of the development of the new shear system, the operator was able to make use of the system in establishing the Norg gas storage and production wells. The operator was thus able to accomplish their goal with two large-bore wells instead of three smaller ones, at substantial cost savings.