bluuebunny/crossref_metadata_2025_split huggingface dataset:
Elastic Pipe Control and Compensation for Managed Pressure Drilling Under Sea Wave Heave Conditions
Authors: Samuel Robello , Lovorn Randy 
Published: March 2015

Abstract
Managed pressure drilling (MPD) was developed as a group of technologies to more precisely control the annular pressure profile for which accuracy of the estimation of the bottomhole pressure is important. Particularly, under severe wave heaves in deepwater environments, the estimation based on static state pipe movement models can result in underestimation/overestimation of bottomhole pressures. The purpose of this study is to investigate the dynamic axial response of the drillstring with friction to applied heaving velocity, with particular interest to the effect at the bottomhole pressure.
The paper presents an efficient and accurate method for solving the dynamic axial drillstring with friction and it allows it to be applied to heave velocity at surface. The model that couples the pipe motion solves the full balance of mass and balance of momentum for pipe and annulus flow, considering the compressibility of the fluids, the elasticity of the system, and the dynamic motions of pipes and fluids. Also considered are surge pressures related to fluid column length below the moving pipe, compressibility of the formation, and axial elasticity of the moving string. Fluid properties are adjusted to reflect the effects of pressure and temperature on the fluids. The modeling takes into account the pipe elasticity under different combinations of heave and pipe velocities. Furthermore, the real-time torque and drag models are calibrated to actual hole conditions in real-time using survey, temperature, pressure, and downhole tool data to calculate friction factors in a wellbore.
It has been observed that different conditions exist, some resulting in velocity reversal, thus causing surge or swab pressures. It has also been observed that heave amplitude has significant influence on bottomhole pressure. The different conditions observed for periodic or time function of displacements include: Surface pipe velocity attributed to wave heave is in phase with the bottom movement of the string.Surface velocity of the pipe is out of phase with the bottom velocity of the pipe.Wave velocity and surface pipe velocity can be out of sync, and the bottom pipe velocity can be in phase with the surface velocity.Wave velocity and surface pipe velocity can be out of sync, and the bottom pipe velocity can be out of phase with the surface velocity.
The results of these calculations can be coupled to a real-time hydraulics model to determine a setpoint pressure for the MPD choke system.
Historical Advances in Drill Pipe Internal Coating Systems and the Performance of Liquid versus Powder Applied Coating Systems
Authors: Lauer Robert S. 
Published: March 2015

Abstract
As one scans the market today, it is noted that the vast majority of drill pipe is internally coated with a polymeric coating system. One also notes that completion pipe, landing strings, etc are increasingly utilizing internal coating technology to provide corrosion, hydraulic and scale mitigating benefits. Transitioning from simple drilling operations in the 1950’s to the ability to withstand drilling, fracing, cementing, gravel packing, acidizing, and mechanical intervention at high temperatures and pressures. There has been a transition in technology from those very early coating systems to the newest technology available today. Several milestones define the technological advances in internal coating capabilities.
Initial versions of these drilling coating systems utilized a liquid applied epoxy phenolic coating systems. As the industry developed, there became a need for a powder version of the traditional drill pipe coating systems. From there, the market showed a need for a more abrasion resistant system to handle not only drilling applications, but also completion operations. A third era was ushered in with this new abrasion resistant technology, but transitioned back from a powder application to a liquid application due to the market experienced performance benefits of a liquid applied material. We now stand in a new era of coating technology in the drilling and completion market. While still focusing on a liquid applied material, the traditional epoxy phenolic is being left behind. This new coating utilizes a high temperature, multi-functional epoxy resin as its backbone. This system also deviates from the norm in that specialized additives are used to improve characteristics such as coating toughness and flexibility. Historically, the use of additives would reduce the final glass transition of the coating system, reducing its overall performance in a given environment. These new additive systems in conjunction with this multi-functional epoxy allow for them to be used in concert without reducing the glass transition temperature. This new system increases the chemical resistance over traditional liquid applied systems, doubles the flexibility over other industry available systems, exhibits greater performance at temperature over traditional coating systems, and now possesses the most abrasion resistance available in the market.
Defining Design and Optimization Method: Dynamic Simulation Model Produces Integrated BHA Solutions for Efficient Wellbore Delivery
Authors: Chen Wei , Shen Yuelin , Harmer Richard , Rawlins Sheldon , Dong Yani , Chen Rongbing 
Published: March 2015

Abstract
In difficult drilling environments, a critical aspect for success is BHA design optimization in the pre-job phase. In previous operations, modeling and run simulations have proven valuable at helping operators improve drilling efficiency (reduce NPT; increase footage/day), produce high-quality log data and properly position the wellbore to increase contact with the reservoir. To further improve modeling accuracy/reliability, a dynamic modeling system was used for BHA analysis. The FEA (finite element analysis)-based system enables engineers to leverage the team's combined expertise and full suite of drilling tools to optimize a BHA for a specific application.
Four criteria are used to evaluate BHA performance during simulations: stability; robustness/reliability; measurement quality; steerability. Simulations are run to determine each configuration's potential for axial, lateral/torsional vibration and identify the root cause and dominant mode. To ensure maximum BHA robustness, the loading on BHA components is mapped/rated allowing refinements to increase BHA service life and reduce the potential for costly NPT. Simulations are run to observe the potential for MWD/LWD tool deformation and sag angle to determine the adverse effect sensor motion could have on measurement quality. To mitigate steerability issues, build/walk tendencies are simulated to determine how the BHA will respond to steering command from RSS/PDM.
A wide-range of factors can be considered in this procedure. Various cutting structures and steering tools are analyzed and modified as required. The type and location of BHA components are also modeled and re-positioned for optimization purposes. Various drilling scenarios and operating parameters are fed into the system including RPM/WOB, sliding/rotating time, back-reaming and rotating off bottom. Formation characteristics including rock types, friction factor, heterogeneity/homogeneity, degree/amount of interbedding can all be varied to investigate the BHA's corresponding directional implications and vibrational response.
All potential BHA designs are evaluated under a set of pre-defined drilling scenarios. A comparative analysis is performed to investigate BHA responses against each specific criterion to identify the optimum BHA configuration. Operating conditions are analyzed for each BHA and an optimal parameter window of minimized BHA shock and vibration is generated with a range of RPM/WOB recommendations. The authors will present several conclusive case studies that document the method's effectiveness and cost reducing capabilities.
MPC-Based Feedback Delay Compensation Scheme for Directional Drilling Attitude Control
Authors: Bayliss Martin , Bogath Chris , Whidborne James 
Published: March 2015

Abstract
For practical engineering reasons, the attitude control of directional drilling tools is subject to significant temporal feedback delays, which reduce the performance and stability of these algorithms. This paper details the modification of an existing attitude tracking algorithm to use a model predictive control (MPC) scheme incorporating a state-space plant model augmented with pure delays on the state variables. Provided with an estimate of the temporal feedback delay and other plant model parameters, the MPC scheme is able to mitigate for the effects of the feedback delay. Additionally, feedback loops designed by pole placement are added to the core MPC scheme to identify disturbances to the plant, which cannot be measured directly on line. The paper details the algorithm and gives results from a transient simulation-based on the stated scheme.
Drilling Systems Automation Roadmap - The Means to Accelerate Adoption
Authors: de Wardt John P , Macpherson John D , Zamora Mario , Dow Blaine , Hbaieb Slim , Macmillan Robin A , Laing Moray L , DiFiore Amanda M , Inabinett Calvin E , Anderson Mark W 
Published: March 2015

Abstract
The Drilling Systems Automation Roadmap (DSA-R) initiative is a cross-industry effort launched in June 2013 to help accelerate the adoption of advancements in drilling systems automation for both onshore and offshore wells. When completed, this technology roadmap will provide the drilling industry with a well-defined guide on the expected development and adoption of drilling systems automation technology in the near and long terms. The focus on needs, vision, scope, and boundaries will enable development of solutions to implement Drilling Systems Automation (DSA) in a manner that effectively improves performance, reduces well costs, removes people from high-risk operations, and promotes general drilling safety, among other key goals. To enhance consensus, the DSA-R initiative decided to affiliate with the SPE, IADC and the Association for Unmanned Vehicle Systems International (AUVSI).
This technology roadmap uses the well-known template developed by Sandia National Laboratories to provide a mechanism to forecast how DSA developments can progress, and to provide a framework to coordinate among disparate players. The process also will enable players outside of the oil and gas industry to envision how to participate and contribute to the implementation and advancement of DSA.
From the onset, the roadmap was segmented into eight key challenges, each individually defined in terms of functional description, performance targets, current status, problem statement, and development to meet the vision. The eight challenges are (1) Systems Architecture, (2) Communications, (3) Instrumentation and Measurement Systems, (4) Drilling Machines and Equipment, (5) Control Systems, (6) Simulation Systems and Modeling, (7) Human Systems Integration, and (8) Certification and Standards. Interdisciplinary challenge teams formed by subject-matter experts from both inside and outside the oil and gas industry are developing the maps for the challenges. The interdependencies and related interfaces among the challenges are being coordinated through the committee to ensure consistency of approach and timelines.
The purpose of this paper is to describe the launch of the DSA technology roadmap initiative, the processes being applied and key details on the status of each of the challenges. All roadmaps are invariably long-term projects, but the sharing of information at this critical stage is important to encourage wide industry involvement and participation to accelerate the implementation of automation in drilling.
First Time Drilling With Steerable Drilling Liner from Semi-Submersible
Authors: Noordoven Q. , Grindhaug G. , Eidem M. , Spreckelmeyer N. 
Published: March 2015

Abstract
Using Steerable Drilling Liner to drill through an unstable formation has been a proven solution from fixed installations where this technology greatly increases the chance of successfully drilling a wellbore and landing a liner at planned depth. The key to the increased performance are the reduced open hole time, mechanical impact on formation and pressure fluctuation in the well.
In previous subsea wells on the Vigdis field on the Norwegian Continental Shelf, stability problems have led to setting the liner prematurely, resulting in loss of production. The stability problems seen in the offset wells have been time dependant, with few difficulties experienced during drilling. However, when running the liner afterwards, pack-offs, shallow setting of liners and problems with cementing have occurred.
The Steerable Drilling Liner solution was selected to prevent initiation of instability while drilling the reservoir and in addition to ensure the section could be secured with the liner in place before formation instability problems occur.
The implementation of the Steerable Drilling Liner enabled drilling of a nearly horizontal section with several unstable palaeosol intervals without any stability related problems, hence meeting the objective of reaching a challenging target. It has been concluded that the section would have been difficult to drill with conventional methods.
In contrast to previous Steerable Drilling Liner utilization, this well was drilled from a semi-submersible rig in rough weather conditions. These harsh conditions in the North Sea demanded high attention with respect to drilling practices and well control which had to be addressed accordingly.
In the following, the planning and execution phase, leading up to the successful drilling operation from a floating installation will be described. The paper will also touch upon some improvements for further use of the Steerable Drilling Liner technology.
Axial Oscillation Tools vs. Lateral Vibration Tools for Friction Reduction – What's the Best Way to Shake the Pipe?
Authors: Gee R. , Hanley C. , Hussain R. , Canuel L. , Martinez J. 
Published: March 2015

Abstract
There are many benefits to reducing friction along the drill string while drilling directional wells. Higher rates of penetration (ROP), improved tool-face control, reduced drag, and reduced stick/slip are only some of the benefits documented in previous technical papers. There are generally two types of downhole tools used to generate benign vibrations within the drill string and/or bottom-hole assembly (BHA) to reduce friction: axial oscillation tools (AOTs) and lateral vibration tools (LVTs).
This paper reviews the benefits and drawbacks of each of these types of tools and presents the results of mathematical modeling and field data to conclude which type of tool is more effective at reducing friction in horizontal wells.
Axial oscillation tools typically employ a valve driven by the mud flow to generate pressure pulses. A shock tool is run above or incorporated into the AOT to convert these pressure pulses into an axial oscillating motion. This motion travels up and down the drill string to reduce friction between the pipe and the borehole wall.
Lateral Vibration Tools (LVTs) typically employ one or more eccentric rotating masses driven by the mud flow. This creates a vibration in the lateral direction, perpendicular to the long axis of the tool, creating motion between the tool and the borehole wall and thereby reducing friction.
To investigate the potential benefits of each type of tool, a mathematical model of a BHA and drill string was created and, using finite element methods, the friction reduction effect (in terms of drag reduction) was compared between the AOT and LVT.
In each scenario evaluated in the study, a benchmark calculation was first made with no oscillation. Then, the oscillation for each tool was applied and the response of the system evaluated with respect to the improvement in weight transfer along the drill string. Afterwards, the results were compared to an actual case study for verification.
The research concludes that axial oscillation tools provide significantly more effective friction reduction, which enhances drilling performance in horizontal wells. The paper also provides several additional examples of comparative field results.
Drilling Performance: Efficient Integration of the Entire Drilling System
Authors: Greenwood Jeremy A. 
Published: March 2015

Abstract
Every basis of design and the required configuration of the rig, drilling equipment, and services undergo a series of iterations to balance requirements and resolve conflicting approaches. Effective design and subsequent optimization of a drilling plan requires the interaction of many different technical specializations in different organizations to meet the overall well objectives. To achieve maximum operational and economic performance, these diverse and specialized disciplines must interact effectively and efficiently in the fewest number of iterations. An essential requirement for this interaction is a clearly defined process that allows everyone involved in design and execution to be aware of both the requirements and objectives for the well and also those of other team members. Most importantly, knowledge of where the connections or touch points exist between the different domains is essential so that the implications of a change to the system can be rapidly assessed by the entire engineering team and service providers to help ensure the overall goals are met. The approach is novel within the industry because of the scope of the workflow, which encompasses all engineering relationships while drilling the well; whereas previous work tended to focus more on optimizing real-time behavior to respond to conditions encountered, using reservoir simulators to plan developments, or has been limited to collaboration between only two or three disciplines (Brett et al. 1986; Adeleye et al. 2004).
Overcoming Complex Geosteering Challenges in the Cardium Reservoir of the Foothills of Canada to Increase Production Using an Instrumented Mud Motor with Near Bit Azimuthal Gamma Ray and Inclination
Authors: Suh Asong , Bradley James , Feltham Greg 
Published: March 2015

Abstract
The Cardium Formation is a conventional sandstone reservoir in the Western Canadian Sedimentary Basin. The Cardium Formation is currently at a phase of exploitation requiring long horizontal penetrations and large-scale, multi-stage, fracture stimulation to ensure productivity. In the Canadian Foothills, the Cardium is complexly deformed and naturally fractured. Correctly placed horizontal wellbores take advantage of these natural fracture systems which create permeability pathways resulting in extremely prolific wells. To maximize production and effective reservoir drainage, horizontal wellbores need to be drilled to intersect multiple natural fracture networks within the deformed Cardium reservoir. Sub-seismic scale folds and faults result in rapid changes in reservoir bedding orientation and/or position which requires sensitive geosteering responsiveness in order to create an optimal reservoir penetration.
The Cardium reservoir exhibits good gamma contrast and predictable character. Therefore, gamma ray has been shown to be an effective tool for geosteering. An innovative instrumented mud motor that provides azimuthal gamma ray and continuous inclination 2.7m from the bit was used for successfully geosteering several wells, and has proven to be a vital component in the horizontal drilling process. For example, a common geological scenario can result in a 5° change in apparent bedding orientation relative to the wellbore resulting in the wellbore exiting the reservoir. Reservoir re-entry can occur as quickly as 30.5m when using the instrumented mud motor compared to 56.4m when using a conventional gamma sensor positioned 15.2m behind the bit. The instrumented mud motor works by wirelessly transmitting the azimuthal gamma ray and continuous inclination measurements via short hop communication to the MWD (Measurement While Drilling) system from where it is transmitted to the surface realtime.
This paper describes the complex Cardium reservoir in the Canadian Foothills and presents the unique challenges faced when attempting to geosteer and optimize wellbore positioning within the reservoir. We review the near bit instrumented mud motor and discuss the workflow of how data was used from the instrumented mud motor to help with geosteering the well. Finally, we compare the results from several wells drilled using the instrumented mud motor to those drilled using a standard MWD gamma located 15.2m behind the motor. The use of the instrumented mud motor with near bit azimuthal gamma ray and continuous inclination proved to be a successful geosteering tool in one of the most complex environments of the Western Canadian Sedimentary Basin. Additional footage in zone and increased production in this complex geological environment displays the tool's capibilities and the benefits it could provide to other areas of the basin.
Recent Advances in Soft Torque Rotary Systems
Authors: Dwars Sicco 
Published: March 2015

Abstract
Many rigs have STRS, the Soft Torque Rotary System, also known in the drilling industry as SoftSpeed, EPST or RevIT. STRS expands the stick-slip free drilling envelope. Weight on bit can go up, RPM can go down. Rate of penetration goes up. Whenever STRS is in use, the frequency of tripping a drill string out and back into the hole reduces. That's because it reduces the likelihood of prematurely worn bits, for twist offs, back offs or for damaged down hole tools. From the vast amount of operational data collected by mandatory 24/7 high speed top drive torque and speed recorders, we learnt that the now mature technology could still be further improved. This paper outlines the Z-Torque approach, a novel SoftTorque controller that expands stick-slip free operating envelopes and greatly simplifies tool operation. Author of this paper is an electronics engineer, approaching the stick-slip challenge from an unusual perspective: aim to cure stick-slip vibrations with the same tools and tricks as traditionally used in high frequency printed circuit board design, in telephone lines, TV antenna coax cables, fiber optics, in seismic, and the likes.