bluuebunny/crossref_metadata_2025_split huggingface dataset:
Lateral Buckling – The Key to Lockup
Authors: Mitchell Robert F. , Weltzin Tore 
Published: March 2011

Abstract
Conventional wisdom suggests that buckled pipe first forms a plane buckled configuration, then transitions to a helical shape as the axial load increases. The helical configuration has been extensively studied using analytic solutions that allow calculation and analysis. Lateral buckling has received much less attention because no analytic solution exists for smooth pipe. Most conclusions about lateral buckling are just guesses. Tool joints have received some analysis, and buckling calculations, both lateral and helical, have been made for pipe with connectors, but these calculations have received little attention from the industry.
Buckling tests (Weltzin et al. 2009) were performed in the Ulrigg U2, a 2,020-m research well, with a buildup and 60° tangent geometry. These tests represent a major advance in the understanding of drillstring buckling. Although there have been many laboratory-scale studies and a few full-scale tests of limited value, this study is the first full-scale study to acquire a large amount of high-quality buckling-displacement data for analysis.
This paper presents the calculated drillstring positions for two loading tests performed in build and inclined sections of the Ulrigg U2 test well. Both tests were loaded until drillstring lockup. In both cases, lateral buckling was the primary buckling mode, with only a short interval in the build section tests showing actual helical buckling.
The results from the Ulrigg U2 tests show that: 1) connectors appeared to have primary importance in the buckling behavior of drillpipe, and 2) lateral buckling was the primary mode of behavior. These results, which were not expected, will require considerable revision of the conventional buckling models, with much more focus on the impact of connectors and a deeper understanding of lateral buckling. In particular, the analysis of casing running in extended reach horizontal wells will be significantly impacted.
Casing Design with Flowing Fluids
Authors: Mitchell Robert F. 
Published: March 2011

Abstract
Tubing forces and displacements have long been calculated for design purposes. Formulations, such as the Lubinski's buckling model, have the underlying assumption that the fluids are static. Adding the effects of fluid dynamics to the pipe force equilibrium problem is not as straight forward as one might think.
The key point is the loads generated by the fluid on the tubing. What information can we obtain from a simple balance of momentum of the fluid in bulk? For example, for flow inside a pipe, we can determine exactly the load exerted on the pipe by the flowing fluid in terms of only the fluid density, pressure, and momentum.
What might be the effect of fluid dynamics? Most papers have dealt with static fluids, but how are these static effects modified for a flowing fluid? Do we need to add a pressure gradient to the pipe buoyancy? How is fluid friction included in the pipe loading? How does fluid momentum affect the pipe? For curved pipes, we might expect a centrifugal force term. The answers to these questions are often surprising, even counter-intuitive.
In this paper, the general equations for the balance of fluid momentum are then combined with the equilibrium equation for the pipe. The effective force then emerges as a natural combination of pipe force and fluid-force terms. Pipe displacement is usually formulated in terms of the actual axial force, but the necessary modifications to this formulation are presented for the effective force.
Mitigating Stick-Slip in Deep Drilling Based on Optimization of PDC Bit Design
Authors: Pelfrene G. , Sellami H. , Gerbaud L. 
Published: March 2011

Abstract
Deep-hole drillstring vibrations are an important cause of premature failure of drillstring components and drilling inefficiency. PDC bits are more susceptible to the stick-slip phenomenon characterized by intense RPM fluctuations of the drill bit. Based on full scale laboratory drilling tests and numerical simulations, this paper aims at understanding the dynamic behaviour of the bit/rock interaction and assessing how stick-slip depends on bit design (bit profile and diameter; cutters geometry and set up). It is generally assumed in the scientific and technical literature that forces acting on PDC cutters do not depend on cutter velocity. However, an extensive single cutter experimental program shows that these forces are rate-dependent for four tested carbonate rocks. This rate-effect is associated with the dynamic shearing of a layer of crushed rock carried away beneath the moving cutter. Based on these experiments, a semi-empirical rate-dependent cutter-rock interaction model is developed, implemented in a bit design software and used to predict the velocity signature of various PDC bit designs. These predictions fit well with numerous experimental results obtained using a full scale drilling bench. In particular, the model accounts for the negative damping effect, considered as the main source of stick-slip, and for important operational trends like an increasing risk of stick-slip in harder rocks, at higher weights-on-bit or for advanced cutter wear. The bit-rock interaction model is used as the boundary condition of a drillstring vibration software designed to perform a time-domain analysis of lumped systems. Simulations show that the bit design significantly impacts the risk of stick-slip. As a result, general optimization guidelines are suggested in order to improve PDC bit design.
Fluid Hammer Drives Down Well Costs
Authors: Staysko Robert , Francis Brenda , Cote Brad 
Published: March 2011

Abstract
An innovative proven new tool, the "Fluid Hammer", provides axial percussive force and effective weight transfer to the bit which increases the rate of penetration (ROP) from 30-50% with no impact to bit life.
BBJ Tool's patent pending Fluid Hammer together with Suncor Energy Inc. of Calgary, Alberta, Canada has applied the Fluid Hammer in several wellbores with excellent results. The tool is positioned between the bit and the mud motor with an antiback off connection. The relatively simple mechanical design delivers effective agitation to the bottomhole assembly (BHA) and reduces issues in deviated wellbores, such as hole drag and proper weight transfer to the bit. It has been successful in improving ROP in vertical/deviated and horizontal hole sections.
The Fluid Hammer has been successful on &gt;80 bit runs in vertical/deviated/horizontal wellbores with water, oil base and nitrified drilling fluid systems. Direct comparisons of formations with and without the Fluid Hammer have been completed. The study compares geological formations, compressive rock strength, mud weight and BHA parameters such as weight on bit, rpm, hole drag and ROP. Resulting sliding ROP matches rotating ROP in horizontal wellbores with the downhole agitation at the bit. Tool design improvements will be further enhanced with the use of an Axial Dynamic Simulator.
The Fluid Hammer increases ROP, has no effect on telemetry tools, causes no restriction to pump rate and can be used with any mud system. This tool can be run in conjunction with conventional adjustable housings or rotary steerable tools. No special percussion bits are required and it has been run with a wide variety of conventional bit types and sizes. An additional feature of the Fluid Hammer has been in extended reach horizontal hole sections in which the BHA has been simplified with the removal of conventional agitation tools.
Automation of the Drilling Fluid Mixing Process, Field Experiences and Development from North Sea Operations
Authors: Kvame Ove , Blom-Jensen Bjarne , Bastesen Yngve , Sandvik Jan Erik 
Published: March 2011

Abstract
There has been substantial development over the past years with respect to automation of drilling equipment and operations on the drill floor, and this trend is projected to increase over the coming years. Automation in bulk transfer and in the drilling fluid mixing process has also been and is continuing to be developed, but may not have received worldwide recognition yet. Indications from operators show there is a rising interest in developing this area and focusing on total integration of auto- mated drilling systems.
This paper will summarize the initial development and field performance feedback from several years of operating at different automated levels of bulk transfer and the drilling fluid mixing process, respective of rigs operating in the Norwegian sector of the North Sea. It will address systems from semi-automated sack cutting units to fully automated drilling fluid process systems which are able to automatically mix drilling fluid according to a preset recipe from the mud engineer. Examples of existing applications on typical North Sea rigs are the automatic mud and bulk transfer systems and automatic mud density regulation systems.
Initial field findings are the automation of the drilling fluid mixing process achieves: Improvements to HSE issues including personnel, equipment, and operationIncreased efficiency (reduced mixing time, more efficient use of resources)Improved drilling fluid quality and repeatable processes
This paper also includes thoughts for future implementations with respect to taking the automation of the mixing of drilling fluids process further, for instance employing an automated viscosity regulation system or even allowing the mixing process to be automatically controlled by well conditions.
On Interaction Buckling in Platform Conductors
Authors: Adams A. J. 
Published: March 2011

Abstract
For over thirty years, the design of platform and jack-up conductors has been based on Stahl and Baurs' famous hypothesis that internal string loads do not contribute to buckling (Stahl and Baur 1980). It is a vital result, allowing significant weight and cost savings. However, no derivation was ever given, and the result has remained a folk theorem: widely used, but never proved. The industry has therefore been at risk should the result prove to be a severe approximation, or to have unduly restrictive assumptions and/or limitations. This paper provides a rigorous proof of the hypothesis. It shows that it is an approximation, albeit an acceptable one, and gives a thorough exposition of its meaning, assumptions and limitations. Finally, it derives the exact counterpart of Stahl and Baurs' result. The improved result gives further minor weight and cost savings.
Analytical and Experimental Backward Whirl Simulations for Rotary Steerable Bottom Hole Assemblies
Authors: Stroud D. R. , Lines L. A. , Minett-Smith D. J. 
Published: March 2011

Abstract
A unique analytical model has been developed to predict dynamic behaviour of the drilling assembly and gain a better understanding of the dominant factors that cause backward whirl. A full-scale test rig has been constructed that is capable of initiating and sustaining full rolling contact backward whirl, repeatably, reliably and safely. Excellent correlation between these near real time analytical simulations and full-scale experimental results has been achieved giving confidence in using the model for serious predictive analysis of system response in real down-hole drilling conditions. This uniquely verified analytical model can be used for rapid iterative analysis to help generate and evaluate potential design improvements and whirl mitigation strategies.
These simulations have been focused on a latest generation point-the-bit rotary steerable system (Figure 1 shows the general arrangement of the steering system), but the principles can likely be applied to other rotary drilling assemblies.
Figure 1 Schematic diagram of a point-the-bit rotary steerable system
In the process of validating the analytical model, some interesting observations were made. The first being the appearance of a ‘partial whirl’ or transition phase preceeding full backward whirl in most cases. The large impact loads predicted by the analytical model over the partial whirl phase correlated with those experienced in full-scale testing and could explain the large lateral vibrations experienced in the field during supposed episodes of backward whirl. The parameters affecting both the length of the partial whirl period and the magnitude of the impacts were found, leading the way for preventative measures. The second finding, and possibly the most instantly useful, was that full backwards whirl could not occur in close to gauge hole unless the friction coefficient between the borehole and the drilling assembly was increased dramatically. This would indicate that devices and procedures aimed at maintaining good hole quality could be effective measures to prevent backward whirl.
Improvements to the analytical model have been suggested but even in its current form it has proved an extremely versatile and reliable tool. Now that both the simulated motion and predictive capabilities of the analytical model have been proven, future technical papers will explore the effect of drilling parameters in more depth and will attempt to provide whirl mitigation strategies for field use.
"Understanding XLOTs"
Authors: Heger Alexander , Spoerker Hermann F. 
Published: March 2011

Abstract
Leak-off Tests (LOTs) are a common procedure during the drilling process and have been performed for decades. Still the pressure vs. volume curve seems to be not fully understood, and slightly different explanation theories exist. The paper discusses these theories together with the commonly applied leak-off testing procedure and attempts to explain the curve from a stress calculation standpoint. Theories are presented about fracture initiation at the wellbore wall, SH determination from extended leak-off tests (XLOTs) and the change of the pressure vs. volume curve by repeating pressure cycles.
Industry estimates put the contribution of wellbore stability to non-productive time at approximately 40%, costing the industry approximately $8 billion dollars per year1. In addition wells are becoming more and more difficult to drill as complex trajectories are required and smaller drilling margins are encountered to discover new oil and gas deposits.
The authors advocate that fundamental understanding of geomechanic principles by all the engineers involved is required to efficiently and successfully drill complex wells. Better understanding of and familiarity with these phenomena will minimize inappropriate decisions which might cause down time or even a loss of the well.
Challenges Of Drilling In The Chilean Altiplano
Authors: De Angelis Roberto , Holdeman Matthew , Pidcock Gary , Levy Warren , Figueroa Horacio , Lyon Raul 
Published: March 2011

Abstract
Recent interest in Chile to develop renewable energy sources has created a new market for drilling contractors with geothermal well experience. The geothermal fields in Chile are unique in that they combine the issues of remote area drilling with additional challenges such as desert conditions, cold weather, deep snow, and, most importantly, high elevations. Over 50% of the geothermal concessions in Chile are located in the northern regions at elevations from 3500 meters to 5000 meters. These altitudes are the normal environment of mountaineers, not drilling rigs, with oxygen levels reduced between 35% and 50% compared with sea level.
Effects of altitude, geography and climate must be taken into account in the overall planning of a drilling operation. The effects on personnel can vary and are somewhat unpredictable. There are specific tests that must be performed before working at high elevation that can detect potential problems and there are mitigation methods that can be applied on site that can help personnel increase their performance.
Equipment is also affected by the high elevation and the climate. The lack of oxygen at elevations over 4000 meters results in a loss of power for internal combustion engines of more than 40%. This is exacerbated by the limited experience operating large drilling equipment at high altitudes. The contractor must overcome these power limitations not only for the drilling rig but also for all associated services for the operation using engines.
Overcoming these challenges can only be achieved through careful planning at all stages of the operation and by selecting specific technologies to mitigate the effects of the environment in the operations. In this contractor's experience, the use of mechanized pipe handling equipment and the minimization of internal combustion engines brought the biggest value to the operation.
Maximizing Core Recovery in Lower Tertiary Through Drilling Optimization Service and Intelligent Core Bit Design
Authors: Guarisco Peter , Meyer James , Mathur Rohit , Thomson Ian , Robichaux Jeremy , Young Clifford , Luna Edgar 
Published: March 2011

Abstract
The deepwater Gulf of Mexico (GoM) Lower Tertiary Wilcox group is still considered an area with many geological uncertainties. In this geological environment, core samples are crucial for geologists, geoscientists, and reservoir engineers to better understand and characterize the reservoir.
This paper will focus on the longest 12 ¼-in. coring application in a deepwater Gulf of Mexico lower tertiary well. A total of 360 ft of lower tertiary Wilcox sand was cored and recovered in a single run. 12 ¼-in. core barrels were assembled for this application along with a fit-for-purpose 12 ¼-in. core bit equipped with abrasion-resistant polycrystalline diamond compact (PDC) cutters and an integral stabilization sleeve for better bit and bottomhole assembly (BHA) stabilization throughout the operation. Extensive preplanning was done in order to ensure flawless execution in this challenging environment.
In deepwater coring operations, maintaining weight on bit (WOB) is crucial for good results. Lack of rig compensation and heavy rig heave can be a disastrous combination. Bit bounce associated with high rig heave and core barrel jamming are some of the hazards of having insufficient weight reaching the core bit, which leads to increased nonproductive time (NPT). In order to have better control of the downhole drilling parameters, such as downhole weight on bit, torque and vibration, a comprehensive drilling mechanics and dynamics measurement tool was placed on top of the core barrel. The benefit of implementing this tool is the ability to optimize the coring parameters in real time in order to maximize core recovery.
Additionally, the section was drilled using a constant rheology drilling fluid, and hydraulics simulations were performed to guarantee equivalent circulating density (ECD) management, optimized hole cleaning and reduced operational risks. Geomechanical modeling included fracture characterization analysis to select the proper particle size distribution for bridging and wellbore strengthening formulations.
The planning and collaboration between the service company and the operator, in a multidisciplinary team, was the key for the accomplishment of this record run. The record run eliminated two extra coring runs (the standard coring application in the Gulf of Mexico is 120 ft), accounting for significant reduction in operational cost.
Cutting the Cost of HP/HT Cleanups: Novel High Density Cleanup Package Enables Brine Reclamation and Reduces Costs
Authors: Richmond Michael , Hutton Alistair , Davidson Marcus , Howard Siv , Frost Bob , Leon Stuart , Jaspars Marcel 
Published: March 2011

Abstract
With the passing of "easy oil," the need for high-pressure, high-temperature (HP/HT) drilling and completion fluids has increased. This has, in turn, increased the need for sufficiently robust cleanup methodology. This requirement for high density, solids free cleanup fluids drove the investigation into the use of cesium formate as the base brine. The use of cesium formate brings unique challenges to the cleanup, most notably, the cost implications. The high price of cesium formate brine means that any losses could severely impact upon the cost of the cleanup operation. Furthermore, any brine used in cleanup pills that could not be recovered for re-use would have to be considered as lost. It was, therefore, imperative to return the brine to its original condition, thereby avoiding the need to dispose of a very expensive commodity. This paper will look at the laboratory testing surrounding the development of a high density cleanup fluid (HDCUF) and the ability to remove the contamination from the brine to bring it back to an acceptable condition.
The cleanup spacers were made up with cesium formate brine and several approaches to remove the contamination were investigated. Contamination was from both the chemicals used to formulate the cleanup spacer and from the oil based drilling fluid that would be used to drill the wells. Nuclear Magnetic Resonance (NMR) Spectroscopy was used to measure the level of contamination in the brine.
The results of the study showed that, using the method selected, it was possible to remove the cleanup chemicals to an acceptable level where the cesium formate brine was able to be re-used. This would enable the operator to recover the brine and avoid the significant costs from losing the volume and disposing of the waste.
Surface Hole Casing While Drilling (CwD); A Review of 5 Years Experience in Gabon, West Africa
Authors: Askew B. , Phillips A. , Wingate J. H. 
Published: March 2011

Abstract
This paper will document the experiences (both positive and negative) of surface hole Casing while Drilling (CwD) in onshore Gabon, West Africa over a 5 year period. Modifications and improvements to the CwD shoe will also be discussed as well as the Health and Safety benefits of the system.
The CwD system is a simple non-retrievable premium Polycrystalline Diamond Compact (PDC) bit mounted on the end of a casing string. The string is rotated at surface by means of a rudimentary drive-sub (water bushing). This technique requires no modifications to a standard drilling rig. The CwD bit can be drilled-out with a standard rock bit or a specialized PDC bit. CwD technology also lends itself to mitigating drilling hazards associated with drilling surface hole in Gabon. The surface hole geology consists of unconsolidated sands overlying fractured hard carbonates. CwD allows this interval to be drilled and cased simultaneously and provides health and safety benefits associated with eliminating tripping of conventional drill strings.
Since 2005 a total of 50 wells in Gabon have been drilled using CwD technology. Some of the performance highlights include; a cumulative distance drilled of 8,410m (27,593 ft), average run length is 172m (564 ft) with an average penetration rate of 6.75 m/hr (22.1 ft/hr). The average time to drill one joint of casing is 56 minutes.
As performance targets increase drilling further and faster will mean improvements to the current bit designs. The recommended bit changes include; diamond volume management, changes to cutter size to improve point loading and change to cutter type to improve durability and impact resistance. Changes to the current well designs are required before the addition of sophisticated casing drive systems to speed up connection times and minimize off-bottom drilling time become economic.
The trend is for more surface hole to be drilled using CwD techniques in Gabon and other West African countries. This technology is also readily transferable to offshore shallow water applications.