bluuebunny/crossref_metadata_2025_split huggingface dataset:
Blowout Control Challenges of Pad Drilling and Production: A Case History with Lessons Learned
Authors: Haghshenas A. , Cuthbert A. , Portillo L. 
Published: March 2017

Abstract
Efforts to help reduce environmental footprint, infrastructure, and development costs have led to an increased use of pad drilling. However, the close proximity of wells in pad drilling increases the risk of more severe consequences during well control incidents. In the case of a burning well, both radiant and direct heat can potentially ignite adjacent wells, possibly threatening both human life and equipment and detrimentally affecting the immediate environment. This paper describes challenges and lessons learned from controlling a multiwell pad blowout.
A series of six wells with 15 ft spacing was drilled on a pad. Each well was completed with multistage hydraulic fractures; however, during flowback operations, a well developed a leak through a flowback line connection. The gas exiting the well eventually ignited, and the heat from the fire damaged the seals and wellhead equipment on neighboring wells, causing all of the wells on the pad to develop leaks, which consequently caught fire. Successful well kill operations using surface well intervention subsequently secured all of the wells. This paper provides unique insight into the challenges of containing a blowout on closely spaced well pad configurations and highlights lessons learned.
Challenges and Solutions to the Correct Interpretation of Drilling Friction Tests
Authors: Cayeux Eric , Skadsem Hans Joakim , Daireaux Benoît , Holand Remi 
Published: March 2017

Abstract
During drilling operations, it is important to monitor carefully that cuttings are transported out of the hole and that the open hole formations do not collapse. A friction test is a simple procedure involving measurement of pickup weight (PUW), slack off weight (SOW) and free rotating torque (FRT) that provides information about possible changes in mechanical friction between the drill-string and the borehole while drilling deviated wells. It is not uncommon to observe very large variations in measured values between consecutive tests, even if there are no obvious reasons why the downhole conditions should have changed.
The inherent problem with the interpretation of friction tests is that many factors influence the observations. First, the drilling fluid circulation conditions have an impact on the forces applied to the drill-string. If friction tests are performed with different flowrates, the results are necessarily dissimilar. Second, as the drill-string is elastic, the transitions from pure rotation, to upward axial movement and then to lowering are transient and require some time before reaching steady state movement. Since the elasticity of the drill-string changes with the bit depth, the minimum distance that is necessary to attain stable measurements varies throughout the drilling operation.
A dynamic drill-string mechanical model coupled with a transient hydraulic model has been used to analyze a series of high quality real-time measurements taken during the drilling of a medium complexity well in the North Sea. Half of the friction tests were taken with a totally automated procedure while the other half were performed manually by the drillers. The automatic friction test procedure resulted in greatly improved consistency in test measurements compared to the manually executed tests. The results of this investigation show that many of the variations observed in measurements of the PUW, SOW and FRT were in fact related to slight dissimilarities in the way the manual friction tests were executed by the drillers.
This study clearly demonstrates the value of using transient mechanical and hydraulic models to interpret friction tests. Especially in cases where the friction tests are performed manually, these models enable much more reliable indications of whether the downhole conditions are changing or not. Furthermore, the new method has shown that it is possible to even further improve the automatic test procedure by reducing execution time without sacrificing the result quality.
A Comparison of Stick-Slip Mitigation Tools
Authors: Kyllingstad Aage 
Published: March 2017

Abstract
The most effective way to mitigate torsional stick-slip oscillations is to apply smart control of the top drive so that it effectively absorbs energy from vibration components near the stick-slip frequency. This paper is a comparative study of several smart control systems available in the market.
The comparison is based mainly on analysis of the top drive mobility over a wide range of frequencies. Torsional mobility is defined as the complex ratio of speed to torque variations at the top drive output shaft and it carries information on both amplitude and phase relations between the two variables. The real part of normalized mobility, defined as the non-dimensional product of this mobility and the characteristic impedance for the upper drill string section, has proved to be a very useful tool for analyzing damping characteristics and for calculating the risk of instabilities.
Four different variants of smart control methods have been analyzed, both with perfect tuning and no signal delays and when signal delays are present. The systems have not been rated against each other, but they all show a relatively high sensitivity to signal delays, even small delays in the order of 50 milliseconds.
Improved Wellbore Stability in Tor/Ekofisk Wells through Shale-Fluid Compatibility Optimization
Authors: Oort Eric van , Pasturel Christian , Bryla Jedrzej , Ditlevsen Frederik 
Published: March 2017

Abstract
Tor/Ekofisk wells drilled in the Danish sector of the North Sea have historically suffered from borehole instability problems when intersecting the Upper/Lower Lark and Horda shale formations using either water-based mud (WBM) or oil-based mud (OBM). An extensive wellbore stability investigation was carried out, focused primarily on improving shale-fluid compatibility. It was augmented by a lookback analysis of historical drilling operations in order to identify practical solutions to the borehole instability problems.
A state-of-the-art experimental rock mechanics and shale-fluids compatibility investigation was carried out featuring X-ray diffraction and cation exchange capacity characterizations, shale accretion, cuttings dispersion, mud pressure transmission and a new type of borehole collapse test for 11 different mud systems (WBM, OBM and high-performance WBM). The results of this investigation were then combined with the results of a comprehensive well lookback study. The integrated study clearly identified the root cause(s) of the Tor/Ekofisk well problems and highlighted comprehensive practical solutions, which were subsequently implemented in the field.
The borehole instability problems at Tor/Ekofisk in the Lark/Horda shales have a characteristic time-dependency, with wellbore cavings occurring after 3-5 days of open-hole time. The problems were not related to mud weight selection, but were instead caused by mud pressure invasion into the shales, which destabilizes them over time. An extensive experimental testing program revealed that this effect occurs in both WBM and OBM to equal extent, which explains why non-optimum field performance has historically been obtained with both types of mud systems. New high-performance WBM (HP-WBM) formulations were identified that significantly improve upon the mud pressure invasion and borehole collapse behavior of conventional OBM and WBM systems, yielding extended open hole time that would allow the hole sections in the Lark/Horda shales to be drilled, cased and cemented without triggering large-scale instability. Lookback review also indicated that secondary causes of wellbore instability, such as barite sag, extensive backreaming and associate drillstring vibrations should be minimized for optimum drilling performance. A new HPWBM system, together with improved operational guidelines, was successfully implemented in the field.
New Gas-Tight V0 Packoff Stage-Cementing Equipment Provides Reliable Solution for Wellbore Integrity and Significant Reduction in Rig Time
Authors: Abdel Al Aziz Mahmoud , Khallaf Ahmed , Urdaneta Nava Luis , Jacob Jobby , Farley Doug , Shaker Sherif 
Published: March 2017

Abstract
Selective cementing is required in challenging wellbores with tight mud-weight windows between low-and high-pressure formations around the Arabian Gulf. It is typical to cover the Thamama 5,6 high-pressure formation and the Mishrif low-pressure formation in the Satah Al Razboot (SARB) field and the Salabikh formation in the Zakum and Umm Shaif fields in a single 12.25-in. hole section. This paper will discuss the reliability and cost impact of using new packoff stage-cementing equipment for cementing and zonal isolation in this situation.
Operators have a history of compromised casing integrity requiring intervention of wells because of the short lifetime of stage-cementing equipment. They have been forced to select other, more costly and more time-consuming methods (requiring four to six trips), such as installing a liner hanger and a tieback to surface. Although these methods are reliable and field proven, they have added considerable upfront investment in rig days and greater expense to the operation.
The evolution of reliable, gas-tight stage cementers (two-trip systems) rated at up to 10,000 psi at 350°F reduces the required number of operating days and total well costs and expands the technology limit for more challenging well conditions.
Rigorous testing and equipment qualification to International Organization for Standardization (ISO) 14998 V0 and ISO 14310 V0 have established confidence in stage-cementing tools with integral packer and slip systems. Based on this validation, wells in the Arabian Gulf Region can now be constructed using a single long string of casing, thereby eliminating the added expense of a liner hanger and liner tieback system. In addition to equipment savings, these stage-cementing tools reduce by as many as to 6 to 7 days the total number of operating days required to construct the well. The tools also reduce approximately US $1 to $1.5 million in direct cost and subsequent costs of intervention over the life of the asset.
This paper will provide insight into equipment installation methods and comparative time and cost for the use of pack-off, two-stage cementing tools in the United Arab Emirates. Technology innovation was achieved by combining completion accessories and downhole products that meet international standards set forth by ISO/API. This maximizes the reliability and validates the extended limitations of the technology to apply alternative well construction techniques that will retain wellbore integrity and reduce cost over the life of the well.
A Study of the Dynamics of Lateral Fastline Vibrations
Authors: Kyllingstad Aage 
Published: March 2017

Abstract
The transversal vibrations of the fastline have been studied. The fastline, which is the part of the drill line running between the drawworks drum and the fast sheave, is put into vibrations by spooling induced motion at the drum and by variations of the line tension. Both excitation mechanisms are described in some detail and the transversal line response is studied with and without fastline stabilizers applied to reduce the vibration amplitudes.
Two type of models have been used in the study, a simplified linear model suitable for frequency analysis and another more advanced simulation model which can also handle non-linear stabilizer damping. Both models show that the vibration amplitude can be severe if the excitation is cyclic with a frequency component matching one of the natural resonance frequencies of the fastline. Both models also show that the effect of a stabilizer is highly dependent on its damping characteristics and on its vertical location.
The study has resulted in the design of a new and patent applied type of stabilizer placed more close to the fast sheave than a conventional stabilizer commonly used today. One of its main advantages is that it provides equal damping to both transversal directions.
RED: Revolutionary Drilling Technology for Hard Rock Formations
Authors: Wiercigroch Marian , Vaziri Vahid , Kapitaniak Marcin 
Published: March 2017

Abstract
Large Rates of Penetration (ROPs) with a good borehole stability in hard rock formations is still one of the major challenges in downhole drilling. In this regard, the Resonance Enhanced Drilling (RED), a new downhole drilling technology being developed by the University of Aberdeen, could offer a radically new way of drilling for oil and gas wells at a reduced cost and a lower environmental footprint. Market research estimated that the RED technology could result in an annual savings of $1.05 billion for operators [1].
The RED technology applies a controllable high frequency dynamic stress on the drilled formation, which is induced by axial oscillations of a drill-bit at the resonance conditions. The resonance conditions between the drill-bit and the formation are maintained for varying drilling conditions by adjusting the frequency and amplitude of the dynamic load to produce a steadily propagating fracture zone. The RED technology is particularly well suited for hard rocks.
Through an extensive physical and mathematical modelling, and experimental studies on the developed full scale experimental rigs, it has been proved that RED can significantly reduce wellbore creation time and deliver the capability to drill with one bit through in various rock formations and drilling conditions. RED also allows to drill efficiently even with a smaller Weight-On-Bit (WOB).
The University of Aberdeen is just about to complete a large multi-million pounds research and development programme funded by the Scottish Enterprise aimed to scale up the laboratory findings and bring the RED technology closer to the commercial world. The paper introduces this technology and discusses its potential impact on the industry.
Changing the Chalk Drilling Paradigm in the Netherlands
Authors: Brands S. , Bocquet R. , Matviykiv T. , van der Pouw Kraan A. 
Published: March 2017

Abstract
In the Dutch sector of the North Sea the Ommelanden Chalk formation commonly contains large amounts of chert, a very hard nodular rock. High friction exacerbates the harsh drilling conditions leading to mechanical dysfunction of the drilling process: severe downhole shocks, large torsional vibrations, bit and bottom hole assembly (BHA) wear and loss of directional steerability. Acceptance of these drilling conditions have long prevented drilling teams in the Netherlands to make significant drilling performance improvements.
This case study shows a step-by-step optimization approach, where we evaluated various drilling systems and their interdependence at each step. Separately optimizing the individual drilling sub-systems: bit, BHA, fluids and the rig led to little overall improvements. The initial focus was on the bit and drive system, but their successful utilization was limited by the harsh drilling environment. Close examination and various attempts proved that a combination of non-aqueous based mud (NABM), lubricant and a rotary drive control system could deliver a stable drilling environment. This allowed us to select different bits and drive systems. After multiple attempts with new technology PDC bits we proved drilling the entire chalk interval in one run was possible. In addition, rotary steerable systems (RSS) enabled directional steering in any part of the 12 ¼-in section.
The improvements led to fewer bit runs. The average progress rate through this section has been increased from 100 m/day to 300 m/day, with estimated savings of 10 to 15 rig days per well. In addition, the downside risk of equipment damage, inability to maintain trajectory control and related cost has been reduced significantly.
Pursuing drilling optimization can take considerable time and effort. It is often not a single-step process, but requires a multidisciplinary approach. This case study demonstrates important process improvements and technology applications, which reduced operating risk and cost.
High Assurance on Barrier Placement and Evaluation for Deepwater Wells in Brazil
Authors: Reveth V. , Ortuno G. C. , Bersaas K. M. , Escalante J. R. , Barron J. , Moretti F. , Antunes A. D. 
Published: March 2017

Abstract
In a Deepwater well off the Brazilian coast which presented a complex architecture with multiple drilling casings and liners, losses were expected during cement placement across a carbonate formation. This paper describes the use of a new real time monitoring and evaluation tool which takes the data acquired during the cement placement, then processes and simulates in real time to provide important job parameters such as estimation of fluid interface positions inside the casing and annular space, pressure match chart, density quality assurance and quality control (QA/QC), ECD and dynamic well security, among others.
This manuscript present two cases history where the operator and the service company work together to define a decision tree for the possible contingencies related to unwanted TOC based on mud losses or unplanned cement placement. Later during the operation the new tool combines the design data with the cement unit and rig acquisition data to compare the job measured surface pressure, density, flowrate and volume with predicted data from simulations. Finally based on the information of real time estimation of the TOC outside the pipe and annulus space observed during the job execution a contingency from a decision tree is taken.
The cementing service company provided real-time monitoring and evaluation tool that allowed the operator to identify the estimated TOC at the end of placement. With this information, the client was able to avoid the top of liner squeeze and save 2-3 days rig time Later a cement bond log showed that top of cement was found between the liner lap confirming the barrier element. In another case it was prevented leaving unplanned cement inside the casing with the analysis of the job and simulated pressure match trends at the end of the displacement and eliminated unexpected flat times for additional drill out time.
Real-time monitoring and evaluation is a tool that can be deployed not only in Deepwater wells in Brazil, but in any section of wells being drilled around the world on land, on the shelf or in Deepwater, where the operator wants to visualize ether the deviation of job execution from job design parameters or a prompt estimation of top of cement as a first level of detection for the well barrier placement just after bumping the plug. In addition having the real time dynamic ECD will also aid in avoiding any potential well control situations (including lost circulation) during the cement operations at any time during this critical activity
Horizontal Drilling with Dual Channel Drill Pipe
Authors: Vestavik O. M. , Thorogood J. , Bourdelet E. , Schmalhorst B. , Roed J. P. 
Published: March 2017

Abstract
Drilling of long horizontal wells is subjected to challenges, such as hole cleaning, drill string torque and drag, and challenges related to the Equivalent Circulating Density (ECD). Where the window for the downhole pressure is small, the length of the open hole section is limited by the dynamic ECD. The result is that several liners or casing strings may be required to reach the target depth.
The Reelwell Drilling Method provides a new solution for above mentioned challenges, incorporating a dual drill string, with a separate channel for the return fluid from the well. This arrangement enables Managed Gradient Drilling, i.e. to drill with a constant downhole pressure gradient that can be controlled to be nearly independent of the flow rate. The solution is similar to Managed Pressure Drilling, however, differs in that the downhole pressure gradient is managed instead of the pressure at one depth in the well. In addition, this new method of ECD control provides efficient hole cleaning at low flow rates, and enables torque and drag reduction due to buoyancy of the drill string.
A shallow horizontal trial well was drilled onshore Alberta, Canada, March 2016, to verify the new technology. New drilling equipment, including a newly designed aluminum dual drill string was used. New drilling procedures were employed, including the new Heavy Over Light drilling fluid solution. The equipment and procedures successfully verified the key benefits of the technology: –Managed Gradient Drilling with ECD eliminated by near static well annulus fluid.–Torque and drag reduction resulting from the drill string buoyancy effect.–Efficient hole cleaning at low flow rate, due to return flow inside the dual drill string.
In the following sections, we describe the technology, how the field trial was organized and present drilling data from the shallow horizontal drilling operation that confirmed the capabilities of the system.
Minimization of Downhole Tool Failures Using Nash Equilibrium and Downhole Data
Authors: Jiang Wanyi , Samuel Robello 
Published: March 2017

Abstract
Complex and expensive downhole tools have been increasingly employed in modern drilling. Downhole tools may fail and result in a reduction in the rate of penetration (ROP), repair or replacement of the damaged tools, wasted trips, and rig downtime, which can substantially add to the drilling cost. The causes of downhole tool failures are compound, ranging from material, quality, and design to operating conditions. Accurate modeling and prediction of downhole tool failure may be useful for tool maintenance, preventive measures, and the determination of optimal operation windows to avoid downhole tool failures and mitigate damages.
The risk of tool failure as well as the drilling cost may be evaluated simultaneously. To model these two objective functions, a two-player, non-zero-sum game theory model is proposed. In the game theory model, the first player takes actions, such as drilling operations, to maximize his/her payoff in terms of ROP, while the second player tries to reduce the probability of tool failure as much as possible. The payoff tables in terms of ROP and tool reliability have been constructed respectively. Based on the payoff tables, the Nash equilibrium (i.e., optimal strategies) has been determined.