bluuebunny/crossref_metadata_2025_split huggingface dataset:
Remote Directional Drilling and Logging While Drilling Operations in the Arctic
Authors: Chatar Crispin , Stepnov Alexey , Mardyashov Anton , Gonzalez Juan Raul 
Published: January 2016

Abstract
Few locations present as many challenges as drilling in Arctic. It is one of the most hostile environments in the world. It contains some of the most remote locations, the toughest logistics challenges and the largest gaps in infrastructure on the planet. While the industry has moved progressively over the past decades to meet these challenges, one company's solution to reduce risk to personnel and the environment and to optimize cost was to do directionally drill and log the well remotely. Theoretically, wells could be steered and controlled from the comfort of your couch at home; millions of dollars' worth of technology controlled from thousands of miles away. With advances in data, communication and transmission technology, we have the capability to make it reality. This is exactly what was done.
The workflow is not only about monitoring or support from town offices but also a fundamental paradigm shift where the Directional Drilling and Measurement While Drilling (MWD) crew is not physically located on the rig. In order to accomplish this, a major transformation was needed to ensure that process safety was not compromised by introducing additional risk to the operation. Technologies had to be qualified and workflows had to be modified ultimately resulting in redefining roles and responsibilities. There was also a major challenge to convince operators to allow the control to come from a source external to the rig. There are many associated risks with such operations. These risks include loss of connectivity, untested methods for diagnosing tool failure and hardware failure to name a few.
In this paper the authors begin with a brief history of Remote Operations (RO) indicating major milestones. The challenges of implementation of RO centers, and the prevention and mitigation of the associated risks are discussed. Given the success in implementation of a major RO center in the Arctic, the methods and technologies used to achieve success is discussed with some specific focus on the Arctic operations. Many of the challenges and methodologies will be supported by details of implementation in the Arctic environment.
Prediction and Mitigation of Torsional Vibrations in Drilling Systems
Authors: Hohl Andreas , Tergeist Mathias , Oueslati Hatem , Herbig Christian , Ichaoui Mohamed , Ostermeyer Georg-Peter , Reckmann Hanno 
Published: January 2016

Abstract
Drilling systems are subject to torsional vibrations that are excited by bit-rock or by drillstring formation interaction forces. These torsional oscillations can be distinguished by mode shape and frequency. Well-known stick/slip oscillations are characterized by low frequencies (usually below 1 Hz) and affect the entire drill-string. High-frequency torsional oscillations (HFTO), in contrast, name the excitation of a high-order natural mode (reaching 400 Hz). In case of HFTO, the bottom-hole assembly (BHA) is exposed to high dynamics loads. Torsional vibrations compromise drilling efficiency and tool reliability. To address these challenges, we are proposing a method for automated BHA optimization based on mechanical drill string models.
Through extensive analysis of high-frequency (1400 Hz sampling frequency) data from field measurements, an analytical, verified, and easy to use criterion for the prediction of the excited torsional mode and the corresponding loads was derived. The criterion is based on the comparison of the resulting excitation from cutting forces at the bit and the damping of a torsional mode. The criterion is unique for every torsional mode and can be used to rank the susceptibility of torsional modes for HFTO or stick/slip.
A software application (Torsional Oscillation Advisor, TOA) has been developed for user-friendly interpretation of the underlying analytical method towards practical issues. The use of the TOA provides valuable input for drilling optimization: For stick/slip, the influence of various drill pipe sizes and the length of the drill pipe section on torsional stick/slip mode are analyzed. It is shown that the limit for stable drilling in case of bit induced stick/slip can be extended by stiffer drill pipes whereas the influence of the length of the drill pipe section is marginal. The material of the bit and its mass distribution is shown to have a considerable influence on the excitation of HFTO.
The software also enables automated BHA optimization in both new product development and tool operation phases. A numerical optimization approach is used to minimize the susceptibility of the bottom-hole assembly for stick/slip and HFTO for given constraints of the geometry and material parameters. Herein, a significant increase of stable drilling conditions regarding weight on bit and bit rotational speed with respect to torsional oscillations is achieved. Even small changes in the drilling system design have a visible impact on the torsional stability. The ability to identify and predict modes of stick/slip and HFTO that are most likely to be excited while drilling, an extension of the stable drilling zone and the estimation of loads before field deployment will result in higher drilling efficiency, more reliable tools and lower non-productive time.
The Anatomy of High Performance Float Equipment and Potential Failure Modes
Authors: Farley Douglas , Barannikow Ivan A. , Bourg Brandon L. 
Published: January 2016

Abstract
Float equipment comes in a variety of configurations incorporating such devices as poppet float valves and flapper valves to prevent cement from re-entering the casing at the end of displacement. Autofill functionality can be achieved by using various methods of flow and ball de-activation to either increase trip speed or reduce surge pressure on the formation. Float equipment performance is now loosely defined by the recommended practices in API RP10F. With the pending introduction of newly proposed API 10F standards, the industry recognizes the need to better define the performance properties for flow endurance, temperature, and back pressure. However, this much needed and improved specification does not address drillability and plug bump ratings.
This seemingly simple technology has highly engineered nuances that may not be readily apparent. The careful balance of flow endurance, high pressure resistance, and debris tolerance while maintaining quick drill-out properties has been achieved through many years of refinement and testing. Even the concrete used in the manufacture of float equipment is highly engineered to provide ultrahigh compressive strengths and shear bonding, which not only create a drillable product but also produce a seal between the steel hull and the valve. If these nuances are not clearly understood, the selection of high-performance, cost-effective float equipment can be compromised, which can lead to poor cement placement, remedial intervention, added drill-out costs, and reduced well integrity. Failure modes are often attributed to design flaws or manufacturing errors. In some cases this is accurate, but a detailed understanding of performance properties and accurate compressibility calculations can mean the difference between allowing sufficient flow back and recording a float failure. Pipe management and standardized cementing practices are also important to success.
This paper will explore the design practices and manufacturing methods for various types of float equipment and the need to dovetail the newly proposed API 10F standards and future iterations into the selection criteria for cost effective, reliable float equipment. This discussion will also review reasons for float failures and the causes behind these incidents.
Automated Drilling Fluid Analysis using Advanced Particle Size Analyzers
Authors: Oort Eric van , Hoxha Besmir Buranaj , Yang Lin , Hale Arthur 
Published: January 2016

Abstract
The era of drilling fluid property analysis carried out manually by a mud engineer is rapidly disappearing. Novel measurement tools and techniques are now making it possible to carry out sophisticated drilling fluid analyses using largely automated equipment. This paper anticipates and highlights the important role that automated particle size analyzers will play in future drilling operations.
A comprehensive experimental study was carried out using a new generation of particle size analyzers (PSA) to investigate their utility for automated drilling fluid analysis. The pieces of equipment that were evaluated were the Canty Microflow LPA (which uses imaging microscopy), the Mettler Toledo G400 ParticleTrack (which uses FBRM laser diffraction) and the Malvern Mastersizer and Zetasizer (which use Dynamic Light Scattering). These instruments were used in conjunction with in-house flow loops and shearing facilities to test (1) degradation of the particle size distribution (PSD) of lost circulation and wellbore strengthening materials under the influence of shear, (2) the behavior of the emulsion droplet size distribution (DSD) of invert emulsion mud systems (oil-based and synthetic-based muds).
Verifying and maintaining the PSD of lost circulation/wellbore strengthening materials is of crucial importance to prevent severe mud loss events that still continue to plague the industry at a trouble cost of many billions of dollars per annum. Our PSA analyses show that the PSD's of such materials, particularly those of medium to coarser sizes, is far from stable and degrades over time, primarily due to the influence of shear. It will be shown that automated, in-line PSA equipment allows for the degradation to be monitored and managed in real-time to maintain optimum drilling performance. In addition, such equipment can be used to monitor and optimize the DSD of an invert system, which is an extremely important quantity that influences many mud performance characteristics such as rheology, emulsion stability, fluid loss behavior, osmotic membrane efficiency, etc.
The work involves a comparative study of novel PSA's, ranking them by accuracy, ease of use, automation potential, real-time monitoring capability etc. It presents novel, non-intuitive data on the degradation of lost circulation/wellbore strengthening materials, thereby allowing ways to manage this degradation. It also presents, for the first time, some preliminary work on the behavior of invert mud droplet size and its impact on oil-/synthetic-based mud performance.
Multi-Zone Intelligent Completions for Interference Test Data Gathering Onshore Kenya
Authors: Ure John , Peytchev Peter , Jha Mihir , Wenk Andrew , Mackay John , Anuar Fendi , Asbey Thor 
Published: January 2016

Abstract
The operator is involved in the exploration and appraisal of the South Lokichar basin in the Turkana region in remote north-west Kenya. The fields so far discovered are characterised by multiple pay zones spread over sand/shale sequences of 800 – 1,000m in thickness, with the shallowest reservoirs at approximately 850 – 1,200m true vertical depth below ground level. Well total depths are in the range 2,300 – 2,500m measured depth below rotary table. Productive hydrocarbon-bearing zones to date have been sub-hydrostatic in initial pressure. The reservoir fluid is a waxy crude oil (24 – 37% wax content) with low, variable gas-oil ratio. Flow assurance is a key aspect of the completion design, due to the reservoir temperature of the shallower prospective zones being close to the wax appearance temperature.
Until late 2014 the drill stem testing of discovery and appraisal wells was rig based. Productive zones were tested in a ‘bottom-up’ sequence resulting in durations of 50 – 60 days for a five-zone drill stem test. The initial aim of well design activity was to increase testing operational efficiency, however the operator accelerated the area development planning as a result of the exploration and appraisal drilling success in the basin. Subsequently, completion design efforts were driven to meet a subsurface requirement for the acquisition of well test and transient interference pressure data from extended well testing involving five wells in two of the discovered fields (Amosing and Ngamia). The approach which has been successfully implemented, was to make all well testing rigless after the installation of a multi-zone intelligent completion, allowing the rig to continue appraisal drilling or well completion activity in parallel with these testing programmes.
This paper presents the completion design selected and the operational challenges which have been overcome by the operator in appraising these fields.
Improved Drilling Performance in Extended Horizontals Using Clean Brines in the Williston Basin
Authors: Davidson J. , Thompson B. , Dearing H. , Jones C. S. , Shipman J. 
Published: January 2016

Abstract
The successful drilling of an oil and gas well relies upon the application and maintenance of innovative technology. In order to improve drilling efficiency, all pertinent data needs to be reviewed appropriately and lessons learned need to be drafted and realized. This is particularly important with challenging extended-reach wells. Due to the very low permeability in the target formation, long horizontal laterals are desirable to improve oil recovery and maximize productivity. Long lateral lengths are limited by frictional losses from torque and drag. In this environment, a drilling fluid that is able to maintain low lubricity coefficients is required. In addition, the fluid must be environmentally sound and cost-effective. An underbalanced high-performance brine drilling fluid (HPBDF) was introduced as an alternative to the weighted oil-based fluid required in use.
As expected, different fluids require different strategies. When using a HPBDF, monitoring lubricant concentration and use is best practice. Using field measurements to adjust concentrations, the desired lubricity was achieved and maintained while minimizing lubricant use. Low lubricity coefficients correspond with reduced pipe wear and decreased torque and drag. By planning, monitoring and maintaining the HPBDF, the operator successfully achieved higher rates of penetration (ROP) resulting in shorter drilling times. In this application, low viscosity brines improved wellbore cleaning due to turbulent flow cuttings transport. This reduced time spent on clean up cycles and tripping times as compared to offset wells drilled with oil-based fluids.
The brine density eliminated the need for barite and minimized the solids in the drilling fluid. Suspended drilled solids in the HPBDF can increase abrasion and lead to increased torque and drag and directional tool wear and failures. When solids accumulated in the HPBDF, a dewatering system was used to flocculate the solids and remove them through a centrifuge to produce clean brine. Techniques were improved to provide clear brine while minimizing lubricant loss. For example, application of a high-performance fluid conditioner prevented lubricant loss in the dewatering process.
This paper discusses the use of HPBDF in drilling over 50 wells and the challenges overcome. It also details the equipment used and highlights the comprehensive technique for evaluating lubricity and its correlation to torque and drag. The resulting performance improvements reduced drilling costs by over 20%.
Multilaterals in the Mississippi Lime
Authors: Meize Robert , Reid Lance , Dano Frank 
Published: January 2016

Abstract
Resource plays are constantly challenged with ways to reduce costs and cycle times. The Mississippian carbonate reservoir offers thickness and rock strength, together with stacked pay conducive to multilateral techniques and their inherent cost savings. A multi-disciplinary team has drilled and completed over 25 multilaterals of various configurations, validating the mechanical feasibility, along with associated cost and production benefits. This paper presents details on operational techniques needed to successfully build the multilateral wellbore, pros and cons associated with the different concepts and some of the initial cost and production results.
Open-hole sidetracks along with cased-hole whipstocks are used to initiate the multilaterals. The reservoir requires stimulation, which necessitates running a packer and sleeve system typically run on a 4-1/2″ liner. After stimulation, the casing is cut-off in the open hole leaving each leg open to the multilateral junction to produce into a common wellbore.
Over 25 multilaterals have been completed with 100% mechanical success. Directional techniques and completion systems make this a viable alternative to single well laterals enabling cost reductions on a field-wide development. These cost reductions provide needed benefit, especially in a reduced oil price environment.
SandRidge Energy, Inc. started work in the Mississippian play in Oklahoma & Kansas beginning in 2009. The use of horizontal drilling techniques in this mature carbonate reservoir together with an aggressive infrastructure strategy has led to over 1,200 horizontal wells being drilled. The multilateral program is ongoing, so additional production information and results will be shared as it becomes available to the public.
Design and Performance of Annular Pressure Build-Up APB Mitigation Techniques
Authors: Sathuvalli U. B. , Pilko R. M. , Gonzalez R. A. , Pai R. M. , Sachdeva P. , Suryanarayana P. V. 
Published: January 2016

Abstract
Subsea wells use Annular Pressure Build-up (APB) mitigation devices to ensure well integrity. Type I mitigation techniques control APB by reducing radial heat loss from the production tubing to the wellbore. Type II techniques work by controlling the stiffness (psi/°F) of an annulus by modifying its contents and boundaries.
Though the physics of APB mitigation is well understood, the reliability of a mitigation strategy or its interaction with other parts of the wellbore is not always quantifiable. This is partly due to lack of a unified approach to analyze mitigation strategies, and partly due to lack of downhole data after well completion. Simply stated, the engineer is hard pressed to find computational-predictive methods to assess alternative scenarios and strategies within the framework of the design basis during the life of the well. In this light, our paper presents a quantitative approach to design the currently used APB mitigation strategies, i.e., rupture disks, syntactic foams, nitrified spacers, and Vacuum Insulated Tubing (VIT). In each case, the design is linked to the notion of “allowable APB” in an annulus, which in turn, is tied to the design of the casing strings, and thus to wellbore integrity. Based on an extensive survey of published literature and patents, we also review APB mitigation techniques that have been used less frequently or awaiting proof of concept/field trial.
Case History: An Enhanced Solids Control Strategy Selective Flocculation Process Allows for Reduced Dilution Rates and Costs in Water-based Drilling Fluids in Auca Field, Ecuador
Authors: Costa Sergio , Maiquiza Klever , Serrano Mario , Bastidas Alejandro , Enriquez Jose 
Published: January 2016

Abstract
The main objective of using selective flocculation is to increase the efficiency of the fluid system and the solids-control equipment. Removing drill cuttings from the fluid system is important for increasing the drilling efficiency and success of the overall operation. Selective flocculation is proven to efficiently remove drilled solids, especially smaller- or colloidal-sized particles. The performance of drilling fluid components increases because larger quantities are allowed to interact with the drilled formation, which is preferred.
This process provides various benefits, including decreased water consumption, which reduces requirements for additional new fluids to be mixed for dilution and consumption of sustaining properties for rheology, filtration control, and inhibition.
The design process focuses on the operation of centrifuges but begins by performing a detailed evaluation using specialized equipment of all solids-control equipment available on the drilling rig, from the shakers to centrifuges. Damaged parts and accessories are repaired and/or replaced, and a simple barite retrieval system and an array of valves for the injection of a concentrated flocculant solution composed of a specialized clay polymer are installed in the centrifuges.
The flow necessary for operation of the centrifuges is separated from the drilling circuit as the design current. The specialized polymer solution is injected, and the process ends with the arrangement of injection rates to obtain an output current with a clay content value measured using a methylene blue test (MBT) at zero or near zero. This current's properties must remain close to those of a new fluid without weighting material.
When the treatment was evaluated, an increase in solids-control equipment efficiency of approximately 10% was obtained, and a 12% reduction in total new drilling fluid volume was observed, which could be optimized up to approximately 30%. Savings in water consumption were directly proportional, and cost savings were influenced by the reduced consumption of fluid products.
Drilling Improvements in Pursuit of the Perfect Well in the Eagle Ford - More than 52% Reduction in Drilling Time and 45% in Cost in Two and a Half Years
Authors: Coletta Claudio J. , Arias Camilo , Mendenhall Scott 
Published: January 2016

Abstract
Drilling time and cost were reduced in the Eagle Ford through the implementation of techniques and processes that resulted in 52% improvement in time and 45% reduction in cost.
The shale revolution sparked an aggressive development campaign starting in 2010 in the Eagle Ford. Wells were drilled with a lack of appropriate knowledge of the area, without sufficient experience or proper equipment. Drilling costs were high but development was profitable due to the surge in oil prices.
Drilling wells in the Eagle Ford is challenging because of the differences in lithology throughout the well, pore pressure profiles, high temperature, geosteering requirements, and casing design. These challenges had to be addressed in the design and execution of the wells. In addition, multiple trips due to downhole tool failures and low rate of penetration (ROP) contributed to high non-productive time (NPT) and associated costs.
When Statoil took over the operatorship in the Eagle Ford an integrated approach to engineering and operations was key to optimize performance and bolster understanding of the area. Application of technology and standardization of operations resulted in continuous performance improvement. Detailed planning and execution, application of rotary steerable, implementation of an optimized casing design, contractor performance management, clear and open communication within the team, implementation of a performance incentive plan, and proper risk management all played a part in the overall drilling performance improvements.
Over the past 2 1/2 years, more than 100 wells have been drilled in the Eagle Ford by Statoil. The techniques and procedures applied to optimize operations resulted in valuable lessons learned that can be applied to other development programs in the Eagle Ford and similar areas.