bluuebunny/crossref_metadata_2025_split huggingface dataset:
Unconventional Drilling in the New Mexico Delaware Basin Case History
Authors: Willis John , Tellez Diego , Neel Randy , Caraway Greg , Adam Derek , Rodriguez John 
Published: February 2018

Abstract
The drilling practices, well designs, and experiences from drilling 179 unconventional horizontal wells drilled from 2012 through late 2017, in the New Mexico Delaware Basin, are presented.
Geological conditions addressed include high-pressure flows, lost circulation, salt and anhydrite, and drilling effects. Successful practices covered include casing design and setting depths, bits, rotary steerable systems (RSS), rig specifications, pad layout, and others. Mud systems discussed include brine, mixed-metal hydroxide, invert and direct emulsions. The benefit of rotary steerable drilling assemblies is discussed. Techniques to predict, prevent, and mitigate the effect of downhole vibrations are addressed, including bit and bottom-hole-assembly design, and operating practices.
Overall drilling speed was increased by 149% (measured as feet-per-day) during the period from 2012 to 2017 through the practices that are covered. During the same period, average lateral lengths increased from approximately 3,000 ft in 2016 to approximately 7,000 ft in 2017, with 10,000 ft laterals common. Rig capabilities, pad layout, casing designs, drilling fluids, drilling dynamics practices, and other designs improved significantly in the past 3 years. A methodical approach to vibrations has proven to be critical to consistent performance. Direct emulsion mud has shown promising results as a low-density fluid with salt-saturated water phase. Casing designs were optimized to eliminate strings in some cases, and to reduce hole sizes in other cases. Rig modifications were required to support long laterals and larger drill pipe sizes.
The economic success of New Mexico unconventional developments is heavily dependent on minimizing well cost. It is a difficult area requiring complex optimization.
Wellbore Instability Prediction Using Adaptive Analytics and Empirical Mode Decomposition
Authors: Lin Abraham , Alali Mohammed , Almasmoom Salahaldeen , Samuel Robello 
Published: February 2018

Abstract
Wellbore stability is one determining factor to the success of drilling operations. A multitude of wellbore stability issues may still be encountered, despite all previous knowledge and experience, when drilling a certain formation. However, the use of the large amount of data collected during drilling can provide valuable insight. This collected data, in combination with artificial intelligence models, can be used to predict wellbore stability in new drilling operations. Because wellbore stability is such a common and expensive issue to the industry, many papers in the literature have presented a multitude of techniques and algorithms to predict wellbore stability. The predictions made in the literature have all provided relatively good accuracy; the most common methods that have been presented include the use of multivariate statistics, linear methods, and artificial neural networks.
This paper presents two approaches to solve the wellbore instability prediction problem. First, principal component analysis (PCA) and linear discriminant analysis (LDA) are used in an attempt to reduce the dimensionality of the dataset. The results indicate that the dataset dimensionality could not be reduced. Second, nonlinear artificial intelligence models were implemented, including the artificial neural network (ANN), specifically the Bayesian regularization neural network (BRNN), and support vector machine (SVM). After building these two models and checking their accuracy, a new feature was implemented to filter the input data. Empirical mode decomposition (EMD) was adopted, which is commonly used in the field of signal processing to eliminate noise and variation in the data. This study evaluates the effect of EMD on the prediction and classification accuracy for wellbore stability. The study results are promising; by using EMD, accuracy was increased by 15% for both the ANN and the SVM models.
Backward Whirl Testing and Modeling with Realistic Borehole Contacts for Enhanced Drilling Tool Reliability
Authors: Popp Timothy , Stibbe Holger , Heinisch Dennis , Reckmann Hanno , Spanos Pol 
Published: February 2018

Abstract
Drillstring-borehole contact may result in backward whirl: a common and catastrophic phenomenon. To increase BHA (bottom hole assembly) reliability, reduce non-productive time (NPT), and ultimately improve service delivery, an in-house backward whirl testing rig is developed to investigate dynamic loads. Analytical and numerical models elucidate dynamic responses and are validated against backward whirl test results. A 6 ¾-in. BHA is tested in an 8.5 in. borehole using a continuous and discontinuous borehole profile. At a rotary speed of 60 rpm, and using a continuous borehole, lateral acceleration amplitudes range between 20 to 30 g with an RMS value of 3 gRMS. In comparison, a discontinuous profile results in acceleration amplitudes between 40 to 50 g with an RMS value of 7 gRMS. In regard to the discontinuous profile, the response spectrum shows a broader range of frequency content up to 200 Hz while distinct frequency peaks are evident in the spectrum when the continuous profile is used. Results indicate that backward whirl may occur from friction induced contact with different borehole profiles. Further, discontinuous profile yields drastically higher dynamic loads with a broader frequency spectrum than a continuous profile. Furthermore, validated models may serve as useful predictions for the backward whirl phenomenon and the system response. Backward whirl testing of full scale drilling tools with realistic, discontinuous borehole contact, supplemented with validated modeling, is a new approach to understand downhole dynamic events.
Improving Surface WOB Accuracy
Authors: Kyllingstad Åge , Thoresen Karl Erik 
Published: February 2018

Abstract
Weight on bit (WOB) is the axial trust force applied to the bit during drilling. It is one of the most important controllable variables of the drilling process. Still, it is quite rare and very difficult to measure it directly, and we are often left with estimating it indirectly through measurements of the tension at the top of the string, or even at the dead line anchor. This indirect WOB measurement, commonly called surface WOB, is most often calculated as measured off-bottom hook loadminus the actual hookload. This method assumes that the reference string weight is constant and does not change during drilling.
This paper challenges this assumption by discussing a variety of physical effects that can cause the reference hook load to change, during the drilling of a new stand and after a traditional WOB zeroing procedure is carried out. The paper discusses the following effects that can be used for correcting the reference hook load: 1)well bore friction, 2)added weight in air, 3)well inclination, 4)flow induced lift, 5) nozzle jet lift, 6)cuttings in suspension, and 7) back-pressure in managed pressure drilling operations.
Automated Large Data Processing: A Storyboarding Process to Quickly Extract Knowledge from Large Drilling Datasets
Authors: Saini G. , Chan H. , Ashok P. , van Oort E. , Isbell M. R. 
Published: February 2018

Abstract
Substantial volumes of data are collected during modern drilling operations. However, the business value of such data is limited unless it can be analyzed quickly to derive practical knowledge for application on subsequent wells. The sheer quantity and messiness of data can overwhelm oilfield personnel, making it difficult for them to extract value. An automated process is necessary to extract knowledge quickly and efficiently from large datasets. Our team identified a preliminary set of 12 questions with answers that provide immediate knowledge to help improve the drilling of subsequent wells. Each of these ten questions is best answered through a storyboarding process. The process involves the automatic creation of a series of one-page visuals with just the right amount of information on each page to validate the answers to the questions. Standardizing the structure of the data (well-site data, survey data, geology data, well plans, etc.) enables software to rapidly create these visuals and is an important step in the process.
This work describes how the storyboarding process was applied to a dataset of more than 100 gigabytes (GB) from 16 shale wells drilled in North America. Examples of questions that could be quickly answered using the process are: ‘What was the best drilled well on the pad?’ and ‘Did a particular bottom hole assembly (BHA) improve drilling in a particular section of the well?’ Scripts were written in Matlab and Python to automatically process the raw data and generate more than 20 different types of one-page visuals that are well suited to present the answers to such questions. The illustrated information includes insights into BHA performance, wellbore tortuosity and quality, vibrations, weight on bit transfer, and other drilling dynamics. Identifying the relevant KPIs to satisfactorily answer the questions and present exactly the right information from the vast amounts of data was a challenge. This paper documents and describes the concept of storyboarding that uses visuals to answer comprehensive questions. This concept is not yet widely applied in the drilling industry today, but is expected to be quickly adopted by stakeholders interested in drilling performance improvement and cost saving opportunities.
Directional Advisor Driven Rig and Directional Operation Integration
Authors: Hildebrand G. , Schultz H. , Torre A. M. , Olesen L. 
Published: February 2018

Abstract
In the North America Land market, drilling operations are typically conducted by a selection of different service companies. Each is responsible for a different aspect of the well construction process, and they must work together to deliver a successful well for the operator. This operational model can lead to overlaps and gaps across the various providers in terms of responsibilities and tasks. Due to differing skill sets across rig and directional personnel, integrating rig and directional execution has practically translated into drilling contractors establishing a directional company and providing both services. While this provides a single accountability point for both, it does not fundamentally change the operational model. A new approach to integrated operations is now possible with the assistance of directional advisor software, coupled with changes in rig driller capability and accountability.
This study demonstrated that by utilizing directional advisor software directional operations could be integrated with rig operations without negatively impacting well construction performance. Through the course of a fast-paced, twenty-two (22) well program in western Canada, directional operations were transitioned through a series of steps from a traditional model of two rigsite directional drillers and two rigsite measurement-while-drilling (MWD) engineers to an integrated and reduced crew model where all directional operations were directed from a remote operations center and directional steering was executed by the rig crew.
Twist Compensation Reduces Trajectory Tortuosity and Improves ROP
Authors: Kyllingstad Åge 
Published: February 2018

Abstract
Twist compensation is a new, patent applied technique for improving the performance of conventional directional drilling assemblies. It is a feed-forward control technique where the reactive twist is used for controlling the angular position of the top drive thus minimizing undesired variations of the tool face. The equilibrium reactive twist is calculated as the torsional drill string compliance multiplied by the applied bit torque. This torque is provided either by direct measurements or indirectly from the mud motor induced increase of standpipe pressure. Twist compensation makes it possible to optimize bit load and rate of penetration while keeping a good directional control. In addition to providing much higher penetration rates during sliding mode, it is also a mean to minimize the wellbore tortuosity.
Measuring Drilled Cuttings and Fluid Recovery by Real Time Mass Balance
Authors: Smith B. E. , Grubb S. A. , Smith M. B. , Eller J. G. , Connelly J. S. 
Published: February 2018

Abstract
A mass balance method of calculating drilled cuttings recovery and fluid loss/influx is presented. Field results are shown that illustrate hole cleaning effectiveness, hole enlargement, and wellbore breathing. A drilling fluid system including mass flow and density meters on the inlet and outlet of the circulating system is used to continuously measure and trend drilling fluid density, flow rate, and drilled cuttings recovery. Drilling fluid density measurements of the inlet and outlet flow streams are compensated for temperature and pressure and then used to calculate cuttings recovery based on the drilled rock density. Mass balance calculations also account for drill string fluid displacement and fluid seepage/loss/influx across the face of the borehole.
Reconstruction of Pipe Displacement Based on High-Frequency Triaxial Accelerometer Measurements
Authors: Cayeux Eric 
Published: February 2018

Abstract
Heavy vibrations in the bottom hole assembly (BHA) may cause permanent damage to the bit or other BHA components, like measurement while drilling (MWD) tools or rotary steerable systems (RSS). Tool- joints along the drill-string may get warned out by high levels of whirl along the drill-string. Repetitive shocks of drill-pipes against the formation may be the origin of wellbore instabilities or cause malfunctions of the communication network of wired drill-pipe high speed telemetry communication systems.
Because of all these potential problems, it is important to better understand how pipes move inside a wellbore. High frequency recordings of triaxial accelerometer measurements at different locations inside the BHA, or along the drill-string, open the possibility to reconstruct the actual displacement of drill-string tubulars. However, because accelerometer readings are taken in a reference frame that is not in uniform movement compared to a fixed referential, the readings are subject to complex effects of centrifugal, Coriolis and Euler accelerations that make the estimation of the pipe movement rather intricate.
Without considering these so-called fictitious accelerations, it is easy to misinterpret the actual movement of the accelerometers attached to a pipe. For that reason, a numerical method has been developed to calculate the displacement of the support of the accelerometers. To validate the numerical model, a laboratory setup has been built that allows for a precise control of the movement of an element that supports three triaxial accelerometers. The known displacements of the accelerometer support and the reconstructed displacements have been compared and a methodology has been developed to use the redundant measurements to reduce the uncertainty of the estimated movement resulting from inaccuracies around the exact position and orientation of the accelerometers relatively to its support.
Lately, several publications have reported results from high frequency triaxial measurements at different locations along the BHA and the drill-string, while others have pointed out the risk of misinterpretation associated with the existence of fictitious accelerations. This paper presents a validated numerical method that allows for an accurate reconstruction of the displacement of drill-string and BHA elements therefore providing a unified point of view to the problem of estimating drill-pipe displacements based on accelerometer measurements.
Dynamic Axially-Stiff String Model for Tripping Operations in Directional Wellbores
Authors: Zamanipour Z. , Miska S. Z. , Hariharan P. R. 
Published: February 2018

Abstract
The soft string model has been widely used for torque and drag calculations. Although several modifications have been developed, the standard model in the oil and gas industry is the static soft string model, in which the string is assumed to be motionless and its stiffness is neglected. In order to estimate more realistic and accurate calculation of drillstring loading, not only the acceleration, but also axial stiffness of the string must be considered in force calculations. In this paper, a dynamic, axially-stiff string model is presented for force calculations of drillstring in tripping operations.
The mathematical model is developed to include axial stiffness of the drillstring and acceleration into the soft string model by coupling mass-spring system with the soft string model. Moreover, static friction and drilling fluid drag are taken into account. The drillstring is considered to be a system of coupled oscillators subject to external forces. Then, the motion of the individual oscillator is governed by external forces and the forces applied by its two neighboring elements. In this model, the static friction effect is included as a constraint for initiation of motion.
The drillstring configuration is considered to be drillpipe, drillcollar, and directional assembly. The developed model ("new model") is implemented for tripping-out one stand in two ideal directional wellbores plus one field case wellbore trajectory. Axial force behavior shows a trend of acceleration that is similar to that observed with the previous dynamic soft string model ("previous model": SPE-173084-MS), and the first peak contains the effect of static friction. Displacement at the end of the string shows that the whole drillstring is in motion after few seconds. The axial force using the new model is compared to that (axial force) calculated using the previous model for two different cases. In the acceleration part of the motion, the new model shows a peak about 12% higher than the maximum load in the previous model which is due to the static friction force. In the constant velocity part of the motion, depending on the amount of damping, the new model can show a result similar to that of the previous model.
The new dynamic axially-stiff string model provides a more realistic prediction of hookload, and consequently more realistic loading of the hoisting equipment and fatigue life of the drillstring. Other applications of this model are for wellbore planning, drillstring design, optimization and automation of tripping operations.
A Method to Estimate Working Range of Vibrators
Authors: Zhang Yuan , Samuel Robello 
Published: February 2018

Abstract
Friction reduction devices in the form of vibrators are becoming more widely used in drilling operations because of their ability to create oscillation in the string, which can reduce the amount of friction force present. Ordinarily, the placement of vibrators is based on past field experience; an improper arrangement of vibrators, however, can reduce their efficiency and lead to possible tool damage. A proper model for estimating the working range for vibrators can enhance the efficiency and safety of the vibrator.
This paper presents a new method for predicting the working range for vibrators based on the stress wave theory. The proposed method uses the stress wave theory to calculate the vibration velocity. Beginning at the vibrator, the stress wave travels a lengthy distance in the string. The friction on the string, however, diminishes the stress wave energy until the vibration velocity reaches zero. The vibrator working range is defined as the string section with a non-zero oscillation velocity.
A set of equations to calculate the stress wave traveling distance is proposed in this paper. This model provides a theoretical prediction of the vibrator working range to effectively optimize vibrator use. The stress wave traveling distance predicted from this model is likely to be a linear relationship to the acceleration generated by the vibrator, which is similar to the results obtained in the field, and can be used to better determine the most effective placement for vibrators in horizontal wells.
Operators' Group, Rig Contractors, and OEM/Service Company Work to Solve Rig Data Quality Issues
Authors: Behounek M. , Nguyen D. , Halloran S. , Isbell M. , Mandava C. , Vinay N. , McMullen J. , Hoefling C. 
Published: February 2018

Abstract
In the current economic climate Operators must reduce drilling costs, so they are turning to well data analytics, real-time advisory, and automation systems to make sustainable improvements (Behounek et al. 2017). Rig surface sensor data is critical to improvement; however, documented issues with consistent, reliable, quality data complicates and delays the value from these systems. The Operators Group for Data Quality (OGDQ) seeks to accelerate the adoption of standardized key measurement specifications, data storage, transmission, transformation, and integration by working with Rig Contractors, Original Equipment Manufacturers (OEMs), and Service Companies. The OGDQ effort focuses on key measurements used for important drilling process decision making.
For this paper, the OGDQ worked with Rig Contractors and an OEM/Service Company to advance recommended data quality components in work processes and commercial agreements. By bringing transparency to the process, the authors hope to contribute to the efforts to address operational data quality issues and to drive alignment and improvements among Operators, Rig Contractors, OEMs, and Service Companies. This paper outlines an approach to putting data quality into practice, including initially identifying the problem, field verification, developing key measurement specifications, constructing framework components, and anticipating management of change issues.
Quality drilling data is essential to both rig and office personnel who are tasked with decision making for fast-paced well programs. Quality drilling data is also essential for the data-driven systems developed to assist in managing well delivery. Rig studies show several cases where Operators independently uncovered systematic errors for 10 key measurements used for drilling process decision making (Zenero 2014; Zenero et al. 2016). The 10 key measurements are listed as follows: Rotary/Top Drive TorqueJoint Makeup/Breakout TorqueHookloadRotary/Top Drive Rotational SpeedStand Pipe PressureDrilling Fluid Pump RateDrilling Fluid Tank/Pit VolumeDrilling Fluid DensityDrilling Fluid ViscosityBlock Position
Widespread agreement on data quality practices among Operators, Rig Contractors, OEMs, and Service Companies is crucial for their quick adoption, and an industry-wide approach has a profound effect on drilling operations. Widely adopted practices will support and drive requirements for sensor quality, calibration, field verification, and maintenance. This standardization will, in turn, significantly enable improved drilling operations, drilling analysis, and big data processing by correcting many errors resulting from poor data quality. This paper outlines the methodology used to develop a guide for commercial drilling components, and illustrates the application of this guide with selected drilling data use cases.