bluuebunny/crossref_metadata_2025_split huggingface dataset:
Automation Provides Unique Insights of The Rock Record and Subsurface Through the Delivery of a Robotic Sample Collection and Analysis Device
Authors: Tonner David , Swanson Aaron , Hollingshead Ron , Hughes Simon , Seacrest Stephen , McDaniel Bret , Leeper Jay 
Published: February 2018

Abstract

Objectives/Scope
From the very early days of oil and gas exploration, appraisal and development drilling, samples have been collected at the rig by mud logging personnel to conduct a preliminary geological analysis of the rock being drilled. This collection typically involves a sample collection recipient, board or bucket to collect a sample of rock over the desired interval. The sample is then sieved and cleaned in the appropriate way depending on the type of drilling fluid being used. As penetration rates have increased in some instances to more than 400 ft. / hr. the sample resolution has deteriorated exponentially. From an ergonomics perspective, the highest frequency to which a person onsite can collect a sample is once every 20 minutes. At 300 ft. / hr. this translates to 100 ft. of drilled rock. A new device has been developed and deployed which automates this manual process and thus ensures faster and more accurate collection of geological samples of the drilled rock interval. Sample resolutions of 5ft rock intervals have been attained at 400 ft./ hr. This technology has provided an important technological breakthrough and enables reduction of personnel at the rig site with a subsequent reduction in cost and HSE risk, particularly in areas of H2S. It further has provided for the potential integration with Measurement while drilling personnel. For both conventional and unconventional play development, this has provided oil and gas operators with an important and cost and risk reducing modus operandi compared to conventional drilling and evaluation techniques. The tool was deployed for an operator in West Texas where both manually collected traditional mudlog samples and automatically collected samples were taken. The samples were analyzed and compared for rock content. In addition, comparisons were made between point sampling with the automated system versus samples collected over a defined interval manually. Results of these comparisons will be presented.

Results, Observations, Conclusions
A new method of automated drill cuttings sample collection has been successfully deployed. The new method provides a step change improvement in accuracy and resolution for sampling the rock record during drilling.

Novel/Additive Information
Additional data of the rock record provides potential insights to optimize wellbore placement and provide increased geo-mechanical data to optimize completions.
Application of an Innovative Spacer System Designed for Optimal Performance in HTHP Wells
Authors: Doan Angela , Holley Andrew , Kellum Matthew , Dighe Shailesh , Arceneaux Cory , Conrad Ken 
Published: February 2018

Abstract
Extreme well conditions, especially higher temperatures, are becoming more commonplace. This in turn requires improvements to our wellbore fluids. This study focuses on the development of a new spacer system designed especially for those wells exhibiting extremely high temperatures.
A critical characteristic of this spacer is that the surface rheology must not be overly excessive as to maintain a pumpable fluid; however, the downhole rheology must not diminish due to thermal thinning or degradation of the gelling agent so the spacer remains stable. To ensure the spacer suitably meets these requirements, both ambient and elevated temperature rheologies are analyzed and reported. The stability of the spacer related to settling of solid particulates is examined by conducting dynamic settling tests at 300°F and above.
In this study, spacer compositions and densities were adjusted to examine effects on rheology and stability of the solids within the system at elevated temperatures. Results show that conventional spacer systems are not adequate at elevated temperatures especially above 300°F. The newly developed spacer system shows much improved results from dynamic settling tests even up to 400°F. Also, the surface rheology of the new spacer system is not significantly different from that of the conventional system.
The innovative spacer system within this paper was shown to add significant value to extreme cementing operations. In addition, by comparing the results between these two testing methods, the dynamic settling test should be considered as an alternate procedure for testing the stability of spacers under high temperature conditions.
Measuring Land Drilling Performance
Authors: Willis John B. , Jackson Richard 
Published: February 2018

Abstract
Managers seek understanding of drilling performance, and visibility of how groups contribute to drilling results. The process described improves executive's understanding of drilling cost and performance. The principles are applicable to any drilling program (and even other, non-drilling operations), but are best suited to land drilling programs with many wells of common types.
In this method, a baseline budget is established for each type of well. As the program changes, a revised budget is created based on the wells actually drilled, plus those currently planned. The monthly revised budget measures performance against a consistent benchmark. The definition of well types, tracking of costs, adjusting for unusual situations, and calculations to apply the technique are discussed. The revised-budget process is used with traditional operational metrics to provide a complete spectrum of performance metrics for all levels of the organization.
The revised-budget method provides a clear perspective of performance, more insightful than standard "actual vs budget" comparisons. Additionally, deviations from benchmarks are quantified by performance, pricing, and scope changes. These categories correspond to organization groups that contribute to performance. The use of the revised-budget technique focuses discussion on the correct issues (performance, pricing, and scope) for each group. Historically, discussion of cost deviations often bogged in debate over which group was responsible. With this system, the contribution of each group to results is identified.
The revised-budget technique does not replace, but enhances traditional drilling metrics such as cost-per-foot, feet-per-day, flat time, non-productive time, and others. Traditional analysis methods are of most value to drilling groups in seeking specific actions to improve.
The system is the result of 10 years of evolution of measures to manage drilling more than 16,000 wells globally. The system has delivered best-in-class performance.
The novel aspect is that it is a complete system encompassing a workable benchmark, it adapts to the constant changes in the drilling program, it identifies how groups contribute to results, and it connects to traditional drilling metrics. The revised-budget technique using granular benchmarks is applicable to many types of operations and solves a chronic budget review problem.
The Application of Wellbore Strengthening to Achieve Zonal Isolation
Authors: Majidi Reza , Dondale Aaron , Braley Nicholas , Flores Rafael 
Published: February 2018

Abstract
Lost circulation while running casing, pre-cement job mud circulation, and cement placement can result in additional remediation, create challenges in achieving zonal isolation objectives, and potentially impact well integrity. Several mitigation methods are available to address lost circulation challenges. However, the focus of this article is on prevention.
Wellbore strengthening is utilized to strengthen low fracture gradient (FG) and permeable zones to a target maximum equivalent mud weight (EMW) value induced during tripping, circulating, or cementing. Engineered wellbore strengthening pills of specific particle concentration and size distribution are placed in the open hole and pressure is applied to the wellbore in a controlled fashion. As a result, a higher fracture gradient of the weak sands exposed in the entire interval is achieved, allowing permeable formations to withstand higher EMW during subsequent tripping, circulating, and cementing operations without inducing losses. This paper summarizes the field application of wellbore strengthening in deep-water Gulf of Mexico (GoM) to achieve zonal isolation. The design, execution, and post-well analysis of several wellbore strengthening applications in a variety of sands from shallow and soft overburden sands to deep producing reservoir sands with depletions greater than 4,000 psi, are discussed. A detailed case study for one of the wells is provided.
The track record of successful wellbore strengthening treatments performed demonstrates the potential for achieving adequate annular cement placement and zonal isolation in narrow pore pressure fracture gradient environments.
Tubular Ratings Used in Well Containment Screening Tool
Authors: Rahman Shaikh , Mason Stan , Sathuvalli Udaya B. , Lumley Pete 
Published: February 2018

Abstract
One of the documents that a drilling operator must submit with the Application for Permit to Drill (APD) to the Bureau of Safety and Environmental Enforcement (BSEE) is the Well Containment Screening Tool (WCST). The data are submitted via eWell by the operator during the APD process. The results of the screening tool are used to demonstrate that the well is adequately designed to contain uncontrolled flow. Worst Case Discharge (WCD) loads are considered as survival loads, and the exposed tubulars must satisfy a design factor is 1.0, for both burst and collapse loads. Two levels of screening are performed in the WCST. Level 1 screening assumes BSEE specified hydrocarbon gradients and ensures that the well can be fully shut-in without causing underground flow. If the well fails Level 1 screening, or if the well contains an unconditionally trapped annulus, Level 2 screening is required to ensure well integrity during unrestricted flow, and subsequent full shut-in. In both levels, the mechanical integrity of the tubulars is one of the three categories that the WCST does screen. BSEE does not provide guidelines on what tubular ratings should be used to account for the effects of downhole temperature. Using manufacturer provided ratings will be less than conservative, since they are valid at room temperature. The burst rating should be derated for the temperature at the depth of interest, because yield strength decreases with temperature increase. The collapse rating should be derated not only for the temperature, but also for the axial tension, if it exists, at the depth of interest for the WCD load. The temperature derated burst and collapse ratings can be estimated when expected WCD temperature is known. The tension derated collapse rating requires a complete examination of the load. The current version of the WCST does not facilitate this task; and the results can lead to a potentially non-conservative conclusion. This paper discusses the impact of temperature and tension on WCD loads and how to use the WCST more accurately.
Automated Directional Drilling Software and Remote Operations Centers Drive Rig Fleet Well Delivery Improvement
Authors: Gillan Colin , Isbell Matt , Visitew Travis 
Published: February 2018

Abstract
Early in 2017, initial discussions began to define an Automated Remote Drilling project that would use a centralized command center and specialized distributed software systems to automate the directional drilling decision-making workflow and the implementation of these decisions at the rigsite. The objective of this de-manning of directional resources at the rigsite was to enable the Operator's in-house directional supervisors to efficiently and safely control a larger number of rigs than was previously possible with legacy work practices and software.
In addition to the standard high-speed data links from office to rig, the project was based on an automated directional software guidance system configured to optimize directional motor slide drilling. This integrated directional navigation software suite also communicates directly with the top drive directional control system to ensure slide commands are implemented exactly as calculated. The software suite captures and assesses the effectiveness of slides automatically and uses sophisticated steering logic and steering targeting systems to support directional drilling best practices and geo-steering adjustments in the production zone.
The paper presents aggregated feedback from directional drillers on the automated systems' decisions and the results of following system directives in the low angle and nudge sections, in the curve, and in the lateral wellbore. Case studies are presented, along with summaries of the workflow changes implemented in town and at the rigsite. Several current lateral Bakken wells are presented as evidence of the effectiveness of the Automated Remote Drilling project approach and the benefits of this level of collaboration between a forward-looking Operator and drilling contractor.
The combination of the directional navigation software, the automated implementation, the geo-steering support, and a new Automation Assisted Workflow presents a new approach to an industry-wide challenge in the current market of how to do more with less without compromising efficiency, safety, or intervention capabilities.
Self-Learning Probabilistic Detection and Alerting of Drillstring Washout and Pump Failure Incidents During Drilling Operations
Authors: Ambrus A. , Ashok P. , Ramos D. , Chintapalli A. , Susich A. , Thetford T. , Nelson B. , Shahri M. , McNab J. , Behounek M. 
Published: February 2018

Abstract
The mechanical failure of drilling equipment is an operational risk that can be limited through a robust detection and alerting system, particularly for Drill String Washouts (DSW) and Mud Pump Failures (MPF). The detection of these issues focuses primarily on the time signatures of the real-time and modeled pump pressure in relation to the flow rate trends. Together, these parameters describe the state of the equipment which can be assessed through real-time alerts.
A new methodology for real-time detection of washout and pump failure incidents during drilling operations was developed. The methodology behind the detection system uses a Bayesian network that models the drilling hydraulics and their associated failure modes. The network aggregates data from real-time rig floor sensors (standpipe pressure, pump rate, flow out, etc.), contextual information (rig state, mud properties, etc.), and predictions from hydraulic modeling. Cumulatively, they are the determinants of a probabilistic belief system indicative of DSW and MPF. The probabilistic model outputs belief values for DSW and MPF between zero and one. Given past and present trends, the model increases accuracy though self-learning and self-calibration that adjusts for poor sensor data, drilling conditions, and model uncertainty.
The Bayesian network was integrated into decision support software with real-time alerting capabilities. The software was then validated by an operator's 100+ onshore wells in North America, some of which contained MPF and DSW incidents with varying degrees of severity. Several case studies drawn from these wells are presented in the paper.
Each failure event that exceeded a programmed threshold for a specified period of time generated an alert in the form of a PDF report containing real-time sensor traces and DSW and MPF prediction outputs. The alerts were also displayed on a dashboard on the rig site user interface. Software thresholds were optimized to reduce false alert reports presented to the driller. Through continuous improvement and validation, DSW and MPF detection reached a level of accuracy which, in some cases, detected the warning signs of a failure hours before the problem was noticed at the rig site. Conclusively, the value added by the early detection of mechanical failures is the decreased amount of non-productive time due to pump downtime and maintenance, as well as trips and fishing jobs due to washed out pipe.
A New Rotary-Steerable System Designed for Vertical and Nudge Applications in North America Pad Development Drilling
Authors: Jones Steve , Sugiura Junichi , Feddema Chad , Charter Marc 
Published: February 2018

Abstract
Pad drilling has become commonplace for North America shale development drilling, which requires tighter well spacing/separation and reduced anti-collision risk. A new digitally-controlled rotary-steerable system (RSS), extensively embedded with electronics, solid-state sensors and electrically controlled mud valve, has been developed specifically for drilling vertical and nudge well profiles from pads in North America. Unique technology includes a slow-rotating steering housing with four mud activated pads to apply side force at the bit. The pad activation is controlled using a novel mud valve driven by a low-power electric motor and gearing system. Activation of the steering pads and control of force to the steering pads is achieved using a small percentage of mud flow and approximately 500 psi pressure drop below the tool. The limited amount of mud flow passing through the mud valve eliminates internal wash issues and reduces repair costs.
The electronics measurement and control system are mounted in the slow-rotating steering housing and includes 3-axis inclinometers, 3-axis magnetometers, 3-axis shock sensors, 3-axis gyros, and temperature sensors. Additionally, compact drilling dynamics sensors are placed at the bit box to gather at-bit data to evaluate bit-rock dynamic interaction.
This paper will describe the unique features that allow the system to be reliable and cost-effective for high-volume land drilling activities. The RSS bottom-hole assemblies (BHAs) have been extensively instrumented with multiple downhole dynamics sensors, which reveal a challenging drilling environment unique to vertical drilling and nudge applications and show the performance of the RSS in this environment.
Drilling as an Evaluation Tool in Horizontal Shale Wells
Authors: Mace Jason 
Published: February 2018

Abstract
The development of unconventional resource plays in the United States has led to numerous changes in the fields of drilling engineering and reservoir evaluation. During the initial years of high commodity prices, the act of drilling a horizontal shale well became more of a service and less of a science in an effort to increase speed of development. Reservoir evaluation through logging suites and core analysis was cast as an unnecessary cost and shale reservoirs were deemed to be "statistical plays"1. Recent downward force on commodity prices has threatened the viability of many active fields and pushed operators into developing only core acreage in an effort to sustain positive well economics.
This new "lower for longer" pricing environment has spurred ingenuity in an effort to elevate non-core acreage to core acreage status and enhance well productivity. Operators have shifted their views on reservoir evaluation by running logging while drilling (LWD) tools behind the bit, logging through the bit on wiper trips, or cased-hole logs such as a pulsed neutron and dipole sonic. Of interest in this paper is the use of drilling data as an analog for conventional logging suites, which add time, cost, and risk to well operations. By applying mechanical specific energy (MSE) data generated from the penetration of the formation, drilling engineers can turn an often disregarded data set into both cost savings and enhanced well productivity.
Integrated Analytical Trajectory Control Model
Authors: Gomez Carolina , Nunez Carlos , Samuel Robello 
Published: February 2018

Abstract
Typical trajectory-monitoring models only consider the geometrical approach, without considering the rock mechanics and operational constraints in a single algorithm. Trajectory corrections could compromise the wellbore stability and drilling efficiency. For this reason, an integrated analytical model is needed to couple the trajectory-control model with the rock mechanics and mechanical, rotational and hydraulic effects in the trajectory correction. This integrated approach allows to visualize the "big picture" when returning to the designed well path.
The paper provides a roadmap so that the directional driller can use in the field in real-time. The geomechanics validation ensures that the wellbore stability is not compromised so that the correction results in trouble-free drilling. The HMSE evaluation enables to analyze the drilling efficiency in terms of mechanical, rotational and hydraulic energy to identify dysfunctions and other operational causes and effects on the trajectory. To validate the integrated model different deviation scenarios are simulated using the information of real wells already drilled. The results have proven that the smoothest correction path calculated is not always the best path as it may result in operational problems. The use of this integrated model allows to anticipate and mitigate operational problems which translate in improved drilling efficiency. This paper aims to bridge this existing knowledge gap and provides a comprehensive treatise on well trajectory control and, more in general, estimations and their underlying model parameters. The paper describes the details and the new calculation methodology of coupling these various models. The paper presents specific field examples with and without these models where there were wellbore stability problems.