bluuebunny/crossref_metadata_2025_split huggingface dataset:
Real-Time Drilling Advisory Roadmap System Delivers Superior Performance When Used in Conjunction with Downhole Embedded Drilling Dynamics Sensors
Authors: Jones Steve , Sugiura Junichi 
Published: February 2020

Abstract
In North America shale development drilling, multiple wells are typically drilled from one pad, and multiple pads are constructed on one lease. Pad drilling allows for numerous lateral wells to be landed parallel to each other in similar lithological sequences. The bottom-hole assemblies (BHAs), drill bits, and drilling practices are incrementally tuned to maximize the rate of penetration (ROP) while minimizing non-productive time (NPT) in pad drilling. This paper describes the use of a real-time drilling parameter advisory system, which aids the objectives of pad drilling and producing consistently better drilling performance.
The real-time drilling parameter advisory system has been developed in conjunction with the learnings from downhole embedded drilling dynamics sensors. The advisory system is pre-programmed with a parameter roadmap that has been developed from analysis of offset downhole embedded sensor, mechanical specific energy (MSE), gamma-ray log and electronic drilling recorder (EDR) data.
The advisory system displays "ideal performance" drilling parameters, such as surface WOB (weight on bit), RPM (revolutions per minute) and GPM (gallons per minute), for a given true vertical depth (TVD), formation transition zone and formation. The "ideal" parameter window of operation is displayed alongside the actual drilling parameters. MSE is used as a guide for comparison of offset drilling efficiency versus current drilling efficiency. Offset well data from optimally placed embedded drilling dynamics sensors (at-bit and string measurements) and gamma-ray counts are also displayed on the advisory system. This gives the user a "look-ahead" of what trouble zones or formation changes that are approaching. Essentially an early warning system with guidance included.
The novelty of this advisory system is the ability to display the offset-well drilling dynamics data, as well as MSE, gamma-ray counts, and ROP so that the users can be fully aware of the approaching formation tops and troublesome local lithologies and can make sense of the recommended surface parameters. The use of embedded drilling dynamics data in every well for a field development, along with the drilling parameter advisory system, helps generate consistently optimal drilling performance well after well.
Validation of Transient Annular Pressure Build-Up APB Model Predictions with Field Measurements in an Offshore Well and Characterization of Uncertainty Bounds
Authors: Pai Rahul , Gupta Anamika , Sathuvalli Udaya B , Suryanarayana P V , Affes Sami , Okoroafor John , Nwamara Ndubuisi 
Published: February 2020

Abstract
The average geothermal gradient in the subject deepwater field in Nigeria is 4.37 °C/100 m, nearly twice the gradient in most fields. As a result, the magnitude of the expected annular pressure build-up (APB) during steady state production is large enough to threaten well integrity. Therefore, an insulating packer fluid (IPF) was used in Annulus A to reduce heat transfer to the outer annuli and to regulate the APB within acceptable values.
To gain confidence in the thermal analyses and to estimate the efficacy of the IPF, downhole temperature and pressure sensors were installed in the completion string and in the Christmas Tree of selected wells. Measurements during flow tests on these wells were thereby obtained.
Our paper reports the results of a study that compares the temperature and pressure measurements from these wells with model predictions. Specifically, we compare APB predictions with field measurements and determine the validity of the thermal model and rheological models of the IPF fluid used in the thermal model. We also characterize the uncertainty inherent in predictions of wellbore temperatures.
There are few published downhole annular P-T measurements. Therefore, the reliability (and post-installation performance) of APB mitigation devices is often difficult to assess. This project to obtain measurements of downhole APB under controlled conditions is an important step in the calibration of currently used APB models, and in the establishment of guidelines for "robust" well design(s) in the face of APB loads and lifetime well integrity concerns.
FEA-Based Fatigue Modeling of Cuts and Pits Saves Money and Reduces Drill String Risk
Authors: Pettit Grant , Lee Kang 
Published: February 2020

Abstract
In different inspection standards, corrosion pits in drill pipe tubes are treated in different ways. Sometimes they are considered a stress concentrator and subjected to relative depth limitations (like a maximum of 10% of the adjacent wall); sometimes they are only considered as a location of wall loss, so the steel thickness underneath them is the only acceptance parameter. This work clarifies the difference in severity between these two types of imperfections, and enables the definition of a reasonable inspection process.
Slip cuts and corrosion pits with varying depths were modeled using Finite Element Analysis (FEA) techniques for multiple drill pipe sizes. The resulting stresses and strains under tension and bending loads were used to calculate the fatigue lives of these components. The resulting number of cycles to failure does not correspond to the real lifetime of real pipe—there are too many variables and neglected parameters—but the results can be compared within the data set to determine which options are better and worse and by how much.
Significantly, this research validates the approach taken by some standards to neglect the stress concentration effects of corrosion pitting, only considering the wall thickness remaining for the purposes of inspection. The commercial benefit to this is huge: it allows the inspector to not have to reject or repair a drill string’s worth of light corrosion pitting. This research indicates this is valid and safe in many cases, but in the more-stringent inspections used for offshore drill pipe the relative depth of the pitting also needs to be considered.
A Voice Interface for Drilling Systems
Authors: Chatar Crispin , Huang Zhe , Hadrovic Peter 
Published: February 2020

Abstract
Every year, millions of dollars in man hours are used for reporting by wellsite personnel. Input peripherals are evolving exponentially as the latest technologies drive what is possible. One of these technologies is a voice interface system.
Consider the case where a system of smart microphones records what is said at the wellsite. This system would also be connected to the rig’s data and control system. At the end of the day, a report could be generated by a system that is smart enough to understand the context of conversations and merge it with sensor data. In addition, as automation becomes more prevalent for drilling operations and as head count on the rig decreases, drillers will be able to spend less time documenting daily activities or hunting down data. The system could also be used to control a drilling system via voice. This is the future that is being built today.
Working with third party partners and using their technology as a base, a proof of concept interface for the rig with voice as an input was built. Testing of multiple scenarios including context simulation, data transfer, data logging, specific log extraction, data feedback and control of a test rig was executed here have been some challenges which are unique to our drilling environment such as noise, distinguishing the origin of an audio source, and new context generation. For these, work was done with local startups as well as some major players from outside the industry to define what solutions already exist or could exist in the future. It is possible to then implement these as an additional layer. The solution also applies to operations outside drilling for other domains in the oil and gas industry. Testing has also been done on the voice interface for production monitoring on demo pumps.
This paper will describe a future that could only be imagined previously. Technologies that exist outside our industry have been merged from various sources to create a unique solution to these problems. The paper will discuss what has been done so far and show the potential of this system for which a real-time demo was created. There will be discussion on challenges along with the strategies that can be employed to solve them. Of these, some have already been tested—these will also be showcased.
Large-Scale Deployment of a Closed-Loop Drilling Optimization System: Implementation and Field Results
Authors: Lai Stephen W. , Ng James , Eddy Aaron , Khromov Sergey , Paslawski Dan , van Beurden Ryan , Olesen Lars , Payette Gregory S. , Spivey Benjamin J. 
Published: February 2020

Abstract
On a land-based rig, the driller has many responsibilities and is rarely able to adjust the main process controls, WOB and RPM, on a continuous basis. The result is sub-optimal drilling and longer spud-to-TD time than necessary. Automatic, closed-loop optimization removes this burden and results in better and more consistent drilling performance. In this paper, a closed-loop drilling optimization system is presented with results from over 1700 wells in the field.
The closed-loop system builds on industry-proven advisory technology and is designed uniquely for petroleum drilling. Since formation characteristics can change rapidly with depth, a fast optimization algorithm based on input signal dithering is used to continually adjust drilling parameters to search for the highest possible ROP and lowest possible MSE. Drilling dysfunctions, such as stick-slip and formation stringers, are treated as discrete time events and mitigated using software protocols triggered by accurate detection algorithms. Also, operation of the inner loop autodriller is of critical importance and controlled using a specialized set of autodriller management protocols.
Over the past 2 years, the system has been deployed on over 270 rigs for construction of over 1700 land wells in North America. One of the main deployment challenges was the need for full organizational buy-in from both rig and office personnel. Another major challenge was the need for parameter limit roadmaps which define reasonable, but non-conservative, optimization limits to be used during the drilling of each well. Drilling performance on approximately 90 wells was analyzed and compared to equivalent offset wells. The result was an average ROP improvement of 6.5% and 7.6% in the vertical and lateral sections, respectively. A case study is presented highlighting improved ROP when the optimization system was used.
Reduce Downhole Drilling Motor Bit-To-Bend and Increase Drilling Performance Through Novel Bearing Lubrication Configuration
Authors: Hankins James , Thompson Patrick , Marchand Nick , Smith Roger , Wong Jerry 
Published: February 2020

Abstract
Short bit-to-bend (SBTB) drilling motors are desirable for their increase in drilling performance and reliability. A SBTB drilling motor is usually achieved by reducing the side loading capability, torque capacity, or thrust capabilities of the drilling motor. The new SBTB technology allows directional drillers to use high-torque power sections and maintain the same weight-on-bit (WOB) parameters. Lower bend settings on a SBTB reduce the stress on housings and will achieve the same build-up rate (BUR) as a conventional drilling motor. These features reduce costs, improve performance, and enable drilling time savings.
Guidance for Calibration of a Directional Drilling Wellbore Propagation Model Using Field Data
Authors: D'Angelo John , Pehlivanturk Can , Ashok Pradeepkumar , van Oort Eric , Shahri Mojtaba , Vasicek Alan , Behounek Michael 
Published: February 2020

Abstract
Accurately estimating the directional tendency of a drill string is important to ensure tracking of the planned trajectory and to prevent over/undershooting targets. Predicting this tendency is often achieved through calibration of a physical model of wellbore propagation using previous directional drilling data. However, the amount of relevant prior information to use and the uncertainty in future predictions is not always clear.
The goal of the work reported here was to determine the amount of prior directional drilling data to use for calibration, and the frequency at which recalibration should occur to ensure accurate predictions of wellbore propagation. A procedure was designed to provide this information for a given wellbore propagation model in a given field. The particular model used in this study is a quaternion-based wellbore propagation model that describes the motion of the bit as a rigid body in space which moves based on fixed angular velocities and drilling inputs given in the form of a traditional slide sheet. However, the procedure can be used for any wellbore propagation model that requires calibration on prior directional drilling data.
The procedure consists of two tests. The first test (hold-out test) shows how the prediction error varies over an increasing amount of calibration data while holding the testing-set size constant. The second test (prediction test) shows how the prediction error varies over an increasing testing-set size while holding the amount of calibration data constant. These variations in prediction error can then be examined by looking at the spread of data over these tests.
The test methodology was applied on field data obtained from North American wells where bent sub motors were used for deviation control. The first test showed diminishing returns when incorporating more actions into the model calibration. In cases where bottom-hole assembly (BHA) changes were observed, calibrating on a larger number of prior actions slightly increased the test error. The second test allowed us to approximate the error propagation rate of our model predictions in the current field. The procedure described in this paper allows for such information to be quantified and visualized easily to improve the directional driller's understanding of the needs and reliability of the wellbore propagation model being used.
New Version of IADC Daily Drilling Report Significantly Increases Granularity, Provides Opportunity to Collaborate Using a Common Digital Format
Authors: Shackleton David , van Kuilenburg Robert , Moralez Nathan , Macmillan Robin , de Wardt John , Hsieh Linda 
Published: February 2020

Abstract
The International Association of Drilling Contractors (IADC) Daily Drilling Report (DDR) is used on more drilling rigs worldwide than any other reporting system. The original version developed mid-last century (Killalea 2005) has not been routinely updated to accommodate the industry needs, causing its full potential to be unrealized. IADC launched the DDR Plus™ project in 2018 to unlock greater value by bringing it in-line with 21st century technologies.
An in-depth industry survey identified major user requirements for an updated DDR. IADC's Advanced Rig Technologies (ART) Drilling Controls Systems (DCS) subcommittee focused on two areas: updating the Operations code set used to record activities at the rig site and developing a standard digital description of the report leveraging modern, XML-based industry standards.
This paper describes the approach IADC took to successfully update the IADC DDR, from identifying a concept using industry input and scope debate to the development of the final product.
The IADC DDR Plus is fully backward compatible with previous versions of the report, while it adds four additional layers of codes to increase granularity significantly. The industry-standard Wellsite Information Transfer Standard Markup Language (WITSML) data exchange standard, developed and maintained under Energistics (Pickering et al. 2009), was adopted as the basis for the report's digital description. Where necessary, WITSML was adapted to the needs of the DDR Plus. Combining the WITSML data transfer protocol and the IADC DDR Plus code structure allows users to integrate real-time data into their digital DDR.
The new IADC DDR Plus provides users with the opportunity to standardize on an industry-collaborated solution. As companies aim to be more competitive in today's drilling market, the new DDR Plus provides greater visibility of their operations and can lead to more in-depth analysis of well construction cycles and reductions in invisible lost time. The standard format provides opportunities for increased industry collaboration and benchmarks where they wish to compare data using the digital description's more detailed standard format. The DDR Plus lends itself to automated reporting from rig sensors, thereby reducing the manhours necessary for data input.
Accounting for Hydraulics and Vibration in MSE Calculations to Estimate Formation Properties
Authors: Trivedi Ajesh Sanjay , Clarkson Christopher R , Shor Roman J 
Published: February 2020

Abstract
Mechanical Specific Energy (MSE), the amount of work done to drill a unit volume of rock, has been evolving as an important parameter to indicate drill-bit efficiency by quantifying bit-rock interactions. Until now, the industry application has been on drilling efficiency, however, the study extends this application by utilizing MSE for estimating subsurface rock properties such as rock strength. Once known, rock strength may be used for improved geosteering – since measurement of MSE is at the bit – or for completion designs. In this study, high resolution (10-second) drilling data is used for the analysis. An updated MSE calculation is proposed which incorporates mud motor dynamics, frictional losses along the drill-string, and drillstring dysfunctions (i.e. vibration). Two new parameters in the form of Hydraulic Specific Energy (HSE), that estimates role of hydraulic impact force at the formation, rather than bit bottom and Vibration Specific Energy (VSE), that estimates the energy associated with vibrations and how it impacts the translational (weight on bit) and rotational energy (Torque) supplied from the top-drive, have been introduced. Upon correcting MSE values for drill-string vibrations (VSE), mud-motor effects and frictional losses along the drill-string, as well as incorporating hydraulic term (HSE), the comparison between MSE and Rock CCS along the well show a high degree of correlation giving an indication of using MSE to estimate rock strength. These corrected MSE values are the actual energy requirements (MSEactual) contributing towards rock-cutting action downhole. Finally, rock CCS values are estimated using the correlations developed between corrected MSEactual and corresponding drilling efficiency calculated as a function of RMS amplitudes of drillstring vibrations.
Whole-exome sequencing detection of the somatic mutations associated with the tumorigenesis and gefitinib-response of mucoepidermoid carcinomas
Authors: Wu Yufeng , He Zhen , Zhang Zhe , Wang Lili , Yang Sen , Liu Yang , Dong Bing , Guo Yongjun , Wang Wei , Zhang Yuhong , Wang Qi , Zhang Yi , Wang Qiming 
Published: February 2020

Abstract
Background: We performed whole-exome sequencing (WES) on the sputum and blood samples of a MEC patient exploring the genetic alternations underlying the mechanism of mucoepidermoid carcinomas (MEC) and gefitinib response.Methods: We previously reported a 10-year old MEC patient who was cured after a complete response to gefitinib treatment. Whole-exome sequencing (WES) was performed on the samples of this patient to detect somatic mutations. Detected genes harboring somatic mutations were compared with previously reported mutant genes related to MEC.Results: Somatic mutations were detected in 13 previously reported oncogene and tumor suppressors, and enriched in apoptosis (RIPK1, SPTA1, and ACTG1). The loss and gain of phosphorylation amino acids occurred in 8 of the 34 non-synonymous mutations, which resided in ARL6, DNAH11, PGM5, PRAMEF15, RALGAPB, RANBP2, TTN, and UBN1. TTN bared two Ala to Thr mutations. Among the 50 genes containing detected somatic mutations, ADAM28, DYSF, GP2, PPP2R5B, and TTN were also detected in a previous study; and all of these overlaps were identified in low and intermediate grade samples.Conclusions: These findings underline the possibility of the accumulated somatic mutations in the tumor suppressor genes and oncogenes might contribute to the tumorigenesis of our MEC patient, which have potential applications for the therapies of MEC.
Nurses communication skill and associated factors in Amhara Region Referral Hospitals, Ethiopia, 2019
Authors: Yazew Kassahun Gebeyehu , Gebrie Mignot Hailu , Aynalem Zewdu Bishaw 
Published: February 2020

Abstract
Background: - Nurses are critical in the delivery of essential health services and are core in strengthening the health system. So, the aim of this article was to assess the prevalence of the communication skills of the nurses to patient and determinant factors in Amhara Region Referral Hospitals, Ethiopia, 2019 Methods: Institution based cross-sectional study was conducted from March 18 to April 16, 2019 in Amhara Region Referral Hospitals. A simple random sampling technique was used to select 684 respondents. Data was collected using pretested and self-administered questionnaire. Collected data was entered into Epi Info version 7.1.2.0 and exported to SPSS version 25.0 for analysis. Bivariate analysis was used primarily and variables with p-value ≤ 0.2 were further examined using multivariable logistic regression model to control con-founders. Then, variables having p-value less than 0.05 with 95% CI were used to determine associated factors. Results: - Out of 678 study participants, 403 (61.4%) of them had effective communication skills with 96.8 % of the response rate. Less than 5 years of working experience [AOR=2.77; 95% CI: (1.28, 5.99)], workload [AOR=1.52; 95% CI: (1.09, 2.12)], and poor evidence-based utilization [AOR=2.00; 95% CI: (1.40, 2.85)] were associated with the nurse’s effective communication skill to patients. Conclusions: More than half of the participants were had effective communication skills. Year of working experience, workload, and poor evidence-based utilization were the main contributing factors of the communication skills. Keywords: Communication skills, Nurses, Patients, Ethiopia