bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Three Methods of Rating Nasolabial Appearance in Cleft Lip and Palate
Authors: Fudalej Sylwia A. , Desmedt Dries , Bronkhorst Ewald , Fudalej Piotr S. 
Published: January 2017

Objective To investigate which of three methods of rating nasolabial appearance—esthetic index, visual analogue scale (VAS), or numerical scale with reference photographs—is optimal. Design Experimental study. Setting Radboud University Medical Centre, The Netherlands and University of Bern, Switzerland. Subjects and Methods Cropped photographs of 60 patients with complete unilateral cleft lip and palate (mean age = 10.8 years) were used for rating. A panel of eight raters rated four components of nasolabial morphology (nasal shape, nose deviation, vermillion border, and profile view) using three methods: 5-point esthetic index, 100 mm VAS, and 0 to 200 numerical scale with reference photographs (reference scores method). Method reliability was assessed by re-evaluation of 20 images after >1 month. Intraclass correlation coefficients were calculated to evaluate consistency of each method. Results Overall reference scores method always produced more reproducible results (i.e., higher ICCs) than did VAS or the esthetic index. However, statistically significant differences were found between reference scores and esthetic index in rating nasal shape, nose deviation, and vermillion border only ( P < 0.001, <0.001, and 0.012, respectively) and between reference scores and VAS in rating nose deviation and vermillion border ( P < 0.001 and 0.017, respectively). Conclusion We recommend the use of reference photographs along with the VAS or numerical (from 0 to 200) semi-continuous scale. The esthetic index, based on a Likert-type scale, seems to produce the most variable results and, therefore, is not preferred.
The Wide Divide Between Fracturing Plans and Reality
Authors: Rassenfoss Stephen 
Published: January 2017

Fracturing Plans
What is observed when an unconventional well is fractured is often at odds with what was expected by those who planned the job.
In-well observations from technical papers from Shell (SPE 179124) and Devon Energy (SPE 179149) presented at the recent SPE Hydraulic Fracturing Technology Conference question many of the assumptions made about how to most efficiently stimulate nearly impermeable unconventional formations.
Completion designs often assume that adding perforations will increase the number of productive fractures. But Shell’s in-well studies using a fiber-optic cable during and after completions showed that in most stages only one fracture, and sometimes two, take in most of the fluid and sand. The company also found that more stimulation translates into more production.
“There is invariably a dominant perforation stage emerging through the jobs,” said Bill Wheaton, formerly a senior adviser in operations engineering for Devon who presented its paper. “We would like to see four [effective] fractures for four perforation clusters, but that is an uncommon thing,” he said.
Generally, the most productive spot in each cluster of perforations is located on the heelward side—the end toward the section of the well that curves from horizontal to vertical. Both papers showed wide variations in how much fluid and proppant flowed into the formation at different spots along the studied wellbores. In the Shell study, more than two-thirds of all the clusters took in 50% more or less than the designed amount.
And the tools used to control the flow during fracturing often leak. Packers frequently fail to seal stages, allowing large amounts of fluid and proppant to escape, and diverters often are unable to temporarily clog large fractures so the hydraulic pressure can be redirected to stimulate small ones.
“We need to pay attention not only to the design but the execution,” said Gustavo Ugueto, senior staff petrophysical engineer for Shell, during his presentation at the fracturing conference. Measures of what flows into the perforations show that “a lot of them receive more than designed for, and a lot receive less.”
Fracturing Efficiency
There is an upside to these critical reports—addressing the problems could lead to revised methods and tools that could produce more oil and gas with less.
Shell’s paper sets that theme by quoting its paper about fracturing from 1963 (SPE 530) that said, “The basic objective of all well treatment is to get the best stimulation compatible with the cost.”
New Syngas Reforming Solutions for Enhanced Gas-to-Diesel Conversion
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 177660, “New Syngas Reforming Solutions for Enhanced Gas-to-Diesel Conversion,” by Conrad Ayasse and Rob Ayasse, Verdis Synthetic Fuels, prepared for the 2015 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 9-12 November. The paper has not been peer reviewed.
This paper presents an overview of the challenges of using traditional synthesis gas reforming methods for efficient gas-to-liquids (GTL) conversion. A second objective is to show how newly emerging reformer technologies, such as those based on plasma or catalytic partial oxidation, will provide significant improvements. A case also will be made for how these new technologies, when paired with a high-efficiency Fischer-Tropsch (FT) process, provide a profitable alternative to the environmentally damaging, and wasteful, practice of flaring or venting associated gas.
Introduction
Given the limitations of footprint, weight, safety, cost, and other factors for platform operations, the use of the FT process for flared-gas conversion to liquids is challenging. This study shows that the best process uses a catalytic partial-oxidation reformer, a unique wax-free FT catalyst, and an advanced FT reactor to meet all platform criteria while cutting traditional capital expenditures (Capex) and operational expenditures (Opex) in half.
Criteria for Platform Operations
The following criteria were considered for the selection of equipment on a platform:
Small footprint (space limitations)
Low weight (weight limitations)
Low pressure (safety considerations)
High gas hourly space velocity (GHSV) (to enable small reactors)
Low pressure drop at high GHSV (reactor shape)
High gas conversion (process efficiency)
High gas selectivity to carbon monoxide (process efficiency)
No water needed (simplicity)
No pure oxygen needed (platform requirement for safety)
No feed-gas preheat needed (simplicity)
No reformer tail-gas heat exchanger needed (simplicity)
At the heart of the list are footprint, weight, and safety. From the safety perspective, temperature, pressure, and oxygen concentration are important. Equipment footprint and weight affect the platform cost and the ability to add equipment to existing platforms. This means that the number of process-unit operations must be kept at a minimum.
Transforming the Upstream Service Industry To Increase Operator Margins
Authors: Spath Jeff 
Published: January 2017

Management
From organizational structures to procurement strategies to engineer staffing and development, the upstream exploration and production (E&P) industry is undergoing a transformation. Operators and service providers alike are not just tweaking, altering, and fine-tuning in this most recent downturn, they are completely rethinking the way they work. Our business of finding, developing, and producing oil and gas profitably, dependably, and in an environmentally responsible manner is facing unparalleled challenges.
In conversations with many chief executive officers during my term as president of SPE, the most common concern I heard expressed was cost control. And that was before the downturn. In fact, it has been a concern for management for most of the past decade.
The combination of escalating finding and development costs, relatively flat global oil production, and a steep decline in commodity prices has put significant pressure on profitability and free cash flow throughout the entire E&P value chain. Part of the reason for this is an extended period of underinvestment in the previous 3 decades. More importantly, the aging production base requires more investment to fight decline, and the newer resources such as pre-salt and unconventionals are more complex and expensive in terms of cost per barrel. Eighty percent of the global upstream research and development (R&D) spend is devoted to maintaining existing production— arresting decline.
One additional statistic that powerfully summarizes the situation is that over the past 10 years, global upstream spend has increased more than 400% while production has increased a mere 15%. Much of this production increase came from relatively expensive new frontiers such as shale oil and deep water. However, there have been significant cost increases throughout the upstream industry due to such factors as labor costs, material costs, inefficiencies in supply chains and logistics, as well as the complexity of project design, customization, decreases in equipment reliability, and the misuse or nonuse of appropriate technology.
One of the overarching objectives of my term as SPE president was to increase the extent with which our industry collaborates with other industries. We have much in common with and much to learn from industries such as the automotive, aerospace, and biomedical industries— to name just a few. It is clear that adopting technologies and processes from these “sister” industries is one way in which we can improve our own technical and financial performance.
In this article, I describe several additional areas of focus, primarily within the service provider’s domain, which when taken individually or collectively, can significantly reduce costs and improve efficiency levels and operating company returns.
Technology Focus: Intelligent Fields Technology
Authors: Hudson John 
Published: January 2017

Technology Focus
Over the last couple of decades, we have seen a steady stream of “intelligent” innovations go from ideas to infancy to catalog solutions. Advances in metering, measurement, control, automation, and modeling have changed our daily routine such that our decisions are better informed, and, as a result, we produce in more-challenging environments, at lower cost, and with better recoveries.
Whether deployed in the office or in the field, the majority of these advances have pertained to improvements in our organizations, in our production facilities, and in our wells. While still not routine, tools based on artificial intelligence, large-scale model integration, and automated data/model integration are finding their way into the typical practitioner’s toolbox. What is clearly emerging now are practical solutions that take the next step into the reservoir and across solution types and discipline boundaries. In the coming years, artificial-intelligence applications will steer our exploration and appraisal processes. While we push model integration (e.g., between static and dynamic and for entire production systems), artificial intelligence will be working behind the scenes to find model inconsistencies, to narrow uncertainties, and to improve our forecasts and option assessments.
These advances are coming at an opportune time in that they can support better decision making in some of our most-costly decisions (e.g., helping us to improve our productive drilling rates and demonstrating the real costs of deviating from reservoir-management plans). The papers highlighted in this section provide clear illustrations of how some of this will be achieved. JPT
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 26209 Proactive and Reactive Strategies for Optimal Operational Design: An Application in Smart Wells by A.C.A. Abreu, PUC-Rio, et al.
SPE 176760 Leveraging Intelligent-Field Data for Full-Field Pressure-Transient Analysis by B. Al-Wehaibi, Saudi Aramco, et al.
SPE 177829 Smart Proxy: An Innovative Reservoir-Management Tool; Case Study of a Giant Mature Oil Field in the UAE by S.D. Mohaghegh, Intelligent Solutions, et al.
Polymer Injection in Deepwater Field Offshore Angola
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174699, “Dalia/Camelia Polymer Injection in Deep Offshore Field, Angola: Learnings and In-Situ Polymer-Sampling Results,” by D.C. Morel, E. Zaugg, S. Jouenne, J.A. Danquigny, and P.R. Cordelier, Total, prepared for the 2015 SPE Enhanced Oil Recovery Conference, Kuala Lumpur, 11–13 August. The paper has not been peer reviewed.
The polymer-injection project in the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects. Thorough, integrated geoscience and architectural studies led to the decision to initiate a polymer-injectivity test on a single well, followed by a continuous injection of polymer on one of the four subsea lines delivering water to the field. The complete paper describes the main results of the pilot phase.
Introduction
A subsea development scheme with water injection for full pressure maintenance was chosen for the Dalia field together with gas reinjection. Very early in the geoscience studies, oil viscosity was identified as the main limiting factor to water-injection recovery. Polymer injection was positively screened as a potential enhanced-oil-recovery method for the field.
Extensive feasibility studies of polymer flooding were initiated in 2003, 3 years before production start-up. A phased approach was chosen to assess and reduce the main uncertainties of the project, consisting of the construction of a powder-polymer solution-preparation skid, a single-well injectivity test, a longer injection period through one of the injection lines (supplying three wells), and the drilling of a sampler/producer well to assess in-situ viscosity, while continuing surface and subsurface studies.
Dalia Reservoir
The field is developed by water injection, using a floating production, storage, and offloading (FPSO) vessel with 28 deviated or horizontal subsea injector wells and four injection flowlines (plus three gas-reinjection wells active before Angolan liquefied-natural-gas startup). A single flowline generally injects into several reservoirs as well as several systems. Maximum yearly average water injection is 360,000 BWPD. Desulfated seawater has been injected since startup to prevent any barium sulfate deposition, and all the produced water is reinjected.
Production is achieved through four production lines and 40 producers. First oil was on 13 December 2006. The 240,000-B/D oil-production plateau was reached after a few months, while, at the time of this writing, 8 years after startup, the field is still producing at a reduced plateau rate of 200,000 BOPD. A schematic of the layout is provided in Fig. 1.
Top-Down Modeling: A Shift in Building Full-Field Models for Mature Fields
Authors: Mohaghegh Shahab D. 
Published: January 2017

Young Technology Showcase
Description of the Technology
Models are needed to develop and operate petroleum reservoirs efficiently. Datadriven reservoir modeling [(also known as top-down modeling (TDM)] is an alternative or a complement to numerical simulation. TDM uses the so-called “big-data” solution (machine learning and data mining) to develop (train, calibrate, and validate) full-field reservoir models on the basis of measurements rather than solutions of governing equations.
Unlike other empirical technologies that forecast production, or only use production or injection data for its analysis, TDM integrates all available field measurements (well locations and trajectories, completions, stimulations, well logs, core data, well tests, seismic, and production/ injection history—e.g., choke settings) into a full-field reservoir model by use of artificial-intelligence technologies. Intelligent Solutions, as the inventor of TDM, has recently released software application “IMagine” for TDM development.
TDM is a full-field model wherein production [including gas/oil ratio (GOR) and water cut] is conditioned to all measured reservoir characteristics and operational constraints. TDM matches the historical production and is validated through blind history matching, and it is capable of forecasting a field’s future behavior on a well-by-well basis.
The novelty of TDM stems from the fact that it is a complete departure from traditional approaches to reservoir modeling. In this new paradigm, current understanding of physics and geology is substituted with field measurements as the foundation of the model. This characteristic of TDM makes it a viable modeling technology for unconventional assets, where the physics of hydrocarbon production is not well-understood.
Role of Physics and Geology
First-principles physics of fluid flow is not formulated explicitly within TDM, but forms the framework for the assimilation of the spatiotemporal database as its foundation. TDM is built by correlating flow rate at each well/timestep to a set of measured static and dynamic variables.
New Optical Gas-Imaging Technology for Quantifying Fugitive-Emission Rates
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper IPTC 18471, “New Optical Gas-Imaging Technology for Quantifying Fugitive- Emission Rates,” by Hazem Abdel-Moati, ExxonMobil Research Qatar; Jonathan Morris and Yousheng Zeng, Providence Photonics; Petroula Kangas, ExxonMobil Chemical Europe; and Duane McGregor, ExxonMobil Research and Engineering, prepared for the 2015 International Petroleum Technology Conference, Doha, Qatar, 7–9 December. The paper has not been peer reviewed.
Optical gas-imaging (OGI) technology has been developed and can be used to detect leaks of volatile organic compounds (VOCs) from process equipment. Using OGI to detect leaks is more effective than using the US Environmental Protection Agency’s Method 21 because OGI is visual, making detection faster, and can survey an area instead of one component at a time. Although OGI can be very effective in detecting leaks, it does not provide a quantitative measure of leak rate (LR), hindering its adoption as a true alternative to Method 21. This paper describes development of quantitative OGI (QOGI) technology.
Method and Preliminary Results
Approaches have been proposed to establish a quantitative relationship between the pixel intensity difference with and without a plume (ΔI) and the product of concentration in ppm and path length in meters (ppm·m) for a gas column represented by a pixel in the infrared (IR) image for a given temperature differential (ΔT) between ambient air and the background. This quantitative relationship has been confirmed with a study showing that there is a monotonically increasing relationship between ΔI and concentration for uniform black background that was temperature controlled. That study’s data also showed that ΔI increases as the temperature of the background increases for a specific gas concentration.
Engineered Shale Completions Based on Common Drilling Data
Authors: Carpenter Chris 
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 174839, “Engineered Shale Completions Based on Common Drilling Data,” by W.D. Logan, C&J Energy Services, prepared for the 2015 SPE Annual Technical Conference and Exhibition, Houston, 28–30 September. The paper has not been peer reviewed.
Current best practices in North America’s shale basins deliver inconsistent production results because of a lack of reservoir understanding along the lateral. Reservoir data is difficult and expensive to obtain in horizontal sections; therefore, most completions are designed geometrically, with little or no concern for reservoir heterogeneity. In this study, the authors demonstrate a reliable, cost-effective methodology that empowers shale operators with reservoir data on every well.
Introduction
The industry needs a reliable, low-cost reservoir-evaluation methodology that can be leveraged to deliver an engineered completion on every lateral. Such a technique would make engineered completions part of the factory approach on every lateral completed.
The solution described in the complete paper starts with data that already exist on every lateral. Current drilling practices include use of an electronic drilling recorder that collects data such as weight on bit (WOB), torque (TOR), rotational speed (RPM), rate of penetration (ROP), mud-flow rate (Q), standpipe pressure (SPP), and differential pressure (DIFP) on every well. The completions department can leverage these data to drive superior well productivity through a drilling parameter known as mechanical specific energy (MSE).
Adapting MSE for Reservoir Evaluation
The completions department can take advantage of MSE by recognizing the close relationship between it and unconfined compressive strength (UCS). MSE can be used as a qualitative predictor of UCS within each fracturing stage. By calculating MSE from drilling data (a process discussed in the complete paper), one can then predict zones of comparable UCS within each stage. This will enable placement of perforation clusters in zones of similar UCS within each stage, which is exactly what many completions departments are attempting to do with wireline measurements.
Wired Drillpipe, Closed-Loop Automation Technology Drive Performance Improvement
Authors: Wilson Adam 
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 178870, “Using Wired Drillpipe, High-Speed Downhole Data, and Closed- Loop Drilling-Automation Technology To Drive Performance Improvement Across Multiple Wells in the Bakken,” by Donald K. Trichel, SPE, and Matthew Isbell, SPE, Hess; Bruce Brown, BD Drilling Consultants; and Major Flash, SPE, Michael McRay, James Nieto, SPE, and Isaac Fonseca, National Oilwell Varco, prepared for the 2016 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 1–3 March. The paper has not been peer reviewed.
To accelerate learning, an operator deployed a real-time, closed-loop downhole automation system (DHAS) in conjunction with wired drillpipe in the 8¾-in.-hole section. The operator also used downhole memory tools in the 5?-in. lateral section to collect downhole drilling parameters and vibration data. The optimization process drew upon key elements from lean manufacturing concepts. It followed a “plan, do, check, adjust” (PDCA) loop, with the DHAS and the data provided by it affecting three concurrently moving performance-improvement cycles.
Introduction
The operator selected the DHAS with 5-in. wired drillpipe because it was believed the real-time, high-speed data feed would accelerate the learning process. By making the downhole drilling environment visible in real time, the driller could apply this new understanding of the drilling environment to the automation system, to optimize drilling performance. It was also envisioned that the large amount of data available from the system would feed the PDCA cycle and result in lessons learned and performance improvements that could be implemented across the fleet. The idea was to instrument one rig and use the lessons learned to improve the performance of the entire fleet. The primary project goal was reducing cycle time while achieving a breakeven cost for the additional technology.
At the time, there was significant variability in cycle time as well as a significant difference between the best- and worst-performing rigs. To assess the rate of improvement and, thereby, the potential of the DHAS to improve drilling performance, the operator selected a lower-performance rig for the pilot test.