bluuebunny/crossref_metadata_2025 huggingface dataset:
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 The paper has not been peer reviewed.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.
Comments: Resilient Production
Authors: Donnelly John
Published: January 2017

Editor's column

This issue of JPT offers two suggestions as to why crude oil prices may not rise significantly in the near future. The role of unconventional production becoming the industry’s “swing producer” in reaction to oil prices is laid out in the Management column beginning on page 42 (see also Comments, March 2015 JPT). And the continued strength of Permian Basin output is described in an article beginning on page 24

Although global crude oil production has declined in some regions since the collapse in oil prices began, and there have been massive cuts in company spending, world output has remained stubbornly resilient. Global petroleum production rose in 2015 and 2016, and is projected to rise slightly in 2017, according to the US Department of Energy’s Energy Information Administration (EIA) Short-Term Energy Outlook, published in September.

US crude oil production averaged 9.4 million BOPD in 2015 and is forecast to average 8.8 million BOPD this year and 8.5 million BOPD in 2017. The US production forecast is 0.2 million BOPD higher than one the EIA made in August as it cited an uptick in drilling activity, rig efficiency, and well productivity.

The steep decline in North American rig activity over the past year came primarily from the onshore light tight oil sector, which has short development cycles that allow producers to react quickly to price signals. Production from the US Gulf of Mexico is expected to reach record highs next year due to previous big deepwater discoveries.

Changes to Performance Indices Page

Beginning with this issue, the World Crude Oil Production table in the Performance Indices page will include fewer countries. The table lists the monthly crude oil production numbers from the EIA. Ongoing work on the EIA’s website is disrupting the regular updating of some countries’ production numbers. This has been going on for several months, which is causing considerable delays in our reporting of this information. EIA recently launched the redesign of its International Energy Portal at http://www.eia.gov/beta/international and is currently beta testing it.

Over the years, our readers have indicated that they use the Performance Indices to gather data for their research and analyses. Therefore, we decided not to source production data from another provider in order to preserve the continuity of data for our readers. Other reporting services use different methodologies to collect production information.

In this issue of JPT and going forward, crude oil production data (crude oil including lease condensate) will be sourced from the EIA’s Monthly Energy Review. The Review includes statistics on total energy production, consumption, and trade; energy prices; overviews of petroleum, natural gas, coal, electricity, nuclear energy, renewable energy, and international petroleum; carbon dioxide emissions; and data unit conversion values. It is available at http://www.eia.gov/totalenergy/data/monthly/, including historical data back to October 1974. JPT
Devon Energy Rises to the Top as a Data-Driven Producer
Authors: Jacobs Trent
Published: January 2017

After becoming one of the first shale producers to adopt advanced data analytics, Devon Energy is now one of its most ardent champions. The results speak to why that is.

Since 2012, when Devon began investing in big data technology, its 90-day production rates from horizontal wells have increased by 250%—an improvement that according to IHS Markit data has lifted the Oklahoma City-based company’s early-time production from new wells to the highest level in the US onshore market. Additionally, Devon’s costs to drill, complete, and operate its well have fallen by as much as 40%, the company said.

It is fair to attribute some of these significant gains to the quality of the company’s positions inside North America’s most prolific shale plays, and also the pressure that oilfield contractors are under to make price concessions in a down market.

However, that does not complete the story.

From exploration and drilling to completions and production, Devon has put to work a small arsenal of sophisticated algorithms designed to find the otherwise hidden insights and engineering tweaks that are driving more value out of the shale fields it operates.

This realm of computer science has also made routine tasks that once took engineers hours to complete possible to do in a few minutes, or less. And that some of these programs can literally think for themselves, although in a limited mathematical sense, is not hyperbole.

Today’s offerings in artificial intelligence and machine learning technology can be trained to look for defined outcomes, or they can be set free to decide on their own what to look for and will rewrite their underlying algorithms in order to do so.

Humans Still in the Loop

As intriguing as this emerging world of intelligent software is, when discussing how it has changed her company, Kathy Ball, manager of advanced analytics and data science at Devon, begins by stressing the importance of the human element.
Technology Focus: New-Frontier Reservoirs II
Authors: Kalfayan Leonard
Published: January 2017

Technology Focus

With crude-oil prices continuing to languish, margins in tight-reservoir-asset developments have continued to tighten and new drilling and completion activity, of course, is substantially reduced. Looking back 2 years, the focus in onshore-asset development has essentially shifted entirely from fast-paced growth of tight hydrocarbon reservoirs to production enhancement from existing (but still profitable) wells, as well as to maximizing productivity from the smaller number of new well completions.

However, enhancing production from multizone, propped-fracture completions in tight reservoirs, for example, is not straightforward. There are questions to address, especially with respect to the understanding of the contribution of natural fractures and induced unpropped (IU) fractures. How can natural and IU fractures be accessed or enhanced in new wells or in existing wells that are candidates for refracturing? Is there an opportunity with the use of smaller proppants? What are the implications of fracture and well spacing? Can the pumping and rate steps of fracture stages be redesigned for improved containment and fracture conductivity, even formation permeability enhancement? Are there learnings from long-term injection operations in tight reservoirs that can be applied to well-stimulation operations?

Also, for existing well completions, can reactive fluid (e.g., acid or other chemicals) be used effectively, and, if so, how? Can well production be enhanced by injection of fresh water to remove salt potentially residing in existing natural-fracture systems?

The papers featured this month provide assessments and discussions concerning these and other related questions. Each paper is unique, but they all share the intent of advancing efforts in enhancing production from existing and new well completions in tight reservoirs. JPT

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 180274 Study of the Rock/Fluid Interactions of Sodium and Calcium Brines With Ultratight Rock Surfaces and Their Effect on Improving Oil Recovery by Spontaneous Imbibition by M.K. Valluri, Texas A&M University, et al.

SPE 169843 Estimating Long-Term Well Performance in the Montney Shale Gas Reservoir by Vu P. Dinh, Murphy Oil, et al.

IPTC 17739 A Comparison of North American and International Risks in Unconventional Resource Plays by D. Nathan Meehan, Baker Hughes
Injection in Shale: Experience on the Norwegian Continental Shelf
Authors: Carpenter Chris
Published: January 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170851, “Injection in Shale: Review of 15 Years of Experience on the Norwegian Continental Shelf and Implications for the Stimulation of Unconventional Reservoirs,” by F.J. Santarelli and F. Sanfilippo, Geomec, and R.W. James, H.H. Nielsen, M. Fidan, and G. Aamodt, ConocoPhillips, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.

Waste injection in shale, with matrix permeability in the nanodarcy range and without the presence of any permeable layers, has been performed on the Norwegian Continental Shelf (NCS) for more than 15 years. To avoid leakages to the seafloor using this method, techniques have been developed that allow wells to dispose of several million barrels into individual shale domains, with vertical propagation of the disposal domain less than 1,000 ft above the injection point. Recently, use of frequent 4D interpretations of seismic surveys shot over a permanent sensor array allowed detailed domain mapping and independent dynamic monitoring.

Historical Perspective

Changes of North Sea regulations in the mid- to late 1990s made the seabed disposal of oily cuttings and other waste from drilling and production impossible without the use of significant topside cleaning systems. Meanwhile, the development of fields required increasingly complex wells, resulting in the almost systematic use of oil-based mud for efficient drilling. This led to a dual challenge for the industry, with an increased amount of waste generated and the difficulty of discharging it. Options were then reviewed between shipping onshore and treatment or reinjection into the subsurface with cuttings-reinjection (CRI) wells (a typical design of a CRI well in the Ekofisk Field region is outlined in the complete paper). Most operators concluded that the CRI option was much safer and more economically favorable than shipping to shore and onshore treating and disposal.

A survey of all CRI wells on the NCS noted that 110 had been or were operating, with approximately 30 of them still active at the time of the survey. This confirms the attractiveness of CRI wells as a means of waste disposal, at least as far as the NCS is concerned. Unfortunately, the same survey also revealed that 14 of these 110 wells had suffered from a leakage to the seabed, thus illustrating the risks associated with CRI operations.

An outcome of the investigation was the discovery that a vast majority of the leakage-to-seafloor cases occurred in wells where shallow sand bodies were lacking or where their quality was very poor. This justifies the general strategy traditionally adopted by Norwegian operators (i.e., avoiding the upward migration of hydraulic fractures with high-permeability sand bodies); this emphasizes the risks associated with the lack of good-quality “blanket” sands above the injection point.
Big-Data Analytics for Predictive Maintenance Modeling: Challenges and Opportunities
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26275, “Big Data Analytics for Predictive Maintenance Modeling: Challenges and Opportunities,” by I.H.F. Santos, M.M. Machado, E.E. Russo, D.M. Manguinho, V.T. Almeida, R.C. Wo, M. Bahia, and D.J.S. Constantino, Petrobras; D. Salomone, M.L. Pesce, C. Souza, and A.C. Oliveira, EMC—Brazil Research Center; and A. Lima, J. Gois, L.G. Tavares, T. Prego, S. Netto, and E. Silva, PEE-COPPE/UFRJ, prepared for the 2015 Offshore Technology Conference Brasil, Rio de Janeiro, 27–29 October. The paper has not been peer reviewed.

Big-data analytics can allow a better understanding of a production system’s abnormal behavior. This knowledge is essential for the adoption of a proactive maintenance approach, leading to a shift toward condition-based maintenance (CBM). CBM focuses on performing interventions on the basis of actual and future states of a system determined by monitoring underlying deterioration processes. One of the building blocks of CBM design and implementation is the prognostic approach, which aims to detect, classify, and predict critical failures. This paper presents approaches for constructing a prognostic system.

Introduction

Optimization of maintenance costs is among operators’ main concerns in the search for operational efficiency, safety, and asset availability. The ability to predict critical failures emerges as a key factor, especially when reducing logistics costs is mandatory.

Experience has shown that significant benefits can be achieved when major maintenance interventions (overhauls, usually performed periodically) can be postponed on the basis of conclusions from the use of degradation models. Such an approach can be complex, but its results may reduce maintenance and logistics costs while keeping availability within required levels.

Traditional approaches to reliability estimations are based on the distribution of event records of a population of identical units. Many parametric failure modes, such as Poisson, exponential, Weibull, and log-normal distributions, have been used to model machine reliability. This project attempts to create an integrated solution using big data and analytics techniques to implement a CBM standard procedure for the target problem.
Flow-Assurance Methods Enabled by Medium-Voltage Heating Technology
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26389, “Flow-Assurance and Hydrate-Prevention Methods Enabled by Medium-Voltage Electric Heating Technology,” by C. Molnar and M. Riley, Chromalox, prepared for the 2016 Offshore Technology Conference Asia, Kuala Lumpur, 22–25 March. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Medium-voltage electric heating systems offer reduced installation cost and increasing efficiency for multi-megawatt oil and gas heating applications compared with low-voltage systems. For offshore applications, the systems offer the added benefit of both space and weight reductions. The technology is based on the same principles as low-voltage electrical-resistance heating that has been used in industry for the past century, but reapplied for medium-voltage use.

Introduction

Most industries use low-voltage systems, typically less than 1,000 V, for electric heating applications. These were practical for most applications through the 20th century. Now, however, many applications in heavy industries such as oil and gas, petrochemical, and chemical demand much higher power output. These applications require multi-megawatt electric heating systems. At low voltages, such requirements lead to challenges with power distribution, process design, and costs.

A viable solution involves leveraging medium-voltage power. A safe and reliable technical design for metal-sheathed electric heating and power controls exists for heating systems operating at medium voltages. These medium-voltage electric heating systems allow the oil and gas industry to capture all the advantages of electric process heat while minimizing the disadvantages of low-voltage, high-amperage designs.

Description and Application of Equipment and Processes

A medium-voltage electric heating element is capable of very large power output that can operate on voltages up to 7,200 V. Modified dielectric material formulations are capable of ultrahigh insulation resistance and enable the element to reach values in excess of 25,000 V during safety testing. These two properties deliver the performance and reliability necessary for industrial applications, even at temperatures up to 540°C.
Thermoplastic-Composite-Pipe Flowline Helps Reduce Project and Life-Cycle Costs
Authors: Wilson Adam
Published: January 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 26512, “Reduce Project and Life-Cycle Cost With TCP Flowline,” by Bart Steuten and Martin van Onna, Airborne Oil and Gas, prepared for the 2016 Offshore Technology Conference Asia, Kuala Lumpur, 22–25 March. The paper has not been peer reviewed. Copyright 2016 Offshore Technology Conference. Reproduced by permission.

Thermoplastic composite pipe (TCP) is a spoolable, fully bonded, thermoplastic pipe with glass or carbon-fiber reinforcements. The bonded composite pipe has a solid wall like steel pipe and is able to cope with corrosive environments without being affected. For its low weight and collapse resistance, TCP is most often associated with deep water. However, the combination of a solid wall, spoolability, and corrosion resistance makes TCP attractive for production-flowline applications in shallow water also.

TCP

TCP uses a one-material design concept in which the internal liner, the composite layers, and the outer coating are all of the same polymer material (Fig. 1). The pipe is made with an in-situ-consolidation manufacturing process that melt-fuses all layers together to form a strong and stiff solid wall. This produces a pipe that is collapse resistant, spoolable, lightweight, and corrosion resistant.

The orientation of the reinforcement fibers (the lay-up) can be varied for each layer, enabling an optimized design for each set of design requirements, such as internal and external pressure rating, tension capability, allowable bending radius, and fatigue performance. The flexibility and spoolability of the solid pipe are the result of the relatively high strain in the glass-fiber materials and, to a lesser extent, in carbon fibers, compared with steel. Flexibility comes at the expense of tension capacity and vice versa. Therefore, TCP that is designed for high tension (e.g., in dynamic riser applications) will have a larger minimum bend radius than TCP that is optimized for bending. In practice, bending strains of 1 to 3.5% are achieved. For example, a 7-in.-innerdiameter flowline is spooled on a 6-mbarrel- diameter storage drum and has a minimum bend radius in service of 5 m.
DEVELOPMENT OF THE INTEGRATED MODEL OF THE AUTOMOTIVE PRODUCT QUALITY ASSESSMENT
Authors: Amineh Hadi , Kosach Nataliya
Published: January 2017

Issues on building an integrated model of the automotive product quality assessment are studied herein basing on widely applicable methods and models of the quality assessment. A conceptual model of the automotive product quality system meeting customer requirements has been developed. Typical characteristics of modern industrial production are an increase in the production dynamism that determines the product properties; a continuous increase in the volume of information required for decision-making, an increased role of knowledge and high technologies implementing absolutely new scientific and technical ideas. To solve the problem of increasing the automotive product quality, a conceptual structural and hierarchical model is offered to ensure its quality as a closed system with feedback between the regulatory, manufacturing, and information modules, responsible for formation of the product quality at all stages of its life cycle. The three module model of the system of the industrial product quality assurance is considered to be universal and to give the opportunity to explore processes of any complexity while solving theoretical and practical problems of the quality assessment and prediction for products for various purposes, including automotive.
THE RESEARCH OF TECHNOLOGICAL APPROACH TO THE MODELING OF INFORMATION AND ANALYTIC PROVISION OF MANAGING AN ENTERPRISE
Authors: Bochulia Tetiana , Yanchev Andriy , Yancheva Liana
Published: January 2017

The article is devoted to the solution of actual problems of innovative development of information and analytical provision of managing an enterprise according to the newest technology. A number of recommendations concerning technological upgrading foundation of modernization of information and analytic provision of managing an enterprise are elaborated. Technological approach to the modeling of information provision of business management is substantiated. Actualizing information and analytic provision of managing an enterprise has been carried out in developed flexible information system that is organized as internal network structure. Technological foundation of information and analytical process enterprise to modernize has been considered based on the modern tools of information and communication decisions. Information and analytical provision of managing have been developed through internal and external parallels of impact, which interconnection coordinates theory, methodology and organization of information processes with actualization of its model. The model of information and analytic provision of managing an enterprise according to the individual characteristics of corporate culture, and information environment and development strategy of business entity on the basis of characteristics of technological provision of information process is developed. Information complex has been suggested as developed system with technological process of forming initial data and modernizing processing, transmission and storage of information in accordance with distinctive characteristics of enterprise and general tendencies of its development
THE TOBACCO MONOPOLY: THE WORLD AND DOMESTIC EXPERIENCE
Authors: Pasitska Oksana
Published: January 2017

The article analyses the historical and economic development of the tobacco market from its cultivation in America to the formation and operation of monopolies in European countries. The features of the tobacco market in Ukraine, from the time of origin until now, are studied. Researches testify to the fact that tobacco cultivation began in America, and in the sixteenth and seventeenth centuries tobacco production became common all throughout Europe. There were three main historical and economic ways that tobacco was brought to Ukraine: from China, Turkey and European countries. Major tobacco plantations were located in Poltava and Kherson regions, eastern Galicia and Podilia, etc. First tobacco factories as well as trading departments came into operation in the eighteenth and nineteenth centuries. As far as tobacco industry developed by leaps and bounds and brought substantial profit, tobacco production and sales volume of tobacco products were controlled on the state level by means of excise taxes and monopolies. In the first third of the twentieth century, there was a number of monopolies (among them Austrian, Polish, Hungarian, Russian and some other) that were quite successful. After the Second World War tobacco industry in Ukraine could develop on the basis of tobacco factories in Lviv, Kyiv, Cherkasy, Kharkiv, Zhmerynka, etc. and due to the import of tobacco products. In the twenty-first century, tobacco market in Ukraine has to undergo some major changes on both legislative and practical levels.
The results of this study are important for understanding the history of tobacco industry on national and international levels.
Phenotypic Analysis of Major Agronomic Traits in 1008 RILs from a Diallel of Early European Soybean Varieties
Authors: Kurasch Alena K. , Hahn Volker , Leiser Willmar L. , Starck Norbert , Würschum Tobias
Published: January 2017

Soybean [Glycine max (L.) Merr.] is the most important leguminous crop worldwide, but Europe is currently heavily dependent on soybean imports. A prerequisite for further expansion of soybean cultivation in Europe is the improvement of cultivars by breeding. In our study, 1008 F5:8 recombinant inbred lines derived from an incomplete half‐diallel cross of five early‐maturing European soybean varieties were evaluated in multilocation field trials for grain yield, thousand‐kernel weight, plant height, protein content, and oil content. We observed significant genotypic variances, high heritabilities (h2 > 0.7), and transgressive segregation for all traits. Our results further revealed complex relationships between grain yield, plant height, and maturity, but nevertheless indicated that breeding of adapted and high‐yielding varieties is feasible. By contrast, protein and oil content were not affected by maturity but were highly negatively correlated (r ∼ −0.9). Our results suggest that, to maximize protein yield, the maximization of grain yield appears to be the most promising strategy for soybeans for feeding purposes, while the selection of lines with very high protein content may be advantageous for food‐grade varieties, especially for tofu production. Taken together, our results on the available phenotypic variation, variance components, heritabilities, and trait correlations can expedite soybean breeding targeted at Central Europe.
Caesura of History: Performing Greek Tragedy after Brecht
Authors: Dreyer Matthias
Published: January 2017

Taking into account the intertwining of the theory of tragedy on the one hand and theatrical work on ancient tragic texts on the other, the paper explores the way in which tragedy poses the question of history. This is especially the case in conceptions of tragedy as an interruption in a continuum. Hölderlin’s idea of caesura, its reflection in Benjamin’s understanding of tragedy as a revision of myth are in the center of a critical dramaturgy of this kind. By analysing Brecht’s work on Antigone as well as the stagings of critical theatre makers that came after Brecht (Einar Schleef, Dimiter Gotscheff), the paper shows the consequences of the concept ‘tragedy as caesura‘ on the level of the aesthetics of the theatre, unclosing in a radical way the temporality of the tragic process. From this point of view, tragedy is understood as a site of encounter with the persisting powers of the past; as reflexive rupture in the transition between times, that undermines the established order, but without, however, arriving at a new one. Although in the history of theatre and thought tragedy has been too often associated with the universal and timeless, how is it possible to think of historicity in a way negating submission under the universal without losing the genre of tragedy itself?
Opieka onkologiczna w Wielkopolsce na tle zmian systemu ochrony zdrowia w Polsce – część 2. Wykrywanie i zaawansowanie choroby, kształcenie specjalistów i rola badań naukowych.
Authors: Malicki Julian
Published: January 2017

Choroby nowotworowe są jedną z głównych przyczyn zgonów. Wykazano, że profilaktyka i wczesna diagnostyka należą do najbardziej efektywnych kosztowo działań w zmniejszeniu umieralności z powodu nowotworów.W Polsce brakuje lekarzy radioterapeutów oraz onkologów klinicznych i dlatego obie te specjalizacje są zdefiniowane jako deficytowe.Większość świadczeń onkologicznych udzielana jest w dużych ośrodkach onkologicznych lub klinikach uniwersyteckich. W mniejszych miastach dostępność do nawet podstawowych świadczeń onkologicznych jest znacznie gorsza i brakuje kadry specjalistów. W onkologii, będącej dyscypliną akademicką bardzo ważne są również związki pomiędzy nauką i praktyką kliniczną. W ostatnich dziesięciu latach zaszły pozytywne zmiany w nauczaniu onkologii w uczelniach medycznych. Obecnie studenci medycyny stykają się z nauczaniem onkologii już na wcześniejszych latach studiów. Z punktu widzenia planowania zakresu niezbędnych świadczeń onkologicznych i ich dostępności oprócz zapadalności istotny jest stopień zaawansowania wykrytych nowotworów. W Wielkopolsce zainicjowano program wczesnego wykrywania nowotworów głowy i szyi, który działa od roku. Jest zalążkiem programu ogólnopolskiego w wyniku którego powołano koordynatorów we wszystkich województwach.