bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
Technology Focus: Water Management (December 2016)
Authors: Ali Syed A. 
Published: January 2017

Technology Focus
Considering the current downturn in crude prices, there is a renewed interest in recycling produced water for reuse in hydraulic fracturing in the development of unconventional resource plays. As the hydrocarbons are produced, large quantities of water containing high amounts of total dissolved solids (TDS) are also produced in the process. Most of the produced water usually is reinjected into disposal wells. This practice has become a topic of public concern after reports of earthquakes began approximately 5 years ago in the central United States, where disposal wells are heavily used. Reusing produced water as the base fluid for hydraulic fracturing not only alleviates the operators’ dependence on fresh water but also lowers the overall cost of fracturing treatments.
Produced water usually is composed of natural formation water and flowback water. Flowback water is water that was a large component of fracturing fluids injected into a well at high pressure as a part of the hydraulic-fracturing treatment. Within a few hours to a few weeks after the fracturing job is completed, a portion of the injected water returns to the surface. It typically contains much higher levels of chemical constituents, including TDS, than the original fracturing fluid did.
The amount of produced water, and the chemical constituents (i.e., anions and cations) and their concentrations present in the produced water, usually varies significantly over the lifetime of a field. Early in the process, the water-generation rate can be a small fraction of the oil-production rate, but it can increase with time to tens of times the rate of oil produced. Compositionally, the changes are complex and field-specific because they are a function of formation mineralogy, oil and water (both in-situ and injected) chemistry, rock/fluid interactions, type of production, and the required additives for oil-production-related activities.
To reuse the high-TDS produced water as a base fluid for formulating crosslinked-gel-based fracturing fluids, the water must first be treated to remove ions that hinder the development of crosslinked fluid or that cause scale buildup in the wellbore. An ideal solution would be to reuse the high-TDS produced water in subsequent fracturing treatment with no treatment or fit-for-purpose treatment.
The papers featured this month deal with a fit-for-purpose treatment of produced water, a new guar-based system that allows the use of 100% produced water without treatment as a base fluid, and produced-water reinjection. I hope you enjoy reading the selected papers and search for additional papers in the OnePetro online library.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 175206 Produced-Water Injection—The Challenges Faced by N. Bhola, Jorin, et al.
SPE 177067 The Integrated Approach to Formation-Water Management Part 2: Field Applications and Best Practices by R. Correa, AGIP Oil Ecuador, et al.
SPE 181588 Reuse of Produced Water by Membranes for Enhanced Oil Recovery by Remya Ravindran Nair, University of Stavanger, et al.
Employment Status, Anxiety and Depression in a Municipal Context
Authors: Hiswåls Anne-Sofie , Walander Anders , Soares Joaquim , Macassa Gloria 
Published: January 2017

Objectives: This study aimed to investigate the prevalence of anxiety and depression by employment status among a sample of the working age population residing in Gävle Municipality in Sweden.
Methods: A total of 241 persons completed a self-administered postal questionnaire in the baseline survey of the Gävle Household, Labour Market and Health Outcomes (GHOLDH) survey, which collected information on the employment status and psychological health (anxiety and depression) among persons aged 18-65 years. Descriptive and multivariate analyses were performed.
Results: The prevalence and risk of anxiety and depression were high among people who were out of work. In the multiple regression analysis, compared to employed people, those who were not employed had a risk of anxiety of 7.76 (5.97-9.75) and 4.67 (3.60-5.74) for depression.
Conclusion: The prevalence of anxiety and depression was higher among those who were out of labour market as compared to those employed. Furthermore, people who were out of work had a higher risk of anxiety and depression. The odds were slightly higher for anxiety than for depression.
Alterations in conjunctival bacteria and antimicrobial susceptibility during topical administration of ofloxacin after cataract surgery in dogs
Authors: Sandmeyer Lynne S. , Bauer Bianca S. , Mohaghegh Poor Seyed Mohammad , Feng Cindy Xin , Chirino-Trejo Manuel 
Published: January 2017

Abstract
OBJECTIVE To evaluate changes in conjunctival bacteria and antimicrobial susceptibility of bacteria after cataract surgery in dogs.
ANIMALS 16 client-owned dogs.
PROCEDURES Samples for aerobic and anaerobic culture were obtained from the conjunctival fornices of both eyes of dogs 24 hours before (week 0) and 1, 3, and 6 weeks after cataract surgery. Topical administration of ofloxacin (every 6 hours) was initiated 12 hours before surgery and continued for 3 weeks. In vitro antimicrobial susceptibility was determined by Kirby-Bauer disk diffusion and a commercially available test for ofloxacin.
RESULTS Frequency of positive culture results was significantly higher at week 6 than at weeks 0 and 1. Bacterial load was more likely to be moderate or high at weeks 3 and 6 than at weeks 0 and 1. The most frequently cultured organism was Staphylococcus pseudintermedius (21/78 [26.9%]), followed by coagulase-negative Staphylococcus spp (19/78 [24.4%]). Staphylococcus pseudintermedius was the organism most frequently cultured at weeks 0 (5/12), 1 (4/12), and 6 (8/19), whereas frequency of this organism was lowest at week 3 (1/20). In contrast, coagulase-negative Staphylococcus spp were the most frequently cultured organisms at week 3 (10/20). There was a significant increase in the proportion of organisms resistant to ofloxacin at week 3, compared with the proportion at week 0.
CONCLUSIONS AND CLINICAL RELEVANCE The number of bacterial organisms increased and the population of conjunctival bacteria was altered and had a higher proportion resistant to ofloxacin during the 6 weeks after cataract surgery for dogs treated by use of this protocol.