bluuebunny/crossref_metadata_2025_split huggingface dataset:
Team Approach: Perioperative Optimization for Total Joint Arthroplasty
Authors: Feng James E. , Novikov David , Anoushiravani Afshin A. , Wasterlain Amy S. , Lofton Holly F. , Oswald William , Nazemzadeh Milad , Weiser Sherri , Berger Jeffery S. , Iorio Richard 
Published: October 2018

* With the shift toward value-based patient care, greater emphasis has been placed on improving patient outcomes, reducing complications, and minimizing hospital costs. Optimal care therefore requires a multidisciplinary approach for perioperative patient optimization and episode management.* Here we review the case of a 48-year-old woman with symptomatic osteoarthritis of the left hip and multiple medical comorbidities. We present appropriate optimization guidelines from a panel of multidisciplinary experts in their respective specialties.* Continued clinical research is critical with regard to perioperative optimization and disease episode management as part of population health initiatives and will enable us to better identify at-risk patients early in the process. This will promote the development of improved evidence-based screening criteria and guidelines allowing for the optimization of patient outcomes, safety, and satisfaction following total joint arthroplasty.* Historically, surgical risk stratification methods have emphasized the appraisal of non-modifiable risk factors. Consequently, this has incentivized surgeons to operate on healthy, low comorbidity burden patients, while avoiding surgical intervention on unhealthy, high-comorbidity patients. Only recently has the medical optimization of high-risk candidates undergoing total joint arthroplasty demonstrated improved outcomes by reducing hospital readmissions when patients undergo total joint arthroplasty after optimization.
Heat transfer in the mold during vertical continuous casting of steel
Authors: Marukovich E. I. , Demchenko E. B. 
Published: October 2018

The analysis of the performed researches has shown that the offered calculation technique is an effective means of management of formation process in casting. The found dependences and experimental data allow to calculate the specific value of the exactм heat flux in a given range of technological parameters obtained during a series of successful experiments for a particular casting method.Having the results of studies of the temperature regime of the mold during casting of a certain size and profile, it is possible to calculate the thermal state of the mold for the same casting process, but for the production of castings of any other size and profile.Having a certain amount of information on the temperature regime of the mold at different casting methods, you can use the solutions obtained to become the owner of a database containing the necessary information for solving the problems of solidification of the casting. In the subsequent design of equipment and equipment there is no need for additional experimental studies and analysis of the results.
Community Consensus: Thank You, It’s Been a Great Ride
Authors: Spady Darcy 
Published: October 2018

President's column
My year as your SPE 2018 president
Wow. One hundred twenty-four speeches and counting, 39 countries visited, millions of excited volunteers (estimated from good feelings that I have had).
Life is grand. … My knees are really sore. There are bags under my eyes. What’s left of my hair is way grayer than when I started. I’ve busted two of my four accordions from travel stress, and I’m not sure if I have slept properly in about a year.
These are the thoughts that have run through my head as I have had the great honor, rather the great honor, of serving you as your SPE 2018 president. What a ride! I am so humbled.
As I prepare to pass the torch over to my eminently well qualified successor Sami Alnuaim, (a way smarter guy than me) I do so with an immensely thankful heart. I have learned so much. I have been surprised many times. I have been disappointed almost never. What a great bunch of members SPE is proud to call its own.
It is hard to describe the gravity and responsibility of leading this society. With almost 160,000 really great people—all contributing something unique, all are really smart and work really hard—it’s no wonder why we are an industry that is one of the most technical on the planet. There are a really smart bunch of folks working in it. From Kavala, Greece, to Adelaide, Australia, I have been constantly surprised with the wonderful people we call members. I am so unworthy to represent such a group. I only hope that I have chaired the board without prejudice and fostered the robust activities that we undertake.
People—we, the SPE—set the standard that defines the process that provides the majority of the world’s energy needs. We are the global experts who give the planet home heating, products such as plastic, energy to power our cars, and a myriad of life improvements.
Technology Update: Seismic Stimulation: An Eco-Friendly, Effective EOR Alternative
Authors: Wooden Bill 
Published: October 2018

Technology Update
Environmental and economic concerns have led to an increased interest in seismic stimulation as an alternative enhanced oil recovery (EOR) methodology. Seismic stimulation, achievable with the implementation of a single tool, requires significantly lower investments than gas, thermal, and chemical injection methods, while making minimal environmental impact.
Applied Seismic Research (ASR), based in McKinney, Texas, has placed more than 200 of its proprietary seismic stimulation tools in more than 50 locations, including fields in Arkansas, California, Canada, Egypt, Kansas, Mexico, Oklahoma, Oman, and Texas. This article will examine the operation of the tool and highlight the EOR results achieved in a variety of formations.
What is Seismic Stimulation?
Seismic stimulation is the harnessing of low-frequency, high-energy elastic waves to mobilize oil. The method’s origins trace back to the 1950s when it was noticed that natural earthquakes could increase oil production by up to 45%. Attempts in the 1980s to duplicate earthquake effects by the use of surface vibrators above a targeted zone were largely unsuccessful and commercially unviable. Later development of tools that generate subsurface shockwaves proved more promising. ASR received the first patent for its technology in 2000.
A “Greener” EOR Method
In-situ seismic stimulation may be one of the greenest EOR options available. The method doesn’t involve injecting any amount of potentially harmful fluids or chemicals into the earth or dealing with the byproducts created by other EOR methods. In fact, it is implemented in a completely closed wellbore having no hydraulic communication with the formation. It can offer a measure of relief to field operators grappling with issues including managing groundwater contamination from harmful chemicals; dealing with the treatment, transport, and disposal of high volumes of contaminated wastewater; and/or handling the environmental consequences of the intense energy and carbon use occasioned by thermal injections.
How the Tool Works
The seismic stimulation tool (Fig. 1), which has a lifespan of up to 1.5 years and typically requires no maintenance, is powered by a conventional pumping unit and can be installed in abandoned wells at depths from 700 to 10,000 ft. It is relatively easy to transport to wellsites, coming in three preassembled segments in a single crate. The tool is installed into an abandoned wellbore, connected to a rod string and then to a pumping unit. The pumping unit drives movement of three plungers within the tool in unison. The lowest plunger contains a traveling valve to bring in fluids. When the plunger reaches the top of its stroke, it exits the lower barrel to release highly compressed fluids, creating the elastic waves.
In the Battle Against Frac Hits, Shale Producers Go to New Extremes
Authors: Jacobs Trent 
Published: October 2018

A new plan has been put to work in the Permian Basin’s remote but resource-rich swath of land shared by Texas and New Mexico.
Its objective can be reduced to this simple idea: protect neighboring horizontal wells from each other by drilling and completing them at the same time.
Most in the shale business know these projects as “cube developments.” Their scope of work has moved operators away from developing wells one at a time to a half dozen or more at a time. Each cube project is done from supersized well pads that host four to six rigs, two pressure pumping fleets, and hundreds of people every day.
From the surface perspective, these onshore megaprojects are delivering much needed economies of scale on everything from sand and water to parts and labor. However, the bigger motivation lies deep in the ground.
That is where shale producers have been battling poor production results for years because of frac hits between older and newer wells, often referred to as “parent” and “child” wells. The root of this complex problem lies in the fact that a child well’s hydraulic fractures often follow the path of least resistance into a reservoir’s most resource-depleted zones, rather than to areas containing the best reserves.
In some parts of the Permian, the effect has caused child wells to deliver a 30% lower recovery rate than their parents (when factors such as well lengths are normalized). When such production shortfalls are felt fieldwide, the losses are measured in millions of dollars per day. The point of cube developments is to put an end to this cycle by creating only parent wells.
Thinking Inside the Cube Occidental Petroleum began implementing its own version of the cube approach—called “optimized sequenced development”—last summer at its Greater Sand Dunes project in New Mexico. This year, the Permian stalwart says new wells brought on line there have turned in “basin-leading” peak 30-day rates that averaged around 3,100 BOE/D.
The Houston-based firm’s approach relies on a strong understanding of geomechanics to sequence the drilling, completion, and eventual flowback of multiple wells to mitigate frac hits. This allows some wells to be produced, while others nearby are still being drilled or hydraulically fractured, said Oscar Quintero, the president and general manager of Oxy’s Permian assets in New Mexico.
If done correctly, and critical rock properties are entered into the equation, then “you have vertical isolation, and you have horizontal isolation” of each well’s hydraulic fracture growth, said Quintero. “So, by design, we are avoiding the impact of frac hits.”
This succinct outline of the high-density approach boils down a long list of subsurface nuances, ones that remain an intense area of study for the shale sector. Understanding them helps explain why Oxy and a growing number of its peers would go to the lengths of drilling so many wells simultaneously.
Cybersecurity for Upstream Operations
Authors: Wilson Adam 
Published: October 2018

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28121, “Cybersecurity for Upstream Operations,” by Mohammed A. AlGhazal, SPE, and Mohammad J. AlJubran, SPE, Saudi Aramco. The paper was prepared, but not presented at the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
During well drilling and completion, cybersecurity is critical for securing data to prevent hacking or the loss of software programs. Paying attention to data flow, with the goal of protecting the data as well as the facility, while developing capabilities to deal with intrusions is important. This is the essence of cybersecurity and operational leadership. This paper emphasizes the value gained by investing in cybersecurity for drilling, workover, and completion operations.
Introduction
Countless engineering and research projects have addressed cybersecurity for downstream operations. Other works have discussed remote upstream operation models along with data flow and information management that have been implemented to digitize the upstream industry, moving it to a new level of automation, efficiency, and improved overall performance. The benefits of the transforming digitization include assurance, cross-organizational collaboration, leveraging of knowledge, and safer operations with minimal human presence on the well site because of remote control. On the other hand, sensors, controls, and networks are added when intelligence is added. This digital expansion creates vulnerability and more entry points—back doors—to exploit defects and weaknesses. One of the reasons for this proliferation of weaknesses is that no logical system can describe a physical system perfectly because too many pieces are involved.
The Pressing Threat
Upstream oil and gas represents the world’s largest supply chain, involving numerous subcontractors who supply equipment, fluid, and other services to the operating company. The life of upstream assets and resources lasts for decades with multiple time scales for different facilities.
Threats and security defenses continuously evolve and change, but much of a facility does not. This makes cybersecurity of long-lived assets very complex, especially because decisions taken will last a long time and be costly. Additionally, the extended reach of oil and gas infrastructures into remote operational areas creates vulnerability and security exposures alongside environmental risk. Accidents in such extended facilities result in liability increases, revenue losses, and the loss of safety standing with society and authorities.
While substantial emphasis has been placed on physical security for decades, cybersecurity is still evolving and is building an experience curve as threats keep moving.
AI Firm Ambyint’s New Bakken Deal With Equinor Moves the Industry Another Step Closer to the Edge
Authors: Jacobs Trent 
Published: October 2018

In the face of leaner economic times, oil and gas companies want to be able to boost well counts while minimizing any new additions to their field workforce.
Among the companies answering this call is Ambyint, which was just tapped to deploy its artificial intelligence (AI) systems to help optimize all of Equinor’s Bakken Shale wells running on sucker rod pumps—the oil field’s most common breed of artificial lift.
The deal is understood to be one of Ambyint’s largest contracts to date. Specific numbers have not been shared, but public data show that Equinor operates more than 800 wells in North Dakota. Ambyint, which is headquartered in Calgary and has an office in Houston, said the project scope may eventually include all of the Norwegian-owned operator’s horizontal wells in the state as they transition to rod pump.
The large-scale upgrade marks another milestone in the evolution of oilfield automation that for decades has been defined by a nearly-ubiquitous reliance on SCADA (supervisory control and data acquisition) systems.
One of the drawbacks of the status quo is that it requires small armies of field personnel to interpret SCADA data and then adjust setpoints to get pumping units back into optimal operating ranges. This manual process can consume half an hour per well to complete; downtime that quickly adds up in a field of hundreds.
“What we are talking about is having the machine do that entire workflow,” Chris Robart, Ambyint’s president of US operations said.
By equipping wells with its cloud-based AI and edge computing technology, and an application the company calls an autonomous setpoint management system, the man-hours once spent re-setting pumps can hopefully be reallocated to other bottom-line drivers. “We are freeing up individuals to go do other things, like think about new technology, troubleshoot failed equipment, deal with workovers, or new well designs,” Robart added.
Pilot Hits the Mark for Equinor The Bakken project comes after a pilot that included 50 of Equinor’s wells, which saw a net production increase of 6%—considerably larger uplift figures were seen from those wells suffering from underpumping.
The encouraging results were realized with zero shutdowns in production and minimal “human interference,” according to the companies.
“The Ambyint technology has improved the remote data visibility and has delivered a more accurate diagnostic of downhole conditions to our rod pump wells in the Bakken,” a production engineer for Equinor’s Bakken asset, Jack Freeman, said in a statement. “The autonomous speed range management tool has leveraged the power of machine learning to optimize our wells by identifying and acting on real opportunities”
Last year, Ambyint’s Series A funding round raised $11.5 million from several venture capital groups including Equinor Technology Ventures (formerly known as Statoil Technology Invest).
Productivity-Maximized Horizontal-Well Design With Multiple Acute-Angle Transverse Fractures
Authors: Sorek Nadav , Moreno Jose A. , Rice Ryan N. , Luo Guofan , Ehlig-Economides Christine 
Published: October 2018

SummaryHydraulic fractures propagate perpendicular to the horizontal-well axis whenever the drilling direction is parallel to the minimum-principal-stress direction. However, operators frequently drill horizontal wells parallel to lease boundaries, resulting in hydraulic-fracture vertical planes slanted at angles less than 90° from the well axis.The stimulated-rock-volume (SRV) dimensions are defined by fracture height, well length, and fracture length multiplied by the sine of the angle between fracture planes and the horizontal-well axis (fracture angle). The well productivity index (PI) under boundary-dominated flow (BDF) is given by the PI for one fully penetrating fracture multiplied by the number of fractures. An extension of the unified-fracture-design (UFD) approach for rectangular drainage areas enables determination of the unique number of fractures that will maximize well productivity under BDF conditions given the formation permeability, proppant mass, fracture angle, and well spacing. Fracture length and width vary depending on the fracture angle, but the total-propped-fracture volume remains constant.Because the likely reason for drilling at an angle to the minimum-stress direction is to better cover a lease area with north/south and east/west boundaries, the smallest fracture angle will be 45°, corresponding to northwest/southeast or northeast/southwest minimum-stress direction. This results in the need to lengthen fractures by at most 40% to preserve the SRV for a given horizontal-well length and spacing. For the same sufficiently large proppant mass, this will reduce fracture conductivity by the same factor. However, because the flow area has increased, the result will be greater well productivity.This study shows a simple strategy for designing wells to maximize productivity even when not drilled in the minimum-stress direction.
Drill and Learn: A Decision-Making Work Flow To Quantify Value of Learning
Authors: Hanea R. G. , Casanova P.. , Hustoft L.. , Bratvold R. B. , Nair R.. , Hewson C.. , Leeuwenburgh O.. , Fonseca R.-M.. -M. 
Published: October 2018

Summary
The goal of reservoir management is to make decisions with the objective of maximizing the value creation from oil or gas production. To achieve this, models that preserve geological realism and have predictive capabilities are being developed and used. These models are commonly calibrated using assisted-history-matching (AHM) methods which, in general, will lead to reduced uncertainty in the predicted production. Although uncertainty assessment and reduction are often elements of high-quality decision making, they are not value-creating. Value can only be created through decisions, and any decision changes resulting from AHM should be modeled explicitly. Recently, there has been a surge in the application and understanding of value-of-information (VOI) work flows for reservoir management. In this text, we present a comparison of existing work flows and note the differences between them. After this, we introduce a practically driven approach, referred to as “drill and learn,” with elements and concepts from existing work flows to quantify the value of learning (VOL). VOL can be used as a metric to quantify the potential of such work flows and the strategies obtained. Ensemble methods [ensemble smoother with multiple data assimilation (ES-MDA) and stochastic simplex approximate gradient (StoSAG)] are used for the history matching and optimization. The results presented are obtained by applying the proposed drill-and-learn work flow on a realistic synthetic case. Sensitivities to the amount of information obtained before a closed-loop exercise is performed are also investigated. We show the benefit of performing the closed-loop approach to quantify the VOL to modify field-development decisions, which leads to a mature and robust decision-making framework.
Smartwater Synergy With Chemical Enhanced Oil Recovery: Polymer Effects on Smartwater
Authors: AlSofi Abdulkareem M. , Wang Jinxun , AlBoqmi Abdullah M. , AlOtaibi Mohammad B. , Ayirala Subhash C. , AlYousef Ali A. 
Published: October 2018

Summary
The synergy between various enhanced-oil-recovery (EOR) processes has always been raised as a potential optimization route for achieving a more-economic and more-effective EOR application. In this study, we investigate the possible synergy between polymer and smartwater flooding for viscous-oil recovery in carbonates. Although the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more-realistic framework: part of the development of an EOR portfolio for a slightly viscous Arabian heavy-oil reservoir. In this work, we study the possible synergy between smartwater and polymer flooding by performing rheological, electrokinetic potential (ζ-potential), contact-angle, interfacial tension (IFT), and recovery experiments.
Rheological tests, as expected, demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With smartwater, the polymer concentration required to achieve a target viscosity of 11 mPa·s was found to be one-third lower than that with normal high-salinity injection water. Electrokinetic-potential and contact-angle results demonstrated that polymer presence has negligible to slightly favorable effect on wettability alteration induced by smartwater. On synthetic calcite surfaces, polymer showed negligible effect, whereas on reservoir-rock surfaces, polymer resulted in further reduction in contact angles beyond that obtained with smartwater.
Coreflooding experiments conducted at reservoir conditions with finite smartwater/polymer slugs—besides yielding comparable performance to surfactant/polymer flooding—demonstrated the enhanced performance of smartwater/polymer compared with either of these individual processes. A combined smartwater/polymer process was able to recover substantial additional oil—6.5 to 9.9% original-oil-in-core (OOIC)—above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of smartwater/polymer (70% OOIC) were quite comparable to, and actually slightly higher than, that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) after polymer flooding, both processes (smartwater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively.
The results of this work clearly demonstrated the potential synergy between smartwater and polymer flooding—beyond that of the well-established polymer-viscosity enhancement—for a realistic scenario. The additive effect of smartwater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. This favorable synergy will reduce chemical-consumption costs and improve recovery to enhance EOR-project economics.