bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Update: Adjustable, Supramolecular Viscosity Modifiers as Displacement Fluids in EOR
Authors: Akbulut Mustafa , Temizel Cenk 
Published: May 2017

Technology Update
We report a novel type of viscosity modifier relying on the supramolecular assemblies that have pH-adjustable viscosities and robust tolerance against high temperatures and salinities, and are resistant to shear-induced degradation. This technology is developed collaboratively by Texas A&M University, Incendium Technologies, and VaalbaraSoft.
When reservoir oil is displaced by plain waterflooding, the injected water fingers through the reservoirs because of the high mobility ratio (Rachford Jr. 1964). Water fingers leave most of the oil behind, which leads to inefficient oil recovery. Hence, the viscosity modifiers are often added in the displacing fluid, (i.e., water) to better match the viscosity of reservoir oil and enable a uniform advance of the waterfront to effectively sweep the reservoir oil.
Currently, for oil recovery applications, most commonly used viscosity modifiers are water-soluble polymers such as hydrolyzed polyacrylamide, polyvinyl alcohol, and poly(vinylpyrrolidone) (Taylor and Nasr-El-Din 1998). Likewise, water-soluble biopolymers, in particular polysaccharides such as xanthan and guar, are also used in some fields (Alquraishi and Alsewailem 2012).
Current Technology Limitations
While the above-mentioned viscosity modifiers can satisfy part of the oil recovery needs, these polymers still experience some challenges that hinder their effectiveness. For example, when the viscosity of reservoir oil is high, so should the displacing fluid be to match the mobility ratio. The current heuristics suggest that polymer flooding should be applied in reservoirs with oil viscosities between 10 and 150 cP (Taber et al. 1997).
The key factor limiting the recommended range is that for oil viscosities greater than 150 cP, the injected-water-viscosity values required for a favorable mobility ratio correspond to prohibitively low values of polymer injectivity. In addition, pumping high-viscosity displacing fluids tends to lead to clogging in oil wells, which results in a major economic well operating loss.
One potential solution is to use dis-placement fluids with an adjustable viscosity, with the fluid having a low viscosity at the injection site and a high viscosity upon reaching the oil phase. Furthermore, having an adjustable-viscosity displacement fluid can help to reduce pumping-related operational costs because pumping efficacy generally decreases as fluid viscosity increases. The above-mentioned polymers do not offer viscosities that can be controlled in such a fashion.
The Future of the Oil Sands Depends on One Thing: Totally Rethinking Everything
Authors: Rassenfoss Stephen 
Published: May 2017

Shell and Marathon have agreed to sell most of their oil sands operations. Exxon Mobil recently removed 3.5 billion bbl of the ultraheavy crude from its proved reserves because it no longer plans to develop them any time soon, following a similar move by ConocoPhillips.
In a world with a surplus of oil production options, the oil sands suffers because the cost of development is high and the value of ultraheavy crude is low, with oil sands bitumen selling for USD 15/bbl less than the benchmark for light crude, and these projects require big financial commitments stretching out for decades.
“They (oil sands) are the most expensive kid on the block and that is not a good place to be,” said Ron Sawatzky, a principal researcher for InnoTech Alberta, and chair of the SPE Canada Heavy Oil Technical Conference. “US shale producers are the biggest competitors for oil sands. We cannot match the nimbleness of those guys.”
Among those competitors are ExxonMobil and ConocoPhillips, with large operations in unconventional plays in the US and Canada and significant oil sands operations.
“We are seeing the same technologies and innovations driving lower costs and greater opportunities,” in the oil sands, Ryan Lance, chief executive officer at ConocoPhillips, said during a presentation at the March CERAWeek conference in Houston. But he keeps asking his oil sands team: “How can you do projects with a 3–5-year cycle time so you can adapt” to a business with big unexpected price swings.
Those who work in the oil sands are learning how to react faster to prepare for when oil may again be in short supply. “At Suncor we will spend around USD 200 million on technology in 2017 because business as usual does not cut it,” said Gary Bunio, general manager, strategic technology for oil sands, at Suncor. “We are working on things we will put in over a couple years, and things that will take a decade.”
The payoff for reviving future growth is huge—oil sands resources are estimated at 135 billion bbl according to the US Energy Information Administration—and there is cash flow to invest in technology. Efficient producers such as Suncor have reduced operating costs to turn a profit with oil prices as low as USD 35/bbl.
Technology Focus: Offshore Drilling and Completion (April 2017)
Authors: Rylance Martin 
Published: May 2017

Technology Focus
Intervention-free wells, intelligent completions, automated and selective smart tools—this veritable buzzword bingo several years ago offered the real promise of some advancement but, unfortunately, mostly delivered consistent failure and disappointment. That was a period when the industry was littered with a swath of great technologies, but they were deployed in such a haphazard and almost incoherent way that they were surely doomed to failure from the offset. Although these technologies often were presented as magic-bullet solutions, few of their trials considered the necessary detail of the greater system within which they were deployed and functioned, an approach that ultimately tainted their delivery and results.
That has since changed. In the present day, the industry has developed a deep and healthy respect for systems-engineering processes and the associated full considerations during the deployment and trial of new technologies and techniques. The result of this uptake has been a significant improvement in the successful use and broader deployment of these automating, enhancing, and attractive technology options.
This month, I would like to showcase just a handful of the studies that demonstrate deployment of such solutions within long-established and mature systems where they have been considered in an integrating, sympathetic, and, as a direct result, highly successful way. This overall-system appreciation and consideration has finally allowed these enhancements and technologies to enjoy their newfound and sustained success.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 26736 Remotely Operated Barrier Valve Provides Interventionless Solution for Offshore Vietnam Completion Campaign by Bruce McLeod, Halliburton, et al.
SPE 181070 A Case Study on Remotely Operated Intelligent Bridge Plugs for Plug-and-Abandonment Operations by Zac Suresh Arackakudiyil, Halliburton, et al.
OTC 27222 The Successful Development and Installation of a New Single-Trip Multizone Completion System Developed for the Deepwater Gulf of Mexico Lower Tertiary Formation by Tommy Grigsby, Halliburton, et al.
Fiber-Optic Leak-Detection Project
Authors: Carpenter Chris 
Published: May 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 183137, “Fiber-Optic Leak-Detection Project,” by Marc Baqué, Total, prepared for the 2016 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 7–10 November. The paper has not been peer reviewed.
The objectives of the Fiber-Optic Leak-Detection (FOLD) project, carried out in Verneuil-en-Halatte, France, were to assess the capability of fiber-optic sensing to detect a small gaseous leakage on a buried pipe, give guidelines regarding the best deployment positions of the fiber along the pipe, compare the performance of several methodologies, and assess the impact of the fiber-optic length on the detection performance.
Buried Pipe and Nozzle Orifices
The 30-m-long pipe used for the testing campaign was typical of those used for gas transportation. It was made of steel and had an internal diameter of 390 mm. As are many in-service pipelines installed during the last century, it was originally coated with coal-tar enamel. This coating was removed before burying the pipe.
All leakages were simulated from the external surface of the pipe. As opposed to the real conditions, this pipe was not filled with pressurized gas but was rather used as a simple cylindrical envelope aimed at accommodating all lines feeding the different leakages with gas. There were 12 nozzle orifices on the pipe, thereby permitting investigation of four different release diameters (1, 3, 5, and 7 mm) and three different release directions (upward, sideways, and downward).
For ease of tracking, each row of nozzle orifices along the pipe was attributed to a given release diameter. In addition, to avoid any important deterioration of the soil that may influence the experimental results between two neighboring orifices, the following sequence was adopted for the orifices: 1, 5, 3, and 7 mm. The first and last rows were located 5 m from the ends of the pipe. All rows were equally distributed along the remaining distance of the pipe.
Main Line
The main line was made of stainless steel and had a nominal size of 1 in. (Fig. 1). This corresponds to inner and outer diameters equal to 24.3 and 33.4 mm, respectively. A dome- loaded pressure reducer (DLPR) driven in by a driving pressure reducer (DPR) was used to adjust the gas pressure to the desired value at the nozzle orifice. Downstream of the equipment, there was a pneumatic remotely operated valve (ROV) that allowed triggering the release remotely. Gas then flowed through two different branches of the main line, depending on which nozzle orifice was being tested: one for Valve 1 and 5 mm and the other for Valve 3 and 7 mm. This was controlled by means of a manual valve (MV) located at the entry of each branch (MV3 and MV4 in Fig. 1). The vent line was used only during the main-line-purging operations. This purging was performed with nitrogen after each test.
Application of MPD Technology for HP/HT Wells in Vietnam
Authors: Carpenter Chris 
Published: May 2017

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 180637, “Best Practices and Lessons Learned on the Application of Managed-Pressure-Drilling Technology for High-Pressure/High-Temperature Wells in Vietnam,” by Bao Ta Quoc, Tan Chai Yong, Harpreet Kaur Dalgit Singh, and Vi Pham Nguyen, Weatherford, prepared for the 2016 SPE Asia Pacific Drilling Technology Conference and Exhibition, Singapore, 22–24 August. The paper has not been peer reviewed.
One common issue among operators in determining whether to install a managed-pressure-drilling (MPD) system for a campaign is the significant upfront cost. However, through detailed cost/benefit analysis and examination of lessons learned, it becomes clear that the benefits in operational safety, drilling optimization, and nonproductive-time reduction through the use of MPD significantly outweigh the cost. The complete paper discusses lessons learned and best practices of MPD technology in relation to high-pressure/high-temperature (HP/HT) wells drilled in Vietnam.
Preparation for MPD: Constant-Bottomhole-Pressure (CBHP)
Drilling in an HP/HT Environment HP/HT drilling activities offshore Vietnam commonly experience a narrow margin between formation pore pressure and fracture gradient, in which variation in bottomhole pressure (BHP) can increase the risk of an underbalance during static wellbore conditions and lead to a higher chance of fracturing the formation in dynamic conditions. Thus, a detailed hydraulics analysis was performed with a proprietary software to simulate several scenarios at the casing shoe, at the peak-pore-pressure point, and at the target depth of the 12¼-in.-hole section.
Formation prognosis for Well A showed a converging pore-pressure/fracture-pressure (PP/FP) window with depth; therefore, hydraulic modeling and analysis were performed by choosing the pivot point set at bit/total depth, and the loss of annular friction during pumpoff events would be compensated for on the basis of selection of pressure at this point. The flow behavior during MPD-CBHP application was simulated to define the circulating parameters that will be used while drilling. These parameters will maintain the dynamic BHP within the PP/FP window, which will be evaluated as the drilling progresses by adjusting surface backpressure (SBP) through the automated MPD choke manifold.
The hydraulics analysis approaches were used to
Establish bottomhole equivalent circulating density (ECD) when drilling the 12¼-in.-hole section with planned mud weight at different pump rates and values of rev/min.
Simulate to identify effect of thermal expansion and hydrostatic-column compression of planned mud rheology used in static wellbore condition.
Simulate to determine equivalent static density (ESD) during pump-off event.
Maintain an overbalanced BHP during circulation and pump-off event.
Determine annular SBP required for the planned MPD application.
A Peridynamics Model for the Propagation of Hydraulic Fractures in Naturally Fractured Reservoirs
Authors: Ouchi Hisanao , Katiyar Amit , Foster John T. , Sharma Mukul M. 
Published: May 2017

Summary
A novel and fully coupled hydraulic-fracturing model derived from a nonlocal continuum theory of peridynamics is presented and applied to the hydraulic-fracture (HF) propagation problem. It is shown that this modeling approach provides an alternative to finite-element and finite-volume methods for solving poroelastic and fracture-propagation problems. In this paper, we specifically investigate the interaction between an HF and natural fractures (NFs). The peridynamics model presented here allows us to simulate the propagation of multiple, nonplanar, interacting fractures and provides a novel approach to simulate the interaction between HFs and NFs. The model predictions in two dimensions have been validated by reproducing published experimental results where the interaction between an HF and an NF is controlled by the principal-stress contrast and the approach angle. A detailed parametric study involving poroelasticity and mechanical properties of the rock is performed to understand why an HF becomes arrested or crosses an NF. This analysis reveals that poroelasticity, resulting from high fracture-fluid leakoff, has a dominant influence on the interaction between an HF and an NF. In addition, the fracture toughness of the rock, the toughness of the NF, and the shear strength of the NF also affect the interaction between an HF and an NF. We also investigate the interaction of multiple completing fractures with NFs in two dimensions and demonstrate the applicability of the approach to simulate complex fracture networks on a field scale. Finally, the 3D interaction study elucidated that the height of the NF, the position of the NF, and the opening resistance of the NF all have a significant effect on the 3D interaction between an HF and an NF.
Use of Annual Phosphorus Loss Estimator (APLE) Model to Evaluate a Phosphorus Index
Authors: Fiorellino Nicole M. , McGrath Joshua M. , Vadas Peter A. , Bolster Carl H. , Coale Frank J. 
Published: May 2017

The Phosphorus (P) Index was developed to provide a relative ranking of agricultural fields according to their potential for P loss to surface water. Recent efforts have focused on updating and evaluating P Indices against measured or modeled P loss data to ensure agreement in magnitude and direction. Following a recently published method, we modified the Maryland P Site Index (MD‐PSI) from a multiplicative to a component index structure and evaluated the MD‐PSI outputs against P loss data estimated by the Annual P Loss Estimator (APLE) model, a validated, field‐scale, annual P loss model. We created a theoretical dataset of fields to represent Maryland conditions and scenarios and created an empirical dataset of soil samples and management characteristics from across the state. Through the evaluation process, we modified a number of variables within the MD‐PSI and calculated weighting coefficients for each P loss component. We have demonstrated that our methods can be used to modify a P Index and increase correlation between P Index output and modeled P loss data. The methods presented here can be easily applied in other states where there is motivation to update an existing P Index.Core Ideas
Our methods expanded upon methods developed by Bolster to modify and evaluate PIs.
Our methods provide practical guidance to other states for modification of PIs.
A theoretical dataset was simulated to represent geographical conditions in Maryland.
Removal of categorical variables and weights increased PI and P loss correlation.
Fertilizer and subsurface components should be evaluated like surface components.
Aging of Dissolved Copper and Copper‐based Nanoparticles in Five Different Soils: Short‐term Kinetics vs. Long‐term Fate
Authors: Sekine Ryo , Marzouk Ezzat R. , Khaksar Maryam , Scheckel Kirk G. , Stegemeier John P. , Lowry Gregory V. , Donner Erica , Lombi Enzo 
Published: May 2017

With the growing availability and use of copper‐based nanomaterials (Cu‐NMs), there is increasing concern regarding their release and potential impact on the environment. In this study, the short‐term (≤5 d) aging profile and the long‐term (135 d) speciation of dissolved Cu, copper oxide, and copper sulfide nanoparticles (CuO‐NPs and CuS‐NPs) were investigated in five different soils using X‐ray absorption spectroscopy. Soil pH was found to strongly influence the short‐term chemistry of the Cu‐NMs added at 100 mg kg−1 above background. Low pH soils promoted rapid dissolution of CuO‐NPs that effectively aligned their behavior to that of dissolved Cu within 3 d. In higher pH soils, CuO‐NPs persisted longer due to slower dissolution in the soil and resulted in contrasting short‐term speciation compared with dissolved Cu, which formed copper hydroxides and carbonates that were reflective of the soil chemistry. Organic matter appeared to slow the dissolution process, but in the long term, the speciation of Cu added as dissolved Cu, CuO‐NPs, and CuS‐NPs were found to be same for each soil. The results imply that, in the short term, Cu‐NMs may exhibit unique behavior in alkaline soils compared with their conventional forms (e.g., in the event of an adverse leaching event), but in the long term (≥135 d), their fates are dictated by the soil properties, are independent of the initial Cu form, and are likely to present minimal risk of nanospecific Cu‐NM impact in the soil environment for the concentration studied here.Core Ideas
Short‐term reactions of Cu are form (dissolved or nanoparticle) and soil chemistry dependent.
In low pH soils, CuO‐NPs dissolved rapidly and behaved similarly to dissolved Cu.
CuO‐NPs persisted longer in alkaline soils and soils with high organic matter content.
In the long term, Cu, CuO‐NPs, and CuS‐NPs transform into Cu bound to FeO(OH) or NOM.
Chemical fate of Cu added to soils is largely independent of the original Cu form.
Failure Analysis for a Low Pressure Aeroengine Turbine Vane
Authors: Citarella Roberto , Giannella Venanzio , Vivo Edoardo , Mazzeo Massimo 
Published: May 2017

Background & ObjectiveIn this work, a thermo-mechanical fatigue application related to a fracture process simulation in a turbine vane is implemented, using a submodelling approach based on the principle of linear superposition.MethodThe proposed crack propagation approach leverages on a combined use of FEM and DBEM methodologies: the global analysis is solved by using FEM whereas the fracture problem is demanded to DBEM. In particular, a DBEM submodel is extracted from a global uncracked FE model and, in the new proposed formulation, boundary conditions are applied just on crack faces rather than loading subdomain boundaries with displacements/tractions and temperatures, as in the classical approach.Results & ConclusionThe adopted approach solves the fracture problem by using simpler pure stress analyses rather than by thermal-stress analyses, as requested by the classical approach. Boundary conditions applied on the submodel crack faces come from the solution of a FE uncracked global model. The computational advantages of such alternative approach are highlighted and, in addition, a fatigue assessment is provided for a turbine vane, considering as initial crack the maximum design defect dictated by GE-Avio regulations for such kind of components.
Effects of Alternate Irrigation with Saline and Non-Saline Water on Sorghum Crop Manured with Elaeagnus angustifolia Leaves Using 15N
Authors: Al-Ain Farid , Al-Chamma'a Mohamad , Kurdali Fawaz 
Published: May 2017

Background:A pot experiment was conducted to determine the effects of alternate irrigation with saline (S) and fresh (F) water on growth, nitrogen uptake and nitrogen use efficiency in Sorghum crop (Sorghum bicolorL.) manured withElaeagnus angustifolialeaves (GM) using15N.Method:Five types of irrigation systems abbreviated as (F, 2F:1S, 1F:1S, 1F:2S and S) and one rate of Green Manure (GM) were employed.Result:Results showed reductions in both Dry Matter yield (DM) and nitrogen uptake (NY) in sorghum grown under different types of irrigation systems as compared with the control (F). The reduction rates of these two parameters increased with increasing number of irrigations with saline water. However,E. angustifolialeaves applied as green manure mitigated the harmful effect of salinity on plant growth parameters. The percent increments as a result of GM application were 9, 19, 43, 43 and 65% for DM, and 33, 30, 42, 36 and 60% for NY in F, 2F:1S, 1F:1S, 1F:2S and S, respectively. Nitrogen use efficiency of added green manure ranged between 25 and 47% in the different types of irrigation systems. Our results indicated that increment of NY in green manured sorghum plants was mainly attributed to its nitrogen availability. According to the availability of S and F water resources, and the economic returns aimed by farmers in the semi-arid regions, it is recommended to use (2F:1S, 1F:1S and 1F:2S) in combination withE. angustifolialeaf GM. Such a procedure can be considered as a promising agricultural practice to improve yield with a proper water resource investment.