bluuebunny/crossref_metadata_2025_split huggingface dataset:
THE TALE OF APHRODITIAN IN THE SLAVONIC HOMILIES AT CHRISTMAS OF THE XV–XVIII CENTURIES
Authors: Kovalenko A. N. 
Published: March 2020

The apocryphal “Tale of Aphrodithian” is one of the most popular apocrypha of Ancient Russia; it narrates about the Magi’s worship to newborn Christ. The article is devoted to a brief review of Slavic homilies at Christmas, based on an apocryphal text. In total, four works of the XVXVIII centuries were identified, containing the apocrypha: “The Word about the star Irania”, “The Word about the Coming of the Magi”, “The Word at Christmas of the former Archbishop Spiridon” and “Tale for the Nativity of Christ”. The article records the number of lists preserved and the degree of elaboration of each work in the scientific literature. In all homilies, the Tale becomes a source of additional information about the worship of the Magi, but the authors of these homilies use the apocryphal details of the Tale in different ways.In the “The Word about the star Irania” the foggy and obscure language of prophecy in the idol temple is corrected, every detail is included in the context and explained. “Tale for the Nativity of Christ”, in our opinion, is a Western Russian revision of “The Word about the star Irania” and both texts are primarily aimed at revealing all the details associated with the appearance of the star – from the first prophecy by Balaam to the final journey of the Magi. The “Word about the Coming of the Magi”, on the other hand, combines most of the popular Old-Russian narrative texts related to Christmas into one plot: this is how the tale of the Magi, The Legend of Aphrodithian and the Word of John Chrysostom, noted only in Russian lists, (first words: “Today is my nature to the promise of renewal comes”) are combined. In the “Word for the Nativity of the Archbishop ex-Spyridon”, the apocrypha become just an occasion for discussion on the theme of Christmas and the worship of the Magi, the main idea of the author is to follow the spiritual Sun - Christ.The legend of Aphrodithian in this case becomes one of many sources, far from been paramount, in the text intended for public sermon, not for private reading.
Lateral Unicompartmental Knee Arthroplasty
Authors: Smith Evan , Lee Danny , Masonis John , Melvin J. Stuart 
Published: March 2020

» Lateral unicompartmental knee arthroplasty affords excellent functional results and implant survivorship for properly selected patients. More high-quality studies are necessary to determine whether expanded indications for medial unicompartmental knee arthroplasty also apply to lateral unicompartmental knee arthroplasty.» Operative adjuncts such as robotics, custom implants, and navigation technology hold promise in minimizing the technical burden and unfamiliarity of lateral unicompartmental knee arthroplasty.» Improvements in lateral-specific implants may translate to operational efficiency and improved outcomes, but few lateral-specific implants currently exist.» Mobile-bearing devices have increased rates of failure due to bearing dislocation, and further studies are warranted to evaluate this complication with newer designs.» Future registry and cohort studies should show medial unicompartmental knee arthroplasty and lateral unicompartmental knee arthroplasty separately to allow for better understanding of the nuances and technical differences between these uniquely different procedures.
Improved In-Situ Stress Characterization Through Analysis of Diagnostic Fracture Injection Tests DFITs Using the Changing Compliance Method and its Impact on Caprock Integrity Analysis
Authors: Mostafavi Vahid , Cramer David D. , Hossini Amir H. 
Published: March 2020

Abstract
Diagnostic Fracture Injection Tests (DFITs) provide a critical piece of information on the competency of the top seal for injection projects and are therefore essential for Subsurface Containment Assurance (SCA) and Maximum Operating Pressure (MOP) determination. Results of DFITs provide the best estimate for the minimum principal stress component, which is a major input for tensile and shear failure tolerance analysis. Therefore, best practices in execution and analysis of DFITs is extremely important for safe and successful operations.
Numerous DFITs have been conducted over the past ten years in Surmont to assess the integrity of the caprock and determine the maximum allowable steam injection pressure. A combination of surveillance and coupled reservoir-geomechanics simulations have been utilized to maintain a minimum of 20% safety factor for caprock failure.
The tangent analysis method for determining fracture closure pressure has been extensively used in the past decade for DFIT analysis in the industry [1 and 2]. The validity of this method has been challenged recently through more rigorous modeling of the hydraulic fracturing process and field observations. An alternative analysis method referred to as the compliance method has been proposed and successfully used in many cases [3].
In the past few years, we have demonstrated the potential to safely increase the maximum operating pressure and its impact on production, through extensive caprock integrity analysis in Steam Assisted Gravity Drainage (SAGD) operations [4 and 5].
In this study, the DFITs carried out in Surmont were revisited to assess the potential impact of characterizing in-situ stresses with improved accuracy on maximum allowable injection pressure and ultimately production uplift. The analysis shows higher minimum horizontal stresses in the caprock are supported by field observations, which could potentially allow for higher injecting pressure and close to five percent additional production in the two selected SAGD pads.
Phase Behaviour of Solvents/Heavy Oil Systems at High Pressures and Elevated Temperatures
Authors: Huang Desheng , Yang Daoyong 
Published: March 2020

Abstract
In this paper, techniques have been developed to determine multiphase boundaries of solvent(s)/heavy oil mixtures at high pressures and elevated temperatures in pressure-temperature (P-T), enthalpy-temperature (H-T), and pressure-enthalpy (P-H) phase diagrams, respectively. Theoretically, the Peng-Robinson equation of state (PR EOS) incorporated with a new alpha function as well as the previously developed enthalpy calculation algorithm are used to predict the multiphase boundaries of the solvent(s)/heavy oil systems by characterizing the heavy oil as a single pseudocomponent. The PR EOS associated with the newly developed alpha function is found to be accurate in reproducing the experimentally measured VL1L2 (V represents the vapour phase, L1 denotes the high density hydrocarbon-rich liquid phase, and L2 refers to the low density CO2 liquid phase) three-phase boundary pressures with an overall absolute average relative deviation (AARD) of 2.01% and maximum average relative deviation (MARD) of 3.54%, respectively. In addition, the VL1L2 three-phase boundaries are expanded and tended to move toward the region with higher temperatures and lower pressures in the P-T phase diagram with the addition of either C3H8 or n-C4H10 to CO2/heavy oil systems compared to those of only CO2 exists in heavy oil systems. The enthalpy changes rapidly with variation of temperature in both H-T and P-H phase diagrams within the three-phase region. Either two-phase (VL1) or three-phase (VL1L2) isenthalpic flash calculations can be performed straightly to determine phase fractions and compositions together with system temperature without conducting the stability analysis for a provided solvent(s)/heavy oil mixture at a constant enthalpy and pressure with the constructed H-T phase diagram.
Through Tubing Casing Break Detection: An EM Thickness Tool Application
Authors: Jawed Rehan , Maheshwari Kishore , Jamali Jay , Rourke Marvin 
Published: March 2020

Abstract
Maintaining healthy well integrity in heavy-oil thermal wells is a challenge. Steam causes significant variation in temperature along the wellbore resulting in excessively high stresses that can result in parted casing or even a complete casing failure.
Determining casing break/failure condition is an important part of managing thermal well integrity. Identifying potential risks based on findings from electromagnetic (EM) casing inspection logs is essential to plan mitigation actions. EM casing inspection logs can also be run prior to putting wells on steam injection to establish a baseline and regularly evaluate well integrity via a time-lapse methodology.
In this paper, we have outlined the successful application of Pulsed Eddy Current (PEC) Electromagnetic casing inspection technology in thermal well integrity. One of the major benefits of PEC casing inspection technology is a reliable method to locate casing breaks. It provides casing inspection without retrieving tubing (first pipe) that saves time and costly workover.
This paper briefly explains the PEC technology, how it has been deployed, and the methodology developed to quickly and clearly identify casing breaks because one of the evaluation challenges is that the typical thermal casing break occurs in the vicinity of the casing collar.
We have demonstrated in the paper validation of the PEC technology for detecting casing breaks. It includes downhole comparison with a traditional multi-finger caliper log after the tubing is pulled.
The paper includes some case study examples of how PEC has been used to successfully identify casing breaks and conclude with a summary collected over five years of PEC application with a 100% success rate in more than 200 Canadian heavy oil wells.
Analysis of the Acoustic Velocity of Gas from Fluid Level Tests in Producing Heavy Crude Shallow Wells with Cyclic Steam and Nitrogen Stimulation, Colombia
Authors: Solano Arias Andres , Garzon Navarro Edgar 
Published: March 2020

Abstract
The fluid level software provides useful information to optimize oil and gas production when is required. The fluid level calculation is given by the acquisition of the half travel time of a soundwave and its acoustic velocity, which is highly influenced by changes in temperature, pressure, and specific gravity of gas, commonly seen in cyclic steam and nitrogen stimulations.
Considering the above concept, a process for collection and statistical analysis of acoustic velocities was developed in a heavy oil field in order to ensure accuracy in fluid level detection in two specific groups of horizontal shallow wells whose gas composition was constantly altered by two different thermal EOR stimulations. The first group contains wells injected with cyclic steam, called EOR-1, and the second group includes wells injected with cyclic steam + nitrogen simultaneously, called EOR-2. Additionally, an estimation of the specific gravity of gas was calculated as a function of gas temperature and acoustic velocity collected, assuming an ideal mixture of gases at determined temperature ranges, considering the behavior of the casing pressure ​​as a constant (less than 2 Psig average). Scatter and box-plot were made using descriptive and inferential statistical methods for the study of data.
With the analysis of the acoustic velocity of gas not only was possible to create a unique reference pattern with specific statistical Tukey's fences to improve the accuracy of liquid level detection by means of outlier determination, but it could also be interpreted the behavior of the annular gas composition in presence of additional gases such as water vapor and nitrogen at different annular gas temperature ranges during their whole production cycle, without requiring an expensive chromatographic analysis. In the same way, a detection method of nitrogen channeling between wells of the same producing sand could be established regardless of the EOR methodology performed, since it was determined that acoustic velocities from 1290 ft/s to 1400 ft/s are highly related to the presence of nitrogen in the gas composition being considered atypical in steam-injected wells (EOR-1), whose determined range varies from 1400 ft/s to 1520 ft/s.
Standalone Sand Control Evaluation: Developing a Large-Scale High Temperature Sand Retention Test Apparatus
Authors: Fattahpour Vahidoddin , Roostaei Morteza , Mahmoudi Mahdi , Soroush Mohammad , Hosseini Seyed Abolhassan , Anderson Mark 
Published: March 2020

Abstract
Primary Cold Heavy Oil Production with Sand (CHOPS) recovery factors are low (typically 8%) and most of the oil is left behind in the formation. Canadian Natural Resources Limited (Canadian Natural) is pursuing alternatives to primary recovery and secondary post CHOPS Enhanced Oil Recovery (EOR) to recover more of this stranded oil resource. Wire-wrapped screens were investigated, using a High-Pressure High Temperature Sand Retention Testing (HPHT-SRT) apparatus, for sand control and inflow performance in a CHOPS formation near Bonnyville, Alberta.
A new HPHT-SRT apparatus was designed/commissioned to better understand the role of oil viscosity on the capability of the standalone sand control screen. The facility allows to control the temperature of the fluid flowing across the sand pack and sand control coupon at different pressure drops. Each test is performed at constant pressure drops up to 300 psi. The temperatures up to 85 °C were tested. Coupons of wire-wrapped screen with three aperture sizes (0.008″, 0.010″, and 0.012″) were tested. Canadian Natural provided oil sand cores and crude oil from the target formation for this testing.
The results indicated a high dependency of the near screen flow performance on the temperature and oil viscosity. As the increase in temperature reduces the oil viscosity below 300 cP, the near screen pressure gradient falls 26% to 40% under constant pressure drop for different aperture sizes. As the screen aperture increases from 0.008″ to 0.012″, the flow rate increases up to 20% for the test stages at 85°C temperature and up to 162% for the test stages at 25°C, for the tested pressure drops. The results indicate that at higher viscosities, the aperture size is the dominant factor in screen flow performance where a slight increase in aperture increases the flow performance and reduces pressure drop. However, increasing the aperture size, up to 0.012″, led to an increase in the sanding over 0.20 lb per square feet of the screen (lb/sq.ft.), which exceeds the acceptable threshold of 0.12 to 0.15 lb/sq.ft. for typical SRTs. Based on the pressure drops and produced sand results, a 0.010″ aperture size was recommended for the target formation.
This paper outlines the results of the experiments with a HPHT-SRT, which is developed to better assess the function of sand control design for heavy oil assets. This phase of the work mainly focused on better understanding the role of the oil viscosity on sand control performance.
Wettability of Calcareous Shales from the East Duvernay Basin: The Role of Natural Fractures, Thermal Maturity, and Organic-Pore Connectivity
Authors: Xu Shiyu , Yassin Mahmood Reza , Dehghanpour Hassan , Kolbeck Christen 
Published: March 2020

Abstract
In this study, we conducted rock/fluid experiments to investigate wettability of calcareous shale plugs from a well drilled in the early oil-window (EOW) of East Duvernay. The wettability of EOW plugs was compared with that of highly-mature and quartz-rich plugs in the oil and gas windows (OGW) of the Duvernay Formation to investigate the effects of kerogen maturity and mineralogy on pore morphology and wettability of shales. We investigated the effects of organic-pore connectivity and fractures on wettability of the EOW plugs. By using CT scan images, we divided EOW plugs into highly-fractured (HF), slightly-fractured (SF), and non-fractured (NF) plugs. We used reservoir oil and brine and conducted comparative imbibition tests on the core plugs to investigate effects of fracture intensity on imbibition profiles. The core plugs were characterized by analyzing the results of tight-rock analysis (TRA), x-ray diffraction (XRD), and rock-eval pyrolysis.
Compared with the quartz-rich OGW plugs, the EOW plugs are categorized as calcite-rich shale (calcareous shale) with high average calcite content of 60%. The EOW plugs are rich in organic matter (average total organic carbon (TOC) of 7.3 wt%) with significantly high value of Hydrogen Index (HI &gt; 500). Surprisingly, the results of wettability tests show higher normalized imbibed volume of brine compared with that of oil, suggesting that the EOW plugs are preferentially water-wet. This trend is opposite to what we previously observed for the oil-wet OGW plugs with significantly high organic porosity, positively correlated to TOC content. We did not observe well-developed organic pores within organic matter of less-mature EOW plugs. We also observed that the normalized imbibed volume of oil is much higher in the HF and SF plugs compared with that in the NF plugs. The results suggest that the fractures enhance accessibility of isolated pores, leading to more connected pore network for oil imbibition. This observation suggests that fracture porosity plays a significant role in wetting behavior of the EOW plugs. The results show that the porosity measured by Boyle’s law helium-porosimetry using crushed EOW samples is significantly higher than their effective porosity. This is because crushing the samples enhances accessibility of isolated pores considered as ineffective porosity under intact conditions. Combined analyses of imbibition profiles and core images of the fractured plugs show that oil rapidly imbibes into the fracture system, and then gradually imbibes from fractures into rock matrix.
Rate Increase in Unconventional Wells with Declining Flowing Pressure
Authors: Pooladi-Darvish Mehran , Tabatabaie S. Hamed , Tavallali Mohammad , Mattar Louis 
Published: March 2020

Abstract
Some simulation studies of unconventional wells with a declining flowing pressure show a significant increase (hump) in the oil rate at the time when the flowing pressure crosses the bubble point. This unexpected "oil-rate hump" is subsequently followed by the traditionally expected rate decline.
The unexplained rate hump raises various questions: The first question is: is it real or simply an artifact of the mathematics of numerical simulation? And if real, other question arise, including: how do reserve estimation methods that are based on rate decline apply to an increase? Or, does a rate increase mean one should produce the wells at pressures below the bubble point pressure to accelerate production of the oil associated with the rate hump? The main objective of this paper is to investigate whether a rate hump is a result of numerical errors of simulators especially as grid-blocks drop below bubblepoint pressure, or if it is an intrinsic response of formulations of two - phase flow under some conditions of flowing pressure, etc. And if the latter, what are the conditions that lead to a rate hump.
We start with the partial differential equations of two-phase (gas and oil) flow for transient linear flow and re-write them in a form similar to those of single-phase flow. This allows term-to-term comparison of the two-phase formulation with the corresponding single-phase one. Through this comparison and the analytical and numerical solutions presented, we suggest that the rate increase is not because of numerical errors, instead it is related to at least three groups of parameters(i) fluid properties impacting the ratio between single-phase and two-phase compressibility. (ii) flow parameters that reflect how efficiently the evolved solution gas displaces the oil, and (iii) the rate at which the pressure at the wellbore is declining.
Furthermore, a series of numerical simulations are conducted to:(i) investigate the effect of parameters of significance and (ii) extend the range of investigation to more practical cases such as those more common to completion in unconventional reservoirs. When we choose typical values for reservoir and fluid properties, and operating conditions from unconventional basins we observe significant rate increases that last for many months and could make a significant contribution to early production.
Next, we look for evidence of the "rate hump" in actual field data. Our review of field data did not result in any convincing data sets with clearly defined rate humps. While a more exhaustive review of field data may reveal this phenomenon to be real, we discuss conditions that may mask or negate the rate hump. We also provide preliminary guidelines for input parameters so that the simulation model does not exhibit the rate hump.
To the best of our knowledge, this is the first time that the rate hump is being investigated in the literature.
Use of Normalized Cumulative Production Curves to Estimate Ultimate Recovery of Unconventional Plays in North America
Authors: Olea Ivan , Tabatabaie Hamed , Mattar Louis , Khaksarfard Reza 
Published: March 2020

Abstract
Operators and investors are interested in finding better metrics to evaluate the production performance of unconventional multi-fractured horizontal wells (MFHWs). This paper discusses the use of cumulative productionratio curves,normalized to a given reference volume in time (e.g. 12-month cumulative production) for different unconventional plays in North America to investigate the median trend for each play, and investigate the median ultimate recovery per play. The selection of using 12-month cumulative production as a reference volume as a normalization parameter is discussed.
Historical production data from thousands of MFHWs in unconventional plays in the US (Bakken, Barnett, Eagleford, Fayeteville, Haynesville, Marcellus and Permian) and Canada (Duvernay, Montney and Horn River) was used to calculate normalized cumulative production curves for theprimary fluid, using different cumulative reference volumes at different points in time (e.g. 6, 12, 24, 36, 48 and 60 months). The observed trends for each of the selected plays werestudied using data analytics tools. A two-segment hyperbolic decline was used to match the median production trend to estimate the long-term performance of each play.
Depending on the data variance, some plays exhibit more clear trends than others. By using normalized cumulative production curves, general profiles for each play were generated and compared. These Cumulative Production Ratio Profiles (CPRP) were extended using a two-segment hyperbolic equation to determine the Expected Ultimate Recovery Ratios (EURR) per play.
Once a well in a region has been on production for a minimum duration equal to the reference time (e.g. 12 months), two results are readily determined: a) the EUR, and b) the production profile. The EUR is obtained simply by multiplying the appropriate EURR by the well's 12-month cumulative production; and the production profile is obtained by using the CPRP (cumulative production ratio profile) of the play and multiplying it by the 12-month cumulative production of the welland converting the results to daily rates.
This cumulative plot serves as a normalized typewell for the region and can be used to guide the production forecasts of wells with a short production life.