bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Universal Ranking for Friction Reducer Performance
Authors: Tomson Ross C. , Guraieb Paula , Graham Shane , Yan Chao , Ghorbani Nasser , Hanna Ty , Cooper Cal 
Published: January 2017

Abstract
In hydraulic fracturing, large amounts of water are pumped at high speed down the wellbore. To reduce pump pressure and costs, a friction reducer is added to the stream. There is currently no unified performance criteria for selection of friction reducers. This work outlines the methodology for producing such a unified method of comparing performance between any friction reducer chemical additives, both liquid and dry powder.
A 0.5 inch stainless steel high-flow low-shear flow loop pumping at ranges between three and twenty gallons per minute was custom-built. The loop uses a Coriolis flow meter, two absolute pressure transducers, and one differential pressure transducer to accurately determine the friction reducer additive performance in any given fluid by measuring pressure drop across a section of developed flow. This paper utilizes over 400 in-house flow loop tests to establish a novel unified ranking system for the evaluation of friction reducers’ performance. The ranking is independent of the type of friction reducer used and quality of water. Produced waters, fresh water, treated produced waters, and synthetic waters were all used to validate the methodology and ranking system to create a unified criteria to compare performance of any friction reducers.
Tomson Technologies created a standardized metric for assessing and ranking friction reducer performance. This standardization was achieved through the use of an unique performance scale comprised of the weighted average of the most important friction reduction parameters of a friction reducer in any produced water: (1) inversion time (InvT), (2) maximum percent friction reduction (Max% FR), (3) time to sustain maximum percent friction reduction (RetT@%Avg.FRmax), and (4) the percent friction reduction at the end of 500 seconds (% FR@500s). 500 seconds is used because fluid during hydraulic fractures travels from the pumps to the reservoir in 500 or fewer seconds in almost all cases. This scale is measured in a new unit called "Friction Reducer Units" (FRU), which ranges from 0 to 10. FRU has been used to rank and correlate the performance of different classes of friction reducers in various types of waters, resulting in a comprehensive results database and is used to show applicability of the overall metric.
Advanced Reservoir Characterization in Antelope Shale Using Chemical Tracer Technology
Authors: Lal Manish K. , Singh Amit K. , Ezernack Joshua , Spencer Jon 
Published: January 2017

Abstract
Understanding zonal contribution is imperative in a well with comingled production from multiple stimulated zones. This has even more importance in shale plays where a primary appraisal objective is to identify the prolific zones with a vertical well to decide which layers of the formation will be targeted for future development. The use of measured inflow over time of each targeted zone provides an excellent methodology to establish zonal contribution and wellbore evaluation.
The Monterey Formation in the southern San Joaquin valley of California produces from three silica phases. While the industry has been pretty successful in producing from the shallow Diatomite rock via cyclic steam operations, the deeper silica-based resources available in the Antelope Shale have yet to be commercially established. Extracting hydrocarbons locked in these silica phases requires unconventional technologies to access the high porosity / low permeability network. Unconventional completions require greater front-end cost and carry an increased risk to return on investment. To minimize the risk, each pay zone needs to be effectively described using both theoretical and empirical data.
In this paper, we present and discuss a case study where chemical-based tracer technology was used to develop an accurate identification of the distinct pay zones within the different silica phases of the Antelope Shale. Unique oil-phase chemical tracers were applied during the permitted hydraulic fracturing on four vertical wellbores that gave an insight into the zonal production contribution and helped narrow potential zones for future development. In comparison to tool based zonal contribution measurement methods, which provide a snapshot in time measurement, the chemical tracers provided the capability to monitor and measure inflow over a longer period indicating that zonal contribution varied with time. Some formation layers produced immediately and then declined, while others took longer to cleanup and start contributing to total production. These results helped narrow the uncertainty around the potential target zones.
Impact of Well Interference on Shale Oil Production Performance: A Numerical Model for Analyzing Pressure Response of Fracture Hits with Complex Geometries
Authors: Yu Wei , Xu Yifei , Weijermars Ruud , Wu Kan , Sepehrnoori Kamy 
Published: January 2017

Abstract
The effect of well interference through fracture hits in shale reservoirs needs to be investigated because hydraulic fracturing is abundantly used in the development of unconventional oil and gas resources. Although numerous pressure tests have proven the existence of well interference, relatively few physical models exist to quantitatively simulate the pressure response of well interference. The objective of the present study is to develop a numerical, compositional model in combination with an embedded discrete fracture model (EDFM) to simulate well interference. Through non-neighboring connections, the EDFM can properly handle complex fracture geometries such as non-planar hydraulic fractures and a large amount of natural fractures. Based on public data for Eagle Ford shale oil, we build a reservoir model including up to three horizontal wells and five fluid pseudocomponents. The simulation results show that the connecting hydraulic fractures play a more important role than natural fractures in declining bottomhole pressure (BHP) of the shut-in well. Matrix permeability has a relatively minor impact on pressure drawdown and well productivity remains little affected due to the overall low permeability used. The BHP pressure decline profiles change from convex to concave when the conductivity of the connecting fractures increases. At early times, the BHP of the shut-in well decreases when the number of natural fractures increases. At later times, the natural fracture density has a lesser impact on the pressure response and no clear trend. The opening order of neighboring wells affects the well interference intensity between the target shut-in well with the surrounding wells. After a systematic investigation of pressure drawdown in the reservoir we formulate practical conclusions for improved production performance.
Characterization of Complex Fracture Propagation in Naturally Fractured Formations Using Digital Image Correlation Technique
Authors: Mokhtari Mehdi , Hayatdavoudi Asad , Nizamutdinov Rustam , Rizvi Hashim , Nath Fatick 
Published: January 2017

Abstract
Most shale and carbonate formations violate the isotropic assumption of rock media in classical fracture models due to the presence of extensive natural-fracture network. However, the current application of strain gauges cannot provide information about how natural fractures interact with induced fractures in such heterogeneous rock system. In this paper, we present the application of Digital Image Correlation (DIC) technique which can measure strain development over time, thus it can determine the fracture initiation and propagation. We apply indirect tensile experiment on Buda Limestone samples with various patterns of complex natural-fracture system while the strain development in sample is measured by Digital Image Correlation (DIC) technique.
As a benchmark, DIC technique was first conducted on a homogeneous sandstone sample. The results verify that that the maximum tensile strain is developed at the central vertical line of sample as it was expected from theoretical solutions. This DIC measurement matches the post-failure fracture pattern of specimen. In contrast to failure pattern in homogenous sandstone specimen, very complex fracture pattern was observed on several Buda Limestone specimen. Fracture slippages along natural fracture, fracture deviation toward inclined and horizontal fracture was recorded. The results of this study can help us to better understand the complex failure mechanism in naturally fractured media. DIC is a powerful technique in providing the strain development over the surface of sample in real time, thus it can provide the fracture initiation and propagation in such heterogeneous rock media.
Mining the Bakken: Driving Cluster Efficiency Higher Using Particulate Diverters
Authors: Weddle Paul , Griffin Larry , Pearson C. Mark 
Published: January 2017

Abstract
This paper focuses on the evolution of an advanced completion design utilizing solid particulate diverters resulting in a dramatic increase in the number of fracture initiation points as validated with radioactive (RA) tracers. The ultimate goal of this strategy is to increase capital efficiency by placing a dense fracture network more contained within the producing formation. The information contained in the paper should be of great benefit to completion engineers working across a variety of unconventional oil and gas basins.
It is generally proven that larger proppant volumes and more frac stages result in higher oil and gas recoveries, i.e., bigger is better. Practically, the number of stages for a 9,500 ft lateral (typical for the Bakken) is limited to 40 or 50 stages due to operational and cost limits. For advanced completion designs (complex fracture networks), the goal is not to just increase the stage count but to increase the number of initiation points (perforation clusters) that are effectively stimulated increasing the contacted fracture surface area. Considerations when executing this strategy include, but are not limited to: proppant transport, screen out risk, stress shadowing and geo-mechanical variability along the wellbore.
With volatile oil prices, continued innovation is necessary to sustain the unconventional shale success. In pursuit of better well performance AND lower capital costs, Liberty Resources has moved to a completion design that incorporates a high density perforating strategy and a focus on diversion methods to effectively stimulate each cluster. Solid particulate diverter was utilized to increase perforation cluster efficiency. Production performance is encouraging, and RA proppant tracers show that cluster stimulation efficiencies in excess of 85% can be achieved.
The unconventional shale revolution that began 15 years ago has successfully returned the United States to being a world leader in oil and gas production and technology. Completion designs have evolved significantly from the first early Barnett Shale completions and are now quite diverse. Variations in design are driven by the uniqueness of each basin's geologic and reservoir properties as well as operator bias. This diversity in completion methodologies has contributed significantly to technology advancement; the status quo is continually tested with new innovations. The Williston Basin was one of the first unconventional shale oil successes and it continues to contribute to the advancement of horizontal fracturing technology.
Cluster Spacing Optimization through Data Integration Workflow for Unconventional Jurassic Mudrocks, Saudi Arabia
Authors: Al-Momin Ali , Mechkak Karim , Bartko Kirk , McClelland Kenneth , Tineo Roberto , Drouillard Matthew , Nadeem Muhammad 
Published: January 2017

Abstract
One of main challenges operators face in evaluating the potential of unconventional reservoirs is the complex geologic nature of organic rich, fractured, laminated, and heterogeneous formations having implications on stimulation and production optimization. An area with a limited number of stimulated appraisal wells in the Jurassic mud rocks in Saudi Arabia was targeted for this study. The objective is to build and calibrate a multidisciplinary integrated workflow consisting of geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a multi-well pad drilled in the subject area.
The workflow developed comprises integration of data analysis to evaluate reservoir and completion qualities and assess their impacts on production performance specifically for unconventional reservoirs. Petrophysical and geomechanical models were calibrated with core measurements. Logs from the horizontal lateral was integrated in the geomechanical model to analyze the hydraulic fracture stimulation by performing fracture pressure matching for all stages. The hydraulic fracture attributes from the fracture simulator were exported to the reservoir simulator. The surface production measurement together with the production log were used to calibrate the reservoir model.
The final calibrated workflow, including hydraulic fracture and reservoir models, was used to perform sensitivity analyses to optimize the cluster spacing and other completion parameters considering the geomechanical and reservoir constraints. Preliminary results suggest stress shadowing is not a major concern even with a short cluster spacing given the level of stress anisotropy in this formation. An optimum cluster spacing was determined based on long-term production performance. The results of this study were implemented in a pilot well pad to determine which completion variables were critical for optimizing well productivity and further calibration of the workflow.
The methodology adopted in this study identifies the major controlling factors of completion and reservoir parameters affecting well productivity for specific unconventional reservoirs. This workflow will help shorten the learning curve and increase the efficiency to reach the optimum stimulation design for the development phase.
Lithology Variations and Cross-Cutting Faults Affect Hydraulic Fracturing of Woodford Shale: A Case Study
Authors: Ma Xiaodong , Zoback Mark D. 
Published: January 2017

Abstract
We conducted an integrated geomechanics case study of the Woodford shale to understand the effectiveness of multi-stage hydraulic fracturing. The study involves two parallel horizontal wells, each about 5,000 feet long with ~15 frac stages. Analysis of Instantaneous Shut-In Pressure (ISIP) of each frac stage indicates significant variations of the minimum horizontal principal stress (Shmin) magnitude along the well length. We observed that Shmin by stage rises with the content of clay and organic matter. The number of micro-earthquakes and the amount of proppant embedment, seems to be affected by the Shmin variation. By combining the analysis of the compositional log and the well steering data, we found that the wellbore traveled in and out of the target zone and penetrated different facies of the Woodford shale along its path, resulting variations of lithology and consequently patchy stimulation performance. The distribution of microseismic events away from the well both vertically and laterally is also influenced by the lithology variation, as well as the presence of pad-sized faults.
Fully Coupled 3-D Hydraulic Fracture Growth in the Presence of Weak Horizontal Interfaces
Authors: Izadi Ghazal , Moos Daniel , Cruz Leonardo , Gaither Michael , Chiaramonte Laura , Johnson Scott 
Published: January 2017

Abstract
Weak bedding planes create a unique mechanism for hydraulic fracture height containment, providing one possible explanation for unusual patterns of height growth in shale formations. This paper describes an investigation into how bedding planes modify the interactions between multiple, simultaneously propagating hydraulic fractures in a formation with weak horizontal interfaces with laterally varying properties. The investigation used a 3-D simulator that fully coupled geomechanics, fracture mechanics, and fluid behavior. Three equally spaced fractures were simulated along a horizontal trajectory. Fluid was injected simultaneously into all three locations, and partitioned according to maintain a specified total injection rate. Variations in perforation spacing, fluid viscosity and injection rate are modeled. The four designs investigated were: 1) 10-cp fluid, 20b-pm injection rate with 30-m cluster spacing. 2) 100-cp fluid and 20-bpm fluid injection rate with 30-m cluster spacing. 3) 10-cp fluid and 40-bpm injection rate with 30-m cluster spacing. 4) 10-cp fluid, 20-bpm and 45-m cluster spacing. Results showed how these changes affected fracture area and shape. The propped surface area for each scenario was also estimated. The results suggested that the presence of laterally varying weak interfaces can significantly affect fracture interference.
Evaluating Stresses Along Horizontal Wells in Unconventional Plays
Authors: Sanchez-Nagel Marisela , Nagel Neal B. , Rodriguez Adolfo A. , Nieto Natalie 
Published: January 2017

Abstract
Multi-stage hydraulic fracturing in horizontal laterals is a key technology in the development of Unconventional plays around the world wherein many hydraulic fractures (on the order of hundreds) are initiated that can greatly increase the surface area for flow and, correspondingly, well production. Stress profiles, both near-wellbore and far-field, play an important role in the initiation of these hydraulic fractures as well as hydraulic fracture growth.
Field measurement of the minimum stress component is often done using DFITS, mini-fracs and leak-off tests, which are very scarce and rarely done on sequenced vertical layers or along horizontal laterals. With the development of dipole sonic tools in the 1970s, log-based, continuous stress profiles (‘Frac logs’) have been used in vertical wells for hydraulic fracture design. Commonly, the minimum horizontal stress, Shmin (often mistakenly called the ‘frac gradient’) has been estimated by assuming no lateral strain (a uniaxial strain assumption) within the earth (sometimes called ‘Eaton's equation’), wherein Shmin is simply a function of Poisson's ratio (from the dipole sonic log), vertical stress, pore pressure, and Biot's constant (also computed from the dipole sonic log). There are fundamental shortcomings to this approach for estimating stresses, essentially related to the change in elastic properties through geological time and plastic deformation, which essentially promotes stress release - not elastic stress buildup. Additionally, tectonic stresses were not originally considered, and Eaton's formulation was extended to include tectonic strain effects as well as the effects of elastic anisotropy (commonly vertical transverse isotropy, VTI).
For horizontal wells, the need for accurate stress measurements is even more critical than for vertical wells; however, Poisson's ratio values obtained from dipole sonic tools run in a horizontal lateral cannot be used to generate a profile of stress along the wellbore as done in vertical wells. The focus of the numerical study presented in this paper was on the limitations and inaccuracies of computing log-based stress in horizontal laterals.
The results presented in the paper provide important insight into the variation of in-situ stress along horizontal laterals as well as the associated change in breakdown pressure. As estimated breakdown pressure has become a common metric for perforation placement, the results of the presented work will impact common horizontal well completion designs in Unconventional Plays.
A Novel Frac-Optimized Perforating System for Unconventional Wells: Development and Field-Trial
Authors: Satti R.P. , McCann J. , Flores J. C. , Zuklic S. N. , Wutherich K. , Hurt R. S. 
Published: January 2017

Abstract
Production optimization in unconventional reservoirs has traditionally been driven by hydraulic stimulation technologies. One critical technology that has been historically overlooked is the actual perforations through which the stimulation treatment is performed. While many technologies have been updated and optimized for unconventional well applications, perforating gun systems have remained largely unchanged. Conventional perforating guns create long, spiral-pattern perforations that enable effective hydraulic fracture treatments in vertical wells. However, in horizontal wells that are drilled perpendicularly to the least principal stress plane, this design is inefficient, leading to issues of tortuosity and competing fractures. This situation eventually leads to inadequate formation treatment, locking hydrocarbons within the reservoir.
In this study, we present a novel, game-changing frac-optimized perforating system that features an efficient gun design and an optimized perforating pattern that enhances fracture treatments, improves overall drainage and increases operational efficiency. The system features only three shaped charges that are orthogonally oriented with the objective of focusing treatment pressures to maximize fracture length and reach while achieving the benefit of reducing competing fractures and tortuosity near the wellbore. This also enables more proppant and fluid to penetrate the formation, reduce pressure drop across the wellbore and minimize choking during flow back. Additionally, the shorter gun length and decreased number of shaped charges provide greater operational efficiency and reduced HSE risk.
Following system qualification and operational planning, a field trial was recently conducted for an operator using the frac-optimized perforating gun system. The system was deployed in two of the stages in a 55-stage well completion. The operation was successfully run on both stages and results showed that the treatment pressures during the frac operation were smaller than in the stages perforated with conventional guns. Further, the desired flow rate of 100BPM was achieved faster with the frac-optimized gun system. The stages where this system was run also had a noticeable operating time reduction in comparison with their adjacent conventional gun stages.
LOCAL APPLICATION OF TRANEXAMIC ACID IN KNEE REPLACEMENT
Authors: Pshenitsyna E. V. , Zagrekov V. I. , Malyshev E. E. 
Published: January 2017

The purpose of the study – assessment of the efficacy of local application of tranexamic acid in TKA and the choice of the optimal dosage. Materials and methods. 48 patients were included in open-prospective study and were randomized to one of four groups. In the first group tranexamic acid was used as intravenous bolus at the beginning of the operation at a dose of 15 mg/kg. Additionally, after the installation of the prosthetic components, the surgeon performed periarticular infiltration of soft tissue by tranexamic acid solution at a dose of 15 mg/kg. In the second group of patients tranexamic acid was used as 500 mg intravenous bolus before surgery, and 500 mg locally after installation of the prosthesis components. In the third group of patients received tranexamic acid once at the beginning of the operation at a dose of 15 mg/kg iv bolus. In the fourth group tranexam was used after surgery once at a dose of 10 mg/kg. Results. In the first group of patients were achieved statistically significant, 5-6 times, reduction of blood loss on drainage in comparison with other groups, where the volume of postoperative blood loss was not significantly different between groups. Also in the first group recorded the smallest decrease in hemoglobin at the 5th postoperative day compared to the third and fourth groups. Complications associated with the use of tranexamic acid were not revealed. Conclusion. The method of periarticular infiltration by tranexamic acid in combination with its intravenous use in knee joint replacement is an effective and safe method for reduction of post-operative blood loss.