bluuebunny/crossref_metadata_2025_split huggingface dataset:
Delineating Stacked Pay with Existing and Emerging Diagnostic Tools
Authors: Haustveit K. , Greenwood H. 
Published: January 2018

Abstract
Stacked pay in unconventional plays has emerged as the primary focus for a majority of operators in North America. The number of completion targets range from two zones in the Bakken to more than ten zones in areas of the Permian Basin. Proper development of multi-zone reservoirs will yield the greatest recovery factor for the unit and minimize the drilling hazards and completion challenges related to depletion. Proper development maximizes the propped height while minimizing propped fracture overlap; this combination improves recovery without overcapitalizing the completion.
This paper will review existing and emerging diagnostic tools deployed in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) to identify the number of landing intervals required to effectively drain the Meramec formation. The Meramec formation has produced a number of prolific wells from several benches contained within several hundred feet of reservoir.
The diagnostic tools that will be reviewed in this paper include electromagnetic (EM) proppant detection, radioactive (RA) proppant tracer surveys and offset pressure responses. The EM proppant and RA proppant surveys were used in a vertical well to measure the propped fracture height. The presence of the RA tracer is detected using a spectral gamma ray log; the EM proppant is mapped using a surface array of electric- and magnetic-field receivers. Downhole gauges in a vertical well measured the pressure responses generated during the treatment of an offsetting horizontal well to evaluate the effects of fluid viscosity on fracture height. Results from the diagnostic tools have been integrated into the well spacing strategy for upcoming development units.
Fracture Conductivity, Geochemical, and Geomechanical Monitoring of the Niobrara Formation under Triaxial Stress State
Authors: Iriarte Jessica , Katsuki Daisuke , Tutuncu Azra N. 
Published: January 2018

Abstract
Decreasing fracture effectiveness due to conductivity decay is a strong contributor to the steep production decline commonly observed in shale plays. The conductivity of a fracture is determined experimentally by measuring the pressure drop of a fluid flowing through a uniformly distributed proppant bed in a core with fixed length and height. Fracture conductivity degradation results from damage mechanisms and fluid interactions that occur during hydraulic fracturing operations. Rock softening and proppant embedment are some of these damage mechanisms. The impact of these interactions can be observed by measuring fracture conductivity in the laboratory under stress states similar to field conditions.
This study is based on experiments performed on fractured and propped Niobrara core plugs. The samples were characterized using X-ray Diffraction (XRD), and X-ray Fluorescence (XRF), and helical CT-scans. The experiments were performed on a triaxial stress test assembly to monitor the chemical and mechanical alterations in the formation, proppant, and fluid under reservoir conditions. To achieve this, fluid chemical composition, dynamic and static moduli, and conductivity were obtained. The setup was used for the simultaneous acquisition of stress, ultrasonic compressional and shear wave velocities, flow data and fluid sampling.
The results from this study indicate that stress-dependent, long-term fracture conductivity shows the sharpest decline in the early stages of the experiment. The associated fluid sample analysis indicates that the highest physicochemical dissolution of most of the elements is happening at the early contact of the fluid with the rock and is later enhanced by the pressure increase in the system. A comparison with the conductivity measurements performed on Vaca Muerta samples shows a similar behavior, yet a steeper initial decay than that observed in the Niobrara samples. The difference observed between the two samples is related to the mineralogy of the formation and the high proppant embedment observed in the Vaca Muerta samples. Although higher softening occurred in the Niobrara samples, larger embedment was observed in the Vaca Muerta sample. This experimental observation is an indication that the conductivity damage varies not only with the mineralogical content of the formation, but also with the distribution of minerals along the fracture face.
Geomechanical, geochemical, and flow data integration provided a better understanding of proppant embedment and mineral distribution of the rock. It is the conclusion of this study that even if the intact core sample contains an average mineralogical composition, the heterogeneity caused by variations in the mineralogy at where the fracture is induced has the biggest impact on embedment.
Proppant Transport by a High Viscosity Friction Reducer
Authors: Hu Y. Thomas , Fisher David , Kurian Pious , Calaway Ron 
Published: January 2018

Abstract
Because of potential reduced cost and improved retained conductivity, high viscosity friction reducers (HVFRs) are becoming increasingly popular in hydraulic fracturing stages where linear or crosslinked guar gels are traditionally used. However, concerns remain regarding the proppant transport capability of HVFRs relative to that of traditional linear gels. To address these concerns, the proppant transport capability of a polyacrylamide-based HVFR is compared with that of linear guar at cost-parity concentrations. Correlation between the proppant transport capability and rheological properties of the fluids, including viscosity and elasticity, is also discussed.
A slot flow device was used to visualize the proppant transport performance of each fluid. The fluid concentrations ranged from 2.25 to 4.5 gpt (gallons per thousand gallons) for the HVFRs and 15# to 30# (pounds per thousand gallons) for guar, which were matched to achieve cost-parity between the two classes of fluids. The proppants used were 30/50, 20/40, and 12/20 mesh sand at 2 ppg (pounds per gallon) loading. Comprehensive rheological properties of the carrier fluids were characterized under steady-state and oscillatory shear and correlated with the observed proppant transport behavior.
At least two sand transport mechanisms were observable in the slot flow tests. Small sand particles remained suspended in the fluid and were transported by convection. Large sand particles settled quickly, but top layers of the settled particles crept forward at a slower speed. The HVFR showed significantly better sand transport efficiency than guar at cost-parity concentrations despite the fact that the HVFR had a lower viscosity at high shear rates. The improved sand transport performance may be attributed to two factors: first, sand particles were suspended for a longer time in the HVFR because of its elevated viscosity at lower shear rates in the center of the slot; second, the HVFR's increased elasticity in the high shear regime near the wall further enhanced sand suspension by providing an elastic lifting force to hinder sand settling. The elastic effect on sand settling is estimated to be much larger than the viscous effect for the HVFR investigated herein but is neglibile in guar. Field results validated the capability of the HVFR to carry proppants, including 20/40 mesh coarse sand, in situations where traditional slickwater FRs and linear guar gel failed.
This study demonstrated that the HVFR has superior proppant transport capability, relative to guar, at cost-parity concentrations despite having lower viscosity at high shear rates. The results indicate that the proppant transport performance of fracturing fluids correlates better with their elasticity and low shear viscosity than the high shear viscosity. Additionally, the findings provide much needed proppant transport data for field engineers to make rational choices for the selection of fracturing fluids.
Evaluation of Cement-Isolated Casing Liner and Degradable Particulate Diverter Refracturing Treatments in the Haynesville Shale
Authors: Cadotte R. J. , Crowley Zachary , Elbel Brittany 
Published: January 2018

Abstract
Evolution of completion techniques in the Haynesville Shale has increased the estimated ultimate recovery (EUR) on new wells by almost double compared to the average EUR of wells completed earlier in the reservoirs' development. Because of inadequate early-time completions, large amounts of reserves were bypassed. Refracturing methodology requires reevaluation, given the large inventory of understimulated wells and the potential EUR uplift.
Refracturing methods in the Haynesville Shale have been performed primarily by degradable particulate diversion using a bullhead treatment or, more recently, by cementing a smaller casing liner inside the existing wellbore. The ability to add additional stimulated reservoir volume and restore conductivity requires overcoming the primary challenges of depletion and discrete zonal isolation along the wellbore. The procedures used in both methods to address such challenges and achieve these goals can be analyzed, and the effectiveness of each approach can be measured using production data.
While both methods mentioned have experienced successful results, when evaluating the effectiveness of the treatment, the potential EUR uplift has to be considered since the two methodologies can vary greatly in cost. Certain cases might even require the mechanical isolation method instead of a bullhead method if the integrity of the existing tubulars cannot withstand pressure experienced during a refracturing treatment. The current dataset suggests that the total volume of reserves added from mechanically reworking the wellbore is generally larger than the particulate-diversion method. However, the cost to rework the wellbore and the volume of the refracturing treatment is also generally larger. The refracturing candidate well should be carefully analyzed to determine which type of treatment to apply.
A dataset of more than 40 wells, inclusive of wells restimulated by both techniques, is analyzed to assess the effectiveness of each refracturing technique. The production results were examined along with the original stimulation and restimulation treatments to determine the consistency and viability of the different techniques.
Hydraulic Fracture Design in the Presence of Highly-Stressed Layers: A Case Study of Stress Interference in a Multi-Horizontal Well Pad
Authors: Ueda Kenji , Kuroda Shintaro , Rodriguez-Herrera Adrian , Garcia-Teijeiro Xavier , Bearinger Doug , Virues Claudio J. , Tokunaga Hiroyuki , Makimura Dai , Lehmann Jurgen , Petr Christopher , Tsusaka Kimikazu , Shimamoto Tatsuo 
Published: January 2018

Abstract
A design of hydraulic fracturing in variably-stressed zones is one of key components for an effective multi-zone, multi-horizontal well pad treatment. In the recent literature, optimum completion strategies catering for stimulation-induced in-situ stress changes are discussed, however, only few of these focus on vertical stress changes and its impact on multi-zone fracture geometries. In this paper, we present an approach to design contained hydraulic fractures in a high stress layers by studying the role of vertical stress shadowing on actual field data.
In modeling hydraulic fractures with pseudo-3D models, if fracture simulations are initiated in high stress zones, "artificially" unbounded height growth results in very limited lateral propagation. On the other hand, 3D hydraulic fracturing models are too computationally expensive to optimize large design jobs, for example, in multi-horizontal well pads. In this paper, we employ a Stacked Height Growth Model, whereby fractures are also discretized vertically yet retain the numerical formulation pseudo-3D models. Coupling with finite element stress solvers then allows to identify vertical stress changes in the vicinity of induced hydraulic fractures and to understand the interference between hydraulic fracture sequences and their respective microseismic signatures.
Considering a potential combination of fracturing sequences, it was revealed that stress perturbations from the neighboring well hydraulic fractures initiating from low stress layers can be used to increase stress within the same zone and also potentially reduce stresses in higher-stress layers above and below. By modeling and calibrating an actual multi-zone, multi-horizontal stimulation job, we elaborate on the benefits of increasing stress barriers before fracturing in higher-stress layer to avoid the chances of re-fracturing from high stress zones. Regarding hydraulic fracture geometries, we explain our results by analyzing actual microseismic observations with respect to simulated stress patterns after stimulation. We explore the notion of deliberately ordering hydraulic fracture to manage vertical interference and create more contained fractures in a multi-zone horizontal well pad.
Fracturing in a higher-stress zone will naturally divert the energy into low stress, potentially unproductive zones. In an effort to manage this phenomenon, this paper presents one of the few data-rich case studies on multi-zone, multi-well engineered stimulation design. The approach shown in this paper can be a helpful reference to understand fracture height growth in the presence of both vertical and horizontal stress shadowing.
Applying Subsurface DNA Diagnostics and Data Science in the Delaware Basin
Authors: Silva J. , Ursell L. , Percak-Dennett E. 
Published: January 2018

Abstract
The application of DNA sequencing in the oil industry provides a non-invasive, economical, and high-resolution data source for elucidating hydrocarbon fluid movement. DNA Diagnostics could be used to understand drainage height and inform the vertical spacing of wells, as well as provide the ability to derive/predict depositional environments based on biomarker signatures.
To date, DNA sequencing has been applied in over 200 wells across 8 basins in North America, including the Permian, Eagle Ford, and Bakken. Subsurface DNA Diagnostics are used to guide well spacing, evaluate well interference (e.g. frac hits), determine oil potential, and understand production profiling.
The effective application of DNA sequencing in the oilfield requires the use of advanced data science techniques and machine learning. To date, the industry's application of machine learning has been focused on production and completion parameters that provide a statistical view of the subsurface. In oilfield DNA sequencing, millions of data points per well are generated; and to apply these direct measurements to the subsurface requires novel machine learning techniques which are presented here.
In this analysis, we present the results of DNA sequencing from a 33-well study in the Delaware Basin. Well cuttings and produced fluid samples were obtained in a non-invasive manner to generate stratigraphically unique signals for hydrocarbon fluid movement. Various data science techniques are presented to interpret the data with initial observations providing a novel view into production across formations.
Additionally, we will provide an overview of future work and how we plan to augment the dataset with other more conventional techniques in order to fine-tune the uncertainties associated with a new data source and methodology.
Effectiveness of Geometric Versus Variable Shot Clusters to Stimulate a Percolating Crack Network Capable of Sustaining Flow
Authors: Ardakani E. P. , Baig A. M. , Urbancic T. I. , Kahn D. , Rich J. , Langton D. , Silver K. 
Published: January 2018

Abstract
The perforation strategy for a hydraulic fracture completion for an unconventional reservoir can have a very large influence on the overall success of the injection program at effectively stimulating that network. To evaluate differences in perf clustering methodologies, operators are frequently in need of observational evidence to suggest which strategy is most efficient. We present a paper where we look at a detailed analysis of microseismicity for different stages with different completion programs.
While event distributions tend to be the first and most frequently examined aspect of a microseismic monitoring effort, because the generation of a microseismic event is not immediately diagnostic of fluid-induced fracturing, the event clouds tend to overestimate the effective area of fracturing. In order to gain further insight into how microseismic events describe effective fracture growth, a deeper look at the waveforms through techniques like Seismic Moment Tensor Inversion (SMTI) and subsequent stress inversion can be effective. These steps are necessary to describe the discrete network of cracks, from the microseismic data. Using a fracture network topology approach, the network can then be characterized in terms of its ability to percolate fluids.
We compare how cracks behave for a regular geometric shot cluster (GSC) and a variable shot cluster (VSC) and assess variations in the stimulations. Both shot clusters were completed in consecutive stages of the same lateral. The mechanisms from the GSC stages show shear-dominant mechanisms with opening and closing components in roughly equal proportions, while the VSC stages have a higher concentration of shear-tensile opening failures. Furthermore, the GSC stages showed modest connectivity around the treatment well relative to the VSC stages, which showed significant growth of connected fractures away from the treatment well. Since the VSC stages also showed relatively more stable stress behaviour than the GSC stages, these observations suggest that stability in stresses allows for steady growth of the fracture network across the reservoir.
This type of higher-order analysis of microseismic data is critical to establishing value from this data stream in terms of completion evaluation. The recognition that each microseismic event is tied to the rupture of a crack in the reservoir allows for these types of comparisons to be made in a robust fashion and be tied to the underlying geomechanics that governs the type of response from one type of completion to the other.
Parent-Child Fracture Interference: Explanation and Mitigation of Child Well Underperformance
Authors: Manchanda Ripudaman , Bhardwaj Prateek , Hwang Jongsoo , Sharma Mukul M. 
Published: January 2018

Abstract
In the last few years, several operators in unconventional plays have seen fracture interference between existing production wells (parent wells) and newly fractured infill wells (child wells). This interference usually has a negative impact on the production from both the parent and child wells. In this work, a mechanistic explanation of the parent-child interaction is provided using results from poro-elastic simulations. Child well underperformance is studied in detail and mitigation strategies are discussed. Results shown in this work quantify the impact of depletion and refracturing on child well fracturing.
In this work, a 3D reservoir-scale poro-elastic geomechanics software (Multi-Frac) was used to model the depletion of the parent well region and calculate its impact on pressure, total stress and effective stress. Refracturing simulations of the parent well were conducted to showcase the importance of a good refracturing operation in reducing the probability of fracture hits from the child well to the parent well. The poro-elastic capabilities of Multi-Frac help in analyzing the stress changes in the reservoir induced by depletion and re-fracturing. These stress changes explain the observed fracture hits from child wells.
The stress changes and the depletion patterns also explain the underperformance of the child well fractures. Implications of depletion on both total stress and effective stress are analyzed. Decrease in the total stress near the parent well creates a zone of attraction for the child well fracture, thus, causing the child well fracture to be created in a region of extensive depletion. Depletion induced increase in the effective stress was observed from the simulation. This increase in the effective stress makes fracture network creation harder and thus reduces the productivity of the child well fractures. Re-fracturing of the parent well showed an increase in the stress in the reservoir and can help avoid fracture hits from neighboring child wells. Thus, re-fracturing a parent well and subsequently fracturing a child well can be a possible strategy to mitigate the impact of fracture hits and thereby improve the EUR of the pad.
The three main factors that induce interference between parent wells and child wells are reservoir depletion, reservoir total stress changes and reservoir effective stress changes. All of these factors have been studied and quantified in this work. Modifications to parent well fracturing treatment design, refracturing treatment design and child well fracturing treatment design are suggested to improve productivity.
Hydraulic Fracture Interaction with Cemented Natural Fracture: A Three Dimensional Discrete Element Method Analysis
Authors: Lee Hunjoo P. , Razavi Omid , Olson Jon E. 
Published: January 2018

Abstract
The propagation path of hydraulic fracture is significantly affected by the properties of cemented natural fractures (i.e., veins), such as, stiffness, tensile and shear strength, and flow characteristics. Moreover, the magnitude of stress anisotropy can control the results of hydraulic fracture crossing or diverting into the vein. To study the effect of vein properties and the differential stress on the interaction of hydraulic fractures with mineral-filled veins, we employed a three-dimensional (3D) Discrete Element Method (DEM) model which couples the fluid flow and the bonded-particle assembly. The hydraulic fracture interaction with the vein was investigated by monitoring the bond breakages and measuring the fracture diversion distance along the vein before kinking back into the rock matrix. Numerical results are in good agreement with the fracture diversion results from the published experimental and numerical SCB tests of Marcellus shale with calcite-filled veins. The propagating hydraulic fracture is more likely to divert into the veins with smaller approach angle. Increasing the differential stress leads to fracture crossing than diversion into the vein. For veins with greater stiffness than the host rock, microcracks were generated in the vein before the hydraulic fracture intersected it. For tight formations with stiffer veins, the vein permeability did not have much influence on the fracture diversion result since the damage induced by the stress concentration ahead of the hydraulic fracture tip dominated the fluid flow in the vein.