bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Experimental Study of Coefficient of Discharge for Consistent Hole Perforating and the Effect on Limited Entry Designs
Authors: Thiessen Scott , Han Oliver , Ahmed Ramadan , Elgaddafi Rida 
Published: April 2021

ABSTRACT
In hydraulic fracturing, determining the perforation pressure loss is a critical step in the design strategy, on-site troubleshooting diagnostics and post-fracture analysis. Historically, the most widely assumed and thus unknown components in the perforation friction equationare the coefficient of discharge and the holistic perforation diameter.
The perforation coefficient of discharge has long been assumed as a dynamic variable dependent on the amount of fluid and proppant pumped through the perforations. This variable becomes increasingly important when clusters are spaced closer together and fewer perforations are shot such as in a limited entry design. Limited entry is a perforating technique used to generate uniform fractures along the wellbore by creating appropriate pressure differentials from cluster to cluster. With the adoption of consistent hole perforating shaped charges, the perforating diameters are more consistent and predictable. While not all consistent hole shaped charges have low diameter variability, the perforating diameters downhole are no longer an unknown, particularly after the introduction of downhole cameras. Therefore, the coefficient of discharge is the only unknown variable remaining.
This paper presents an experimental methodology to accurately define the true coefficient of discharge in common completions perforated by a known consistent hole shaped charge. The test setup is illustrated, detailed test steps are discussed, and experimental data with correlations of rate per perforation and discharge coefficient is presented.
Completions tested included 4-1/2", 5", and 5-1/2" casings in common weights and grades. Various perforating strategies were examined such as single shot and angled shot. Critical parameters such as entry hole diameters were made by the actual shaped charges and measured before and after the test. Freshwater and slickwater were used as hydraulic fluid and circulated at real-world pump rates through each perforation to simulate the actual field flow conditions.
Based on the study, several correlations for the coefficient of discharge of flow through a perforation are created considering casing thickness, entry hole diameter and rate per perforation for the given consistent hole shaped charges. These correlations can improve perforation and fracturing designs where perforation friction are important variables.
Proppant Distribution in Newly Completed and Re-Fractured Wells - An Eagle Ford Shale Case Study
Authors: Allison Justin , Roberts Glyn , Hicks Brad Hicks , Lilly Todd 
Published: April 2021

Abstract
Fracture treatments and stage designs for new wells have evolved considerably over the past decade contributingto significant production growth. For example, in the acreage discussed hererecently used higher intensity fracturing methods provided an ~80% increase in recovery rates compared with legacy wells. Older wells completed originally with less efficient techniques can also benefit from these more up-to-date designs and treatments using re-fracturing methods. These offer the prospect of economically boosting production in appropriately selected wells.
While adding in-fill wells has often been favored by Operators as a lowerrisk option the number of wells being re-fractured has grown every year for the last decade. In this case study two adjacent Eagle Ford wells, comprising a newly completed and a re-fractured well, allow both methods to be considered and compared. Completion design and fracture treatment effectiveness are evaluated using the uniformity of proppant distribution at cluster and stage level as the primary measure. Perforation erosion measurements from downhole video footage is used as the main diagnostic.
Novel data acquisition methods combined with successful well preparation provided comprehensive and high-quality datasets. The subsequent proppant distribution analysis for the two wells provides the highest confidence results presented to date. Clear, repeatable trends in distribution are observed and these are compared across multiple stage designs for both the newly completed and re-fractured well. Variations in design parameters and how these effects distribution and ultimately recovery are discussed. These include changes to perforation count per cluster, cluster spacing, cluster count per stage, stage length, perforation charge size and treatment rates and volumes. As a final consideration production records for the evaluated wells are also discussed.
Historical industry data shows that the number of wells being re-fractured increases relative to the number of newly drilled wells being completed during periods of low oil and gas prices. With the industry again facing harsh economic realities an increasing number of decisions will be made on whether new or refractured wells, or a combination of both, provide the best solution to replace otherwise inevitable production decline. This paper attempts to provide a detailed understanding of how proppant distribution, as a significant factor in production for hydraulically fractured wells, can be evaluated and considered in these decisions.
Natural Fracture Dominated Distribution of Slurry During a Multi-Cluster Hydraulic Fracturing Stage: A Marcellus DAS/DTS Case Study
Authors: Romberg Eric , Adams Andrew , Edwards Jason , Levon Taylor 
Published: April 2021

Abstract
In this paper, the authors examine the impacts of natural fractures on the distribution of slurry in a well with a permanent fiber installation and drill bit geomechanics data. Additionally, they propose a framework for further investigation of natural fractures on slurry distribution.
As part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL), the operator monitored the drilling of a horizontal Marcellus Formation well with drill bit geomechanics, and subsequent stimulation phase with a DAS/DTS permanent fiber installation. Prior to the completion, the authors used an analytical model to examine the theoretical distribution of slurry between perforation clusters from a geomechanics framework. A perforation placement scheme was then developed to minimize the stress difference between clusters and to segment stages by the intensity of natural fractures while conforming to standard operating procedures for the operator's other completions.
The operator initially began completing the well with the geomechanics-informed perforation placement plan while monitoring the treatment distribution with DAS/DTS in real time. The operator observed several anomalous stages with treating pressures high enough to cause operational concerns. The operator, fiber provider, and drill bit geomechanics provider reviewed the anomalous stages’ treatment data, DAS/DTS data, and geomechanics data and developed a working hypothesis. They believed that perforation clusters placed in naturally fractured rock were preferentially taking the treatment slurry. This phenomenon appeared to cause other clusters within the stage to sand-off or become dormant prematurely, resulting in elevated friction pressure. This working hypothesis was used to predict upcoming stages within the well that would be difficult to treat. Another perforation placement plan was developed for the second half of the well to avoid perforating natural fractures as an attempt to mitigate operational issues due to natural fracture dominated distribution.
Over the past several years, the industry's growing understanding of geomechanical and well construction variability has created new limited-entry design considerations to optimize completion economics and reduce the variability in cluster slurry volumes. Completion engineers working in naturally fractured fields, such as the Marcellus, should consider the impact the natural fractures have on slurry distribution when optimizing their limited-entry designs and stage plan.
Turning a Breakthrough Technology into a Scalable Process: Sealed Wellbore Pressure Monitoring
Authors: Iriarte Jessica , Hoda Samid , Guest Ryan , Van Domelen Mary 
Published: April 2021

Abstract
A breakthrough patent-pending pressure diagnostic technique using offset sealed wellbores as monitoring sources was introduced at the 2020 Hydraulic Fracturing Technology Conference. This technique quantifies various hydraulic fracture parameters using only a surface gauge mounted on the sealed wellbore(s). The initial concept, operational processes, and analysis techniques were developed and deployed by Devon Energy. By scaling and automating the process, Sealed Wellbore Pressure Monitoring (SWPM) is now available to the industry as a repeatable workflow that greatly reduces analysis time and improves visualizations to aid data interpretations.
The authors successfully automated the SWPM analysis procedure using a cloud-based software platform designed to ingest, process, and analyze high-frequency hydraulic fracturing data. The minimum data for the analysis consists of the standard frac treatment data combined with the high-resolution pressure gauge data for each sealed wellbore. The team developed machine learning algorithms to identify the key events required by a sealed wellbore pressure analysis: the start, end, and magnitude of each pressure response detected in the sealed wellbore(s) while actively fracturing offset wells. The result is a rapid, repeatable SWPM analysis that minimizes individual interpretation biases.
The primary deliverables from SWPM analyses are the Volumes to First Response (VFR) on a per stage basis. In many projects, multiple pressure responses within a single stage have been observed, which provides valuable insight into fracture network complexity and cluster/stage efficiency. Various methods are used to visualize and statistically analyze the data.
A scalable process facilitates creating a statistical database for comparing completion designs that can be segmented by play, formation, or other geological variations. Completion designs can then be optimized based upon the observed well responses. With enough observations and based on certain spacings, probabilities of when to expect fracture interactions could be assigned for different plays.
High Pressure, High Temperature Bioreactors as a Biocide Selection Tool for Hydraulically Fractured Reservoirs
Authors: Ferrar Joseph , Maun Philip , Wunch Kenneth , Moore Joseph , Rajan Jana , Raymond Jon , Solomon Ethan , Paschoalino Matheus 
Published: April 2021

Abstract
We report the design, operation and biogenic souring data from a first-of-its kind suite of High Pressure, High Temperature (HPHT) Bioreactors for hydraulically fractured shale reservoirs. These bioreactors vet the ability of microbial control technologies, such as biocides, to prevent the onset of microbial contamination and reservoir souring at larger experimental volumes and higher pressures and temperatures than have been previously possible outside of field trials.
The bioreactors were charged with proppant, crushed Permian shale, and sterile simulated fracturing fluids (SSFF). Subsets of bioreactors were charged with SSFF dosed with either no biocide, tributyl tetradecyl phosphonium chloride (TTPC, a cationic surface-active biocide), or 4,4-dimethyloxazolidine (DMO, a preservative biocide). The bioreactors were shut in under 1,000-2,500 psi and elevated temperatures for up to fifteen weeks; hydrogen sulfide (H2S) and microbial counts were measured approximately once per week, and additional microbes were introduced after weeks three and five.
Across two separate studies, the bioreactors containing no biocide soured within the first week of shut-in and H2S concentrations increased rapidly beyond the maximum detectable level (343 ppm) within the first three to six weeks of shut-in. In the first study, the bioreactors treated with TTPC soured within two weeks of shut-in (prior to the first addition of fresh microbes), and H2S concentrations increased rapidly to nearly 200 ppm H2S within the first six weeks of shut-in and beyond the maximum detectable level after fifteen weeks of shut-in. The bioreactors containing DMO did not sour during either study until at least the first addition of fresh microbes, and higher levels of the preservative biocide continued to prevent the biogenic formation of H2S even during and after the addition of fresh microbes. Microbial counts correlate with the H2S readings across all bioreactor treatments. The differentiation in antimicrobial activity afforded by the different types of biocide treatments validates the use of these simulated laboratory reservoirs as a biocide selection tool.
This first-of-its-kind suite of HPHT Bioreactors for hydraulic fracturing provides the most advanced biocide selection tool developed for the hydraulic fracturing industry to date. The bioreactors will guide completions and stimulation engineers in biocide program optimization under reservoir-relevant conditions prior to beginning lengthy and expensive field trials.
Utilization of Hydraulic Completion Units in the Delaware Basin
Authors: Completion Team Matador Resources Company, , Frantz J. H. , Tourigny M. L. , Griffith J. M. 
Published: April 2021

Abstract
In conjunction with the industry and basin-wide paradigm shift to drilling and completing extended laterals, Matador Resources Company (the operator) made significant plans in 2018 that would focus activity toward wells with laterals greater than one-mile. One operational hurdle to overcome in this shift change was the effective execution of removing frac plugs and sand at increased depths during a post-stimulation frac plug millout. Utilization of coiled-tubing units (CTUs) had been proven to be a successful millout method in one-mile laterals, but not without risk. Rig-assisted snubbing units coupled with workover rigs (WORs) provided for less risk with higher pulling strength capabilities and the ability to rotate tubing, but would often require operational time of up to twice that of typical coiled-tubing unit millouts. The stand-alone, rigless Hydraulic Completion Unit (HCU) was ultimately tested as a solution and proved to alleviate risks in extended lateral millouts while providing operational time and cost comparable to coiled-tubing units.
The operator has since performed post-stimulation frac plug millouts on ∼45 horizontal wells in the Delaware Basin using HCUs. The majority of these wells carried lateral lengths of over 1.5 miles. Results and benefits observed by the operator include but are not limited to the list below: 1.) Ability to safely and consistently reach total depth (TD) on extended laterals through increased snubbing/pickup force and the HCU's pipe rotating ability 2.) Ability to pump at higher circulation rates in high-pressured wells (&gt;3,500 psi wellhead pressure) to assist in effective wellbore cleaning 3.) Smaller footprint which allows for the utilization of two units simultaneously on multi-well pads 4.) Time and cost comparable to a standard coiled-tubing millout, particularly on multi-well pads.
Improved Treatment Distribution Through Oriented Perforating
Authors: Snyder Jon , Cramer David , White Matt 
Published: April 2021

Abstract
Perforation-imaging studies have indicated highly variable results on effectively treating all perforation clusters within a given fracturing stage in horizontal well plug-and-perf applications, even when limited entry designs were used. A field test was executed to trial differing perforating designs and levels of perforation friction for identifying a preferred technique for evenly distributing treatment volume along the lateral.
The test was implemented in a horizontal well in the Eagle Ford formation of south Texas. After treatment and plug drill-out operations were completed, a downhole camera was run to visualize perforation entry holes along the entire lateral section. Shaped perforating charges described as equal entry hole charges were used in all stages. The resulting images were analyzed to determine entry hole dimensions and erosion characteristics to determine if alternate perforating strategies provided improved results, as compared to the standard design of multi-phase perforating with 1200 psi of perforation friction.
Test results indicate that orienting perforations in a straight line (zero-phase) along the high side of the wellbore significantly improved treatment distribution among perforation clusters. Oriented perforating achieved this benefit without needing to increase initial perforation friction beyond the area standard of 1200 psi. Another result from this project was development of a statistical process for evaluating perforation entry hole erosion data. Entry hole erosion datasets are complex and difficult to analyze. The statistical process presented in this paper demonstrates a clear way to compare the effectiveness of different perforation designs. This paper also covers the operational difficulties encountered during the project which added complexity to analyzing the results. Lastly, this paper offers suggestions for future modifications for oriented perforation designs to further improve limited entry effectiveness.
Modeling of Proppant Distribution During Fracturing of Multiple Perforation Clusters in Horizontal Wells
Authors: Sinkov Konstantin , Weng Xiaowei , Kresse Olga 
Published: April 2021

Abstract
Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Proppant Placement in the Barnett Shale When Perforations are Selected in Like-Rock
Authors: Juarez Tracy , Francis Caleb , Freels Stephanie , Sinosic Brian , Wutherich Kevin 
Published: April 2021

Abstract
In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer.
This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data.
The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
An Improved Daily Weather Generator for the Assessment of Regional Climate Change Impacts
Authors: Khazaei Mohammad Reza , Hasirchian Mehraveh , Zahabiyoun Bagher 
Published: April 2021

Abstract
Weather Generators (WGs) are one of the major downscaling tools for assessing regional climate change impacts. However, some deficiencies in the performance of WGs have limited their usage. This paper presents a method for correcting the low-frequency variability (LFV) of precipitation in the Improved Weather Generator (IWG) model. The method is based on bias correction in the monthly precipitation distribution of the generated daily series. The performance of the modified model was tested directly by comparing the statistics of generated and observed weather data for 14 stations, and also indirectly by comparing the characteristics of simulated stream-flows of a basin from the simulations run based on generated and observed weather data. The results showed that the method not only corrected the LFV of precipitation but also improved the reproduction of many other statistics. The provided IWG2 model can serve as a useful tool for the downscaling of General Circulation Models (GCMs) scenarios to assess regional climate change impacts, especially hydrological effects.
Prediction of groundwater drawdown using artificial neural networks
Authors: Gholami Vahid , Sahour Hossein 
Published: April 2021

Abstract
Groundwater drawdown is typically measured using pumping tests and field experiments; however, the traditional methods are time-consuming and costly when applied to extensive areas. In this research, a methodology is introduced based on artificial neural network (ANN)s and field measurements in an alluvial aquifer in the north of Iran. First, the annual drawdown as the output of the ANN models in 250 piezometric wells was measured, and the data were divided into three categories of training data, cross-validation data, and test data. Then, the effective factors in groundwater drawdown including groundwater depth, annual precipitation, annual evaporation, the transmissivity of the aquifer formation, elevation, distance from the sea, distance from water sources (recharge), population density, and groundwater extraction in the influence radius of each well (1000 m) were identified and used as the inputs of the ANN models. Several ANN methods were evaluated, and the predictions were compared with the observations. Results show that, the modular neural network (MNN) showed the highest performance in modeling groundwater drawdown ​​(Training R-sqr = 0.96, test R-sqr = 0.81). The optimum network was fitted to available input data to map the annual drawdown ​​across the entire aquifer. The accuracy assessment of the final map yielded favorable results (R-sqr = 0.8). The adopted methodology can be applied for the prediction of groundwater drawdown in the study site and similar settings elsewhere.