bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Case Study: Optimizing Multicluster Stimulation Uniformity in Horizontal Wells
Authors: Kresse Olga , Sinkov Konstantin , Hobbs Brandon 
Published: January 2023

Abstract
The performance and completion efficiency of horizontal multistage hydraulically fractured wells stimulated using the plug-and-perf technique are affected by the uniformity of the multiple perforation cluster treatment. Depending on reservoir heterogeneity, perforation design, and pumping schedule, uneven distribution of fluid and proppant among fractures connected to different perforation clusters can be defined by wellbore proppant transport hydrodynamics, fracture propagation mechanics, or a complex interplay of both. A modeling case study exploring strategies to mitigate nonuniformity of cluster stimulation is presented. Approaches to perforation and treatment optimization are chosen based on consideration of reservoir properties and their heterogeneity. A numerical model coupling a recently developed wellbore flow simulator and an advanced fracture simulator enables comprehensive simulations including both realistic fracture and wellbore modeling for complex perforation designs, treatment schedules, and distributions of reservoir inhomogeneities. The wellbore simulator considers proppant transport and settling, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport to perforations. The fracture simulator models fracture growth, fluid flow, proppant transport inside fractures, and interaction between fracture branches due to stress shadow effect. The interaction between hydraulic and pre-existing natural fractures plays a critical role during fracturing treatments in formations with pre-existing discrete fracture network (DFN). The model considers the effect of formation heterogeneity on fracture propagation, arrest of hydraulic fractures, crossing and opening of natural fractures depending on their properties, fluid viscosity, rate, and stress conditions. Several approaches for optimization of proppant distribution are suggested for cases showing nonperfect proppant transport efficiency caused by high proppant grain inertia. Tapered perforation designs enable achieving more even proppant distribution. However, perforation distribution among clusters providing best stimulation uniformity is sensitive to uncertainties in characterization and heterogeneity of reservoir and discrete fracture network properties. A combination of tapered perforation design and the suppression of inertial effects by increasing carrier fluid viscosity is more robust with respect to reservoir properties variation.
Integration of Fracturing Pressure Diagnostics with Multi-Well Smart Tracer Program for Hydraulic Fracturing Stimulation and Diversion Efficiency Assessment
Authors: Shokanov Talgat , Oliver John , Pena David , Shokanov Adilkhan 
Published: January 2023

Abstract
Multi-stage hydraulic fracturing stimulation and completion programs now account for up to 70% of total well costs (Shokanov et al. 2019). Faced with unprecedented economic pressures on the entire oil and gas industry, upstream operations must take a serious look at increasing their efficiency regarding the use of completion money and ensuring that increased production results warrant the expenditure. Completion operations must develop systems and processes that deepen insight into complex reservoir performance, right-size well spacing, and focus on data-driven stimulation designs that optimize economics.
This paper highlights one such effort in the Tennessee Colony Field project in East Texas. A novel ultra-high-resolution nanoparticle tracer played a key role in delivering useful data that led to a comprehensive understanding of the reservoir response to stimulation efforts at a stage level. Additional multi-well studies in turn led to developing a full reservoir plan and optimizing well spacing.
The state-of-the-art ultra-high-resolution nanoparticle tracers were added before and after each diverter stage for flow profile mapping and diversion efficiency assessment. In addition, a sampling campaign of adjacent wells was initiated to identify potential communication between old and new wells. The tracers’ data integration with fracturing pressure diagnostics helped to improve the target reservoir development approach and provided a live performance flow profile for the entire field. This data was used to optimize completion and workover strategies, achieve the best well productivities, and significantly enhance the understanding of the reservoir geology for the entire field.
This paper describes the project results including the hydraulic fracturing pressure diagnostics with a multi-well tracer program integration. Since tracers were analyzed over several months from numerous wells, the operator has gained insight into continuous flow profiles leading to optimizing well performance on a regular basis as new production-diagnostic results are received.
Results from a Collaborative Industry Study on Parent/Child Interactions: Bakken, Permian Basin, and Montney
Authors: McClure Mark , Albrecht Magdalene , Bernet Carl , Cipolla Craig , Etcheverry Kenneth , Fowler Garrett , Fuhr Aaron , Gherabati Amin , Johnston Michelle , Kaufman Peter , MacKay Mason , McKimmy Michael , Miranda Carlos , Molina Claudia , Ponners Christopher , Ratcliff Dave , Rondon Janz , Singh Ankush , Sinha Rohit , Sung Anthony , Xu Jian , Yeo John , Zinselmeyer Rob 
Published: January 2023

Abstract
This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.
Combined Video and Ultrasonic Measurements for Fracture Diagnostics – Greater than the Sum of the Parts
Authors: Tymons Tobben , Roberts Glyn , Troup Duncan 
Published: January 2023

Abstract
Downhole imaging technology has been widely utilized in recent years to help diagnose proppant distribution during hydraulic fracturing operations. Abrasion leading to entry hole enlargement provides strong evidence of proppant placement into individual perforations, and treatment volume can be inferred by measuring the magnitude of this erosion. Results from individual perforations are easily aggregated to cluster and stage level to provide information on overall treatment distribution.
Two different technologies have been deployed for this purpose – an array of downhole video cameras able to capture a full 360˚ view of the borehole and, more recently, multi-transducer ultrasonic instruments. These services have been considered competitors, and arguments for and against both technologies have included their relative measurement resolutions and how this impacts result accuracy, along with sensitivity to 'stick and slip' effects on toolstring motion. Both technologies are also affected to differing degrees by the well fluid and the presence of diverters and proppant in perforations. The recent introduction of a toolstring able to simultaneously acquire images from both sensor types affords the opportunity to objectively compare results acquired under identical conditions and establish their merits and limitations.
The paper considers the underlying physical principles of each of the measurements and reviews in detail the real world results from North American wells that have been logged using both technologies.
The aim of the paper is to provide a more complete understanding of the technologies involved, and how they can be viewed as complementary rather than competitive when they are run simultaneously, allowing potential users to make fully informed decisions on when, why and how to deploy them. We will also demonstrate how the information derived from simultaneous application is of greater value than that derived from the individual technologies in isolation, and how this can be applied to further enhance completion design and frac execution for unconventional wells.
Towards A Net-Zero Future: Decarbonizing Hydraulic Fracturing Operations
Authors: Narang Rishika , Joshi Vaibhav , Goyal Rajat 
Published: January 2023

Abstract
This study discusses sensor-based, real-time detection and monitoring of emissions generated at a wellsite during a hydraulic fracturing treatment. The sensors recorded live data, which was visualized on dashboards and generated alarms whenever the threshold levels were reached beyond the normal emission rate to tell when the workers were being exposed to unsafe levels of greenhouse gas (GHG) and other noxious elements. Algorithms were also developed to check for fuel adulteration and equipment health, identifying low-performing assets that might have undergone wear and tear.
The sensing device detected emissions using multiple electrochemical sensors that can identify particulate matter (PM2.5, PM10, PM1), carbon monoxide (CO), carbon dioxide (CO₂), sulphur dioxide (SO₂), nitrogen dioxide (NO₂), ozone (O₃), hydrogen sulfide (H₂S), and methane (CH4), along with temperature, humidity levels, and GPS coordinates. These readings were then transferred via an Application Programming Interface (API) to a cloud server, where they were stored in a database along with a timestamp. Advanced data visualization and analytics dashboards were created so that users could monitor direct emissions in real-time.
The sensing device was deployed at various locations: near the pump exhaust (keeping wind flow in mind) to capture outdoor job-related emissions as well as in a closed space to study exhaust efficiency. The sensor successfully captured and transmitted live data of all the gases emitted, without manual calculation. Increased levels of NO₂ were observed after sunset (because NO₂ converts into other derivatives and ozone in sunlight). Algorithms were leveraged to interpolate readings that might be missed by the sensor, due to a power cut or human mishandling, for continuous visualization of emissions taking place. Because the sensor device is customizable to measure emissions data for each type of gas, it will be extremely useful for leak detection for both supplied and produced oil and gas and for checking corrosion in pipelines or wellsite facilities.
Such sensor devices are intrinsically safe, portable, easy to install, scalable, nationally certified, and have GPS tracking enabled. To contribute to environmental sustainability and for the world to see a net-zero emissions future, the oil and gas industry has transformed itself using advanced digital technologies. This pilot study, aimed at directly measuring and visualizing emissions in an industrial setting, is one of the major steps toward more pervasive emission monitoring and helping the industry achieve its net-zero goals.
Understanding the Shear History of Various Loadings of Friction Reducers and the Associated Impact on the Fluid's Stability, Pipe Friction Reduction, and Effect on Proppant Transport and Deposition in Both Fresh Water and Brine Base Fluid.
Authors: Anschutz Don , Wildt Pat , McGill Mark , Lowrey Terry , Contreras Kevin 
Published: January 2023

Abstract
The industry is constantly looking for ways to increase completions efficiency, increase well production, and reduce cost. Unconventional completions, on average, use around 4.5 million gallons of water carrying up to 10 million pounds of frac sand. Volumes vary greatly, from under 1 million gallons of water carrying a couple million pounds of frac sand to greater than 10 million gallons of water carrying up to 20 million pounds of frac sand. Changes in the loading of additives can greatly impact the completion costs. Understanding the advantages, or disadvantages, of any changes made to the frac design can help with efficiency and costs, if implemented correctly. The research in this paper highlights how shear stress, proppant transport, and the deposition profile change based on various loadings of commonly used Friction Reducer (FR) mixed in fresh water and brine water.
A 1,500-foot, 0.62-inch internal diameter flow loop is utilized to develop a shear history based on a shear rate equivalent of 100 barrels per minute (BPM) down 11,000 feet of 4.5-inch internal diameter (ID) casing/pipe. FR and High Viscosity Friction Reducers (HVFR) are evaluated at 0.75, 1.5, 3.0 and 5.0 gallons per thousand (gpt) loadings in fresh water and brine as well as guar with a loading of 5.0 gpt in brine (effective polymer loading 20 lbs./1000 gals). Pre-shear and post-shear viscosity readings are recorded for each gel concentration.
The shear conditioned fluid is then utilized to construct the test slurry for the subsequent transport/deposition test. The test slurry is injected into a large slot flow apparatus (10′H × 20′L), with a transverse fracture configuration (top-middle-bottom injection points along the vertical centerline) with an average 0.375-inch width tortuous slot flow path. A typical test entails approximately 750 lbs. of proppant, comprised of 80% by weight of 100 mesh proppant 1.5 pounds of proppant added per gallon (PPA) and 20% by weight of 40/70 mesh proppant at 1.5 PPA. Slurry test pump rate target is 13 gallons per minute (gpm) to simulate the lower shear rate in a far-field fracture environment. Fluid viscosity measurements are recorded post blender and post slot flow apparatus. A deposition profile is generated for each FR loading and job design.
The data are compiled to demonstrate the effects of shear history on the carrier fluid viscosity, as well as to document transport and deposition behavior based on the various loadings of the different friction reducers and pump schedules.
Please Fill in Your Manuscript Title. Impacts of Perforating and Hydraulic Re-Fracturing on Expandable Casing Patches
Authors: Kraynek Michael , Miskimins Jennifer , Eustes Alfred , Joshi Deep , Balderston Mark 
Published: January 2023

Abstract
Re-fracturing is a common technique to ensure the maximum recovery from low-permeability, unconventional reservoirs. Generally in such reservoir systems, optimal gains are made from treating new areas of the reservoir that were unstimulated during the initial completion. To be successful under such circumstances, diversion away from depleted sections of the wellbore is critical. This paper discusses laboratory testing and subsequent finite element modeling (FEM) of full-length expandable casing patches deployed in several refracturing treatments in the Denver-Julesburg Basin, Colorado.
Short sections of casing patches were deployed in 4.5′, 13.5# casing. These sections included unanchored and anchored patch components. One type of each section (anchored and unanchored) was then perforated with a full-size perforating gun, 4 shot each section, 90° phasing. The perforating took place at the Edgar Mine Testing Facility in Idaho Springs, Colorado. Both the anchored and unanchored, perforated and unperforated, patch/casing sections were then push/pull-tested to determine friction factors and the impacts of the perforating on the patch/casing interface. These results were then incorporated into FEM modeling to determine the ability of the full-size, field-deployed patch to remain stationary and the impact such would have on perforation alignment during treatment conditions.
Both the push/pull tests and the subsequent FEM modeling suggest that the full-length casing patch exhibits only a minimal shift during the application of the forces associated with the hydraulic fracturing process. Some miss-alignment of perforations may occur but not to the level that they negatively impact the treatment success. These results align with the field trials which indicate positive re-fracturing treatment results. This unique project tested the viability of full-length casing patches in the refracturing process and incorporated laboratory testing of the casing-casing patch interfaces under both perforated and unperforated into FEM modeling, with comparison to field results. This process provides a full cycle analysis of the re-fracturing process using this diversion technique.
Simul-Frac Candidate Wells Identified in the Delaware Basin via Remote Operations
Authors: Completions Team Matador , Street Jesse 
Published: January 2023

Abstract
The efficiencies observed in simul-frac operations are commonly associated with a singular, four-plus well pad containing an even number of wells. These efficiencies yield significant savings and reduction in overall completion time, expedite first-production and substantially reduce the time in which offset wells are shut in during frac operations. The introduction of remote simul-frac operations in the Delaware Basin, proven by Matador Resources Company in their Stateline asset, has removed this operational single-pad limitation by connecting adjacent multi-well pads and opening the opportunity to capitalize on ‘traditional’ simul-frac efficiencies on multiple pads simultaneously.
Simul-frac is the use of a singular frac crew to simultaneously stimulate two separate wells. In most cases, the frac crew is equipped with an increase in hydraulic horsepower to be able to achieve rates ranging from 120 – 160 barrels per minute. The backside equipment in a Simul-Frac operation remains relatively unchanged, with the crew still utilizing only one blender. In earliest trials, wells completed via simul-frac operations were on the same pad and potentially receiving an uneven split of the fracturing slurry. By splitting the flow on the low- and high-pressure side of the frac, Matador and Universal Pressure Pumping were able to evenly meter the flow of slurry to two separate banks of pumps on location. One bank led to a zipper manifold on the same location that directed flow accordingly. The other bank directed flow along a 1,500′ high-pressure flanged-pipe frac line to an adjacent location to stimulate its "partner" well. Remote, satellite-communicating pressure gauges were used to monitor pressures on the adjacent pad.
Matador has reported savings of up to ~7.5% of total completion spend per well and increased completed lateral footage per day by upwards of 50% on four well simul-fracs. Six of eleven batched wells in the Stateline asset were selected as a pilot location in Q4 of 2021 for remote simul-frac operations. Two three-well pads, Pad A and Pad B, were to be connected via high-pressure frac line and simultaneously stimulated. A Universal frac spread capable of 160 bpm was rigged up on Pad A and successfully stimulated wells on both Pad A and Pad B, via a high-pressure remote frac line throughout the job. The remote frac operations were a success; 6 wells, 407 stages, and over 73,000 lateral feet were completed in just under 33 days. In addition to the ~7.5% total completion spend per well savings, Matador was able to reduce total completion time by roughly 20 days, which brought forward production on the 11 well batch by 20 days and simultaneously reduced shut-in time of 16 offset wells.
Successful remote simul-frac operations have enabled Matador to revisit a much wider variety of planned pads as candidates for simul-frac activity. After successful implementation in Q4 2021, Matador was able to increase its 2022 simul-frac activity by 91% due to remote operations.
Extended-Time Conductivity Testing of Proppants at 0.5 lb/ft2 Used for Slickwater Multi-Stage Horizontal Completions
Authors: Pearson C. Mark , Green Christopher A. , Milton-Tayler David , Trevino Viviana 
Published: January 2023

Abstract
The American Petroleum Institute testing Standard 19-D (2008) is the current industry standard for conductivity testing of proppants used in hydraulic fracturing. Similar to previous standards from both the API and ISO, it continues the practice of measuring a "reference" conductivity obtained under 50-hours of time at a given stress. The fracture design engineer is then left to estimate a damage factor to apply to the long-term design of the well completion.
This study takes three 40/70 mesh proppants commonly used for multi-stage horizontal well slickwater completions in North America and presents 0.5 lb/ft2 test data over 1000-hours of "extended time" at stress and temperature conditions representative of the Bakken formation of North Dakota. Results presented give clear insight to the degree of damage occurring in the reservoir due to time at stress and temperature. To the authors knowledge, there has never been any extended time conductivity data published at proppant concentrations representative of slickwater fracturing - despite the obvious need for this understanding to optimize the performance of unconventional slickwater well stimulation designs.
The API Standard 19-D procedure for conductivity testing was followed for the tests presented in this paper, but with the proppant concentration loaded at 0.5 lb/ft2 to represent a slickwater proppant pack, and all tests run at 250°F regardless of the proppant material type. The extended time test was run for 1000-hours duration for three commonly used 40/70 mesh proppants used in North American Unconventional Slickwater Well Completions: 40/70 mesh mono-crystalline "white" sand (WS), 40/70 mesh multi-crystalline "brown" sand (BS), and 40/70 mesh light weight ceramic (LWC). The results are presented as conductivity curves as a function of time for the period of testing. Logarithmic Conductivity Degradation Factors (LCDF) were calculated for each proppant type. Degradation for all materials is extrapolated to the point of zero residual conductivity, and compared to previous extended term testing for 1# and 2# proppant packs.