Declining Frac Effectiveness - Evidence that Propped Fractures Lose Conductivity, Surface Area, and Hydraulic Continuity

Vincent, Michael C.; Besler, Monte R.

doi:10.1190/urtec2013-073

Cited by 24 publications

(5 citation statements)

References 5 publications

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“…It can be inferred that the system has been permanently damaged from offset well interference due to the reduction in the productivity index. This can be supported by many case studies that Vincent and Besler (2013) summarized in which wells that have been interfered with, in the most severe cases have crosslinked, sand-laden slurry in the wellbore and surface equipment after a stimulation treatment. It is apparent that the two wells had created a fracture between them.…”

Section: Additional Factors Effecting Fracture Growthmentioning

confidence: 83%

Workflow Development and Sensitivity Investigation of Offset Well-to-Well Interference Through 3-D Fracture Modeling and Reservoir Simulation in the Denver-Julesburg Basin

Levon¹,

Miskimins²

2019

Proceedings of the 7th Unconventional Resources Technology Conference

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The objective of this research was to construct a calibrated multi-well 3D fracture model to evaluate well-to-well interference, also known as well "bashing", in the Niobrara and Codell formations of the Denver-Julesburg (DJ) Basin. Hydraulic fracturing is a vital component to produce in unconventional resource plays economically. In the early stages of development in all unconventional resource plays, including the DJ Basin, single well pads were common for either exploratory drilling or lease retention. Initially many shale plays across the world were not fully developed and in order to capture the resources originally left behind, infill drilling is taking place to access additional resources to create a greater effective stimulated rock volume (SRV) and achieve better recovery. Unfortunately, many previously drilled, producing "parent" wells and newly drilled "child" wells are actually yielding a reduction in recovery rates in short and long-term cases due to interference. Research has shown that one of the main contributors to the variability in production is the presence of pressure depletion from production around the parent wells and the impacts it has on subsequent child well completions. As a means of examining well-to-well interference, the focal point of this study was a nine well pad consisting of six wells in the Niobrara and three wells in the Codell. This pad showed evidence of interference measured using bottom hole gauges installed in the two "parent" wells, one in each formation, during the stimulation of the child wells. Oil and water flowback tracers utilized during the treatment of the child wells also supported the presence of communication. A multi-well, multi-stage (total of 500 stages) 3D hydraulic fracture model was developed using offset vertical well logs and geologic interpretation of mud logs to define the variation in rock properties that best represent the reservoir in which these wells were drilled. vi TABLE OF CONTENTS

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Section: Additional Factors Effecting Fracture Growthmentioning

confidence: 83%

Workflow Development and Sensitivity Investigation of Offset Well-to-Well Interference Through 3-D Fracture Modeling and Reservoir Simulation in the Denver-Julesburg Basin

Levon¹,

Miskimins²

2019

Proceedings of the 7th Unconventional Resources Technology Conference

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“…The shaded band is a 95% confidence interval for the two parameters line. In this area of the Delaware Basin, the relationship between well spacing (ROA) and well performance is clear [36][37][38][39][40][41][42][43][44][45][46][47][48][49][50][51][52][53][54].…”

Section: Rectangular Overlap Area (Roa)mentioning

confidence: 99%

Optimal Spacing of the Wolfcamp in the Delaware Basin

Alzahabi¹

2021

GJES

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Proper well spacing for horizontal wells is one of the missing pieces for the Delaware Basin development in the Wolfcamp Formation. In the Wolfcamp formation in the Delaware Basin, well spacing varies with formation characteristics (rock and fluid) across the Basin. Finding the spacing intervals between horizontal wells right is crucial to maximizing productivity and estimated ultimate recovery (EUR) while avoiding detrimental frac hits and cross-well pressure and fluid interference during stimulation and production.Along with the various parameters affecting development, well patterns and completion methodologies are having the highest impact. Both parameters show a significant impact on the drainage area of wells and may in turn affect optimal spacing between the wells. The model outcomes are expected to improve recovery efficiency, oil production, and minimize detrimental frac hits and cross-well pressure and fluid interference during stimulation and production. A pool of private production and spacing data were analyzed in conjunction with data analytics. This step led to a newly developed model to optimize well spacing.• Fluid Bbls = the amount of fluid pumped downhole to initiate fracture and place proppant.• Fluid Gal/Cluster = the amount of fluid pumped per cluster.

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“…The practice of overflushing or overdisplacing fracture stimulation treatments, to maintain a clean wellbore for plug-and-gun pump-down operations, has raised concerns by some in the industry (Vincent and Besler, 2013, Besler et al, 2007, van Gijtenbeek, Shaol, and de Pater, 2012. A common observation on wells where production logs or oil-based tracers are used to compare production contribution from individual stages is that the stage closest to the heel of the well often is the most productive, such as one well in a study by Goswick and LaRue (2014).…”

Section: Influence Of Over-flushing Fracture Stimulation Stagesmentioning

confidence: 99%

The Application and Misapplication of 100-Mesh Sand in Multi-Fractured Horizontal Wells in Low-Permeability Reservoirs

Al-Tailji

Shah

Davidson

2016

Day 1 Tue, February 09, 2016

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With multi-fractured horizontal wellbores being the primary means to economically access hydrocarbon resources in low-and ultra-low permeability reservoirs, a multitude of completion and stimulation practices can be employed along the lateral section of the wellbore. Completion (staging method, perforations, cluster spacing, etc.) and stimulation (fluid type, proppant type, proppant concentrations, etc.) design parameters are typically adjusted in order to accelerate hydrocarbon recovery and improve ultimate recovery.One practice that has been gaining popularity as a method of maximizing contact area and accelerating hydrocarbon recoveries in many shale plays is the combination of thin water-based fracturing fluids, small-mesh proppants (mostly 100 mesh sand with some 40/70 mesh sand), and a high intensity of injection points in each fracture stimulation stage. The theory behind this practice is that thinner fluids and smaller mesh proppants can generate more fracture complexity in shale formations, thereby increasing contact area which is of high importance in very low permeability reservoirs, and smaller mesh proppants can be transported at larger distances than larger proppants such as 20/40 and 30/50 mesh.Historic hydraulic fracturing practice prior to the shale boom had previously utilized small quantities of small mesh proppants such as 100 mesh sand to assist with hydraulic fracture generation and placement. However, many publications often cautioned against the use of significant quantities of these small proppants, due to the adverse impact it would have on fracture conductivity in tight gas reservoirs with permeabilities on the order of 0.01 to 1 millidarcy or greater. However, many shale plays currently in development, such as the Bakken, Eagle Ford, and Haynesville formations, have significantly lower permeabilities than tight gas plays, on the order of 1 to 1,000 nanodarcy (Walls and Sinclair, 2011), potentially elevating 100 mesh sand to ЉproppantЉ status. This paper will critically evaluate the historic and contemporary uses of 100 mesh sand both as a placement aid as well as a proppant in very low permeability reservoirs. The effects of fracture conductivity in naturally-fractured reservoir will be explored in order to determine how much conductivity is sufficient to adequately drain the reservoir, and if using 100 mesh sand as a proppant is appropriate for this purpose. An evaluation of large datasets from publically-derived completion and production data to statistically evaluate the successes of different completion practices and a couple of specific case studies will be presented to illustrate some ways where operators can exceed the statistical mean well performance in their particular area, without needing to resort to using large fluid volume waterfrac treatments with small mesh proppants.

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Declining Frac Effectiveness - Evidence that Propped Fractures Lose Conductivity, Surface Area, and Hydraulic Continuity

Cited by 24 publications

References 5 publications

Workflow Development and Sensitivity Investigation of Offset Well-to-Well Interference Through 3-D Fracture Modeling and Reservoir Simulation in the Denver-Julesburg Basin

Workflow Development and Sensitivity Investigation of Offset Well-to-Well Interference Through 3-D Fracture Modeling and Reservoir Simulation in the Denver-Julesburg Basin

Optimal Spacing of the Wolfcamp in the Delaware Basin

The Application and Misapplication of 100-Mesh Sand in Multi-Fractured Horizontal Wells in Low-Permeability Reservoirs

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