Hydraulic Fracturing Network Complexity via Stress Alteration
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Solution Overview
Problem
Conventional hydraulic fracturing methods often result in limited stimulated reservoir volume (SRV) due to the creation of predominantly long, planar fractures, which restrict hydrocarbon production by not effectively accessing hydrocarbons far from the wellbore, and lead to inefficient fluid distribution and secondary fracture generation.
Innovation Solution
Monitoring operational parameters such as injection rate, fluid density, and bottomhole pressure during hydraulic fracturing to alter stress conditions and divert fluid flow from highly conductive primary fractures to less conductive secondary fractures, using chemical diverters and adjusting injection rates and viscosities to enhance fracture complexity and SRV.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Length of moving object
If conventional hydraulic fracturing creates long planar fractures, then fracture length is improved, but stimulated reservoir volume (SRV) deteriorates
Solution Approach 1:
The patent applies segmentation by dividing the single long planar fracture into multiple secondary fractures through staged fluid injection. After creating an initial fracture, the method injects diversion fluids to block the primary fracture path and force creation of additional secondary fractures, transforming one continuous fracture into a network of segmented fractures that collectively increase SRV while maintaining individual fracture lengths within optimal ranges.
Solution Approach 2:
The patent transitions from a one-dimensional long planar fracture to a multi-dimensional fracture network by injecting fluids at different angles and stages. This creates fractures extending in multiple directions and planes from the wellbore, converting a simple linear fracture geometry into a complex three-dimensional network that significantly increases the stimulated reservoir volume without requiring excessively long individual fractures.
2Area of moving object
If viscous fracturing fluid is used, then fracture width is improved, but fluid distribution efficiency deteriorates
Solution Approach 1:
The patent employs dynamic fluid viscosity control by using different fluids with varying viscosities at different stages of the fracturing process. The initial stage uses viscous fluid to create wide primary fractures, while subsequent stages use lower viscosity diversion fluids that can more efficiently distribute and redirect into secondary fractures. This dynamic adjustment of fluid properties optimizes both fracture width creation and fluid distribution efficiency across different phases of treatment.
Solution Approach 2:
The patent changes fluid viscosity parameters between stages to optimize performance. By transitioning from high-viscosity fracturing fluid in the initial stage to lower-viscosity diversion fluids in subsequent stages, the method maintains adequate fracture width while improving fluid mobility and distribution efficiency. This parameter change allows the system to achieve both wide fractures and efficient fluid placement throughout the reservoir.
3Device complexity
If slickwater fracturing is used, then fracture complexity near wellbore is improved, but SRV deteriorates
Solution Approach 1:
The patent applies preliminary action by first creating an initial fracture network using slickwater to establish complexity near the wellbore, then subsequently injecting diversion fluids to extend and distribute this complexity into the far-field reservoir. The initial slickwater treatment prepares the formation by creating near-wellbore fractures, which then serve as pathways for the diversion fluids to access and stimulate more distant reservoir zones, ultimately achieving both near-wellbore complexity and extended SRV.
Solution Approach 2:
The patent uses diversion fluids as intermediaries to bridge the gap between near-wellbore fracture complexity and far-field SRV development. The diversion fluids act as mediators that redirect flow from the initial slickwater-induced fractures into new secondary fracture paths, carrying the stimulation effect from the wellbore region into the distant reservoir. This intermediary mechanism allows the benefits of slickwater-induced complexity to be extended throughout the entire stimulated reservoir volume.
Applied Scientific Principles
This section explains which scientific principles are used to turn an abstract innovation direction into a practical engineering solution.
Function Achieved in This Case
This approach increases the complexity of the fracture network and SRV, leading to sustained hydrocarbon production by creating a more extensive and conductive pathway for hydrocarbon flow, reducing residual damage, and optimizing fluid distribution within the reservoir.
Implementation Method 1
a fracturing fluid is pumped at pressures exceeding the fracture pressure of the targeted reservoir rock in order to create or enlarge fractures
Implementation Method 2
The viscosity of most fracturing fluids may be attributable to the presence of a viscosifying agent, such as a viscoelastic surfactant or a viscosifying polymer
Implementation Method 3
slickwater fluids typically do not contain a viscoelastic surfactant or viscosifying polymer but do contain a sufficient amount of a friction reducing agent to minimize tubular friction pressures
Implementation Method 4
the proppants remain in the fracture in the form of a permeable 'pack' that serves to 'prop' the fracture open
Data Source
AI summary
The complexity of a fracture network may be enhanced during a hydraulic fracturing operation by monitoring operational parameters of the fracturing job and altering stress conditions in the well in response to the monitoring of the operational parameters. The operational parameters monitored may include the injection rate of the pumped fluid, the density of the pumped fluid or the bottomhole pressure of the well after the fluid is pumped. The method provides an increase to the stimulated reservoir volume (SRV).