Sequential Fracturing Rate Steps for Complex Subterranean Geometries
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Solution Overview
Problem
Traditional hydraulic fracturing methods often fail to effectively create complex fracture geometries in low or ultra-low permeability formations, leading to poor fracture initiation, limited extension, and reduced hydrocarbon recovery due to near-wellbore pressure issues and competing fractures.
Innovation Solution
A three-phase process involving high viscosity and low viscosity treatment fluids, with incremental fracturing rate steps, to enhance dominate fracture initiation and extension, and subsequent generation of secondary azimuth fractures, optimizing fracture complexity and conductivity.
Engineering Contradictions & Design Principles
Engineering Contradiction Analysis
1Strength
If traditional hydraulic fracturing methods are used, then treatment fluid is pumped at sufficient pressure to break down the formation, but complex fracture geometry is not effectively created in low or ultra-low permeability formations
Solution Approach 1:
The fracturing process is divided into three distinct phases with different fluid viscosities and injection rates. Phase 1 uses high viscosity fluid at low rate for dominate fracture initiation, Phase 2 uses high viscosity fluid at high rate for fracture extension, and Phase 3 uses low viscosity fluid for secondary fracture generation. This segmentation allows each phase to optimize for its specific function, resolving the contradiction between initiation capability and geometry complexity.
Solution Approach 2:
The treatment fluid viscosity and injection rate are dynamically changed between phases. The system transitions from high viscosity/low rate to high viscosity/high rate, then to low viscosity/high rate. This dynamic adjustment allows the system to adapt to different fracture development stages, enabling both effective initiation and complex geometry creation.
2Length of moving object
If high injection rate is used to enhance fracture extension, then fracture length increases, but near-wellbore pressure issues and competing fractures occur
Solution Approach 1:
Phase 1 performs preliminary action by using high viscosity fluid at low injection rate to establish dominate fracture initiation and create a pressure regime that suppresses competing fractures. This preliminary phase prepares the formation for subsequent high-rate injection in Phase 2, allowing fracture extension without the near-wellbore pressure issues that would occur if high rate were applied from the start.
3Strength
If treatment fluid is pumped at high pressure to create fractures, then fracture formation occurs, but fracture complexity and interconnectedness are limited
Solution Approach 1:
The system changes multiple parameters simultaneously - fluid viscosity (from high to low) and injection rate (from low to high) - across the three phases. Phase 3 specifically uses low viscosity fluid at high injection rate to generate secondary azimuth fractures that intersect the dominate fracture, creating the complex interconnected network geometry that cannot be achieved with single-parameter approaches.
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
The process improves fracture complexity, conductivity, and hydrocarbon recovery by reducing near-wellbore pressure, minimizing competing fractures, and increasing the interconnectedness of fracture networks, thereby enhancing hydrocarbon production from low permeability formations.
Implementation Method 1
The treatment fluid is pumped at a rate and pressure sufficient to break down the formation and create one or more fractures therein
Implementation Method 2
the dilated fractures may be held open by particulates to increase the conductivity of the reservoir
Data Source
AI summary
Methods including introducing a first high-viscosity treatment fluid (HVTF) into a subterranean formation through an opening and applying incrementally increased fracturing rate steps (IIFRSs) to the first HVTF to create or enhance a dominate fracture, wherein between each IIFRS applied to the first HVTF a downhole pressure slope over time will increase, decline, or stabilize at a first HVTF measured pressure slope. Evaluating the first HVTF measured pressure slope prior to applying a subsequent IIFRS to the first HVTF. Introducing a first low-viscosity treatment fluid (LVTF) through the opening to create or enhance a secondary azimuth fracture extending from the dominate fracture, and introducing a low-viscosity diversion fluid pill (LVDF) pill through the opening to create a fluidic seal therein.