Figure 3.6.1: Injection record from micro-frac stress test showing rate in gpm (gallons/min) and bottomhole pressure in psi (reference depth is 2400 ft).
This pressure record is from a stress test injection called a micro-frac. A small fracture is created by pumping at a specific depth in the reservoir, and by watching the pressure decline during the post-injection shut-in period, the in situ stress can be observed.
Figure 3.6.2: Bird's eye view of downhole visualization for a fracture growing from a vertical wellbore.
Radial Flow Injection
Before fracture initiation, the injected fluid enters the formation through radial flow from the wellbore. Because hydraulic fracturing is performed at a constant injection rate that exceeds the formation's ability to accept fluid by radial flow alone, the bottomhole treating pressure (BHTP) rises rapidly. When the BHTP exceeds the breakdown pressure (Pb), the rock fails and a hydraulic fracture is created. The breakdown pressure is typically identified as the highest pressure reached at the beginning of the injection, marking the transition from radial flow into fracture propagation.
Bi-Linear Flow Injection
Once the fracture has initiated, the injected fluid flows from the wellbore into the fracture while simultaneously leaking off from both fracture faces into the surrounding formation. This creates a bi-linear flow regime, consisting of linear flow within the fracture and linear leak-off perpendicular to the fracture surfaces. During this stage, the fracture remains open and continues to propagate. The pressure required to maintain fracture growth is called the fracture propagation pressure, which is generally lower than the breakdown pressure because the fracture has already been created.
The fracture propagation pressure depends on several factors, including:
- In-situ stresses
- Fluid viscosity
- Fluid leak-off into the formation
- Fracture geometry
- Injection rate
Linear Leak-off Before Fracture Closure
After the desired volume of fracturing fluid has been injected, the pumps are shut down and the well is shut in. The instantaneous shut-in pressure (ISIP) is measured immediately after pumping stops, once the effects of wellbore friction have dissipated. At this stage, the fracture is still open, and fluid continues to leak off from the fracture faces into the surrounding formation.
During this period, the pressure decline is primarily controlled by linear leak-off from the fracture into the formation. This linear-flow regime persists only while the fracture remains open. As leak-off continues, the fracture gradually loses width until it eventually closes.
Radial Flow After Fracture Closure
When the fracture closes, it no longer provides an open flow path into the formation. Consequently, the flow regime transitions from linear leak-off to radial flow around the wellbore. The pressure corresponding to this transition is interpreted as the fracture closure pressure, which is commonly used as an estimate of the minimum horizontal stress (Shmin) in the formation.
Fracture closure is therefore identified by recognizing the transition in the pressure response from linear leak-off while the fracture is open to radial flow after the fracture has closed.
