MICRO-CRACK Stimulation

Shear Dilation-Based Stimulation without Proppant Using Low-Rate Pumping

Shear dilationLow-rate pumpingWithout proppant

TECHNOLOGY OVERVIEW

HIGHLIGHT

Micro-Crack Stimulation is a stimulation method designed to induce fracture widening (dilation) through a shear-failure mechanism. This method generates volumetric hydraulic stimulation by injecting fluid at controlled pressure (using low-rate pumping or a cementing pump) to create a network of micro-cracks within the rock matrix.

The micro-crack network is expected to increase effective formation permeability while maintaining reservoir mechanical stability and expanding the contact area between produced fluid and perforations.

01Controlled-pressure injection

02Shear dilation

03Micro-crack network

TECHNICAL CONCEPT

How the mechanisms differ

Stress • fracture • permeability

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FRACTURING

Tensile Failure

Normal stress on a rock plane exceeds tensile strength, causing the rock to split and form fractures parallel to the maximum principal stress direction (σ₁) and perpendicular to the minimum principal stress (σ₃).

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DILATANCY

Shear Failure

Shear failure occurs when the Mohr circle touches or exceeds the failure envelope, indicating that shear stress exceeds rock shear strength. Weak planes or shear zones can form, appearing as micro-faults or fractures with internal displacement.

TECHNOLOGY COMPARISON

Micro-Crack vs. Hydraulic Fracturing

Key differences presented in the source poster.

Explore the 11 engineering comparison criteria

Criteria	Dilatation Failure (Shear-Dominated)	Tensile Failure (Hydraulic Fracturing)
Failure mechanism	Shear dilation creates or enhances micro-fractures and pore expansion.	Rock is pulled apart by tensile fracturing, creating a dominant fracture.
Dominant stress	Shear failure along existing fractures or weak planes.	Tensile stress exceeds rock tensile strength.
Fracture orientation	Often follows pre-existing natural fractures or bedding planes; may be irregular.	Perpendicular to the minimum horizontal stress direction.
Fracture network	Complex network interacting with pre-existing fractures.	Typically one dominant planar fracture in a predictable direction.
Fluid injection	Low-to-moderate pressure with high total volume to promote dilation without breaking rock apart.	High-pressure injection to exceed tensile strength and initiate a new fracture.
Reservoir suitability	Naturally fractured, tight formations suited to shear dilation.	Homogeneous competent formations where a dominant fracture is beneficial.
Proppant	May not require proppant; shear dilation can provide permanent fracture conductivity.	Requires proppant to keep fractures open after pressure release.
Long-term conductivity	Network remains open due to residual shear displacement and stress relief.	Depends on proppant placement; fractures may close if stress overcomes proppant strength.
Flow enhancement	Increased permeability through fracture connectivity.	Direct high-permeability flow path through rock.
Unconventional reservoirs	Common in naturally fractured tight sandstones, carbonates and geothermal systems.	Preferred in shales and formations needing large fracture conductivity.
Pressure behavior	More gradual increase as fractures open progressively.	Sharp increase to breakdown pressure followed by a drop as fracture propagates.

FIELD IMPLEMENTATION

SUCCESS STORY

Reported results in source poster

PMB-27 · PERMEABILITY64 → 4,000mD

GNK-53 · PERMEABILITY3 → 168mD

PMB-27 · INJECTION200 → 4,000BWPD

STIMULATION EXTENT70 m / 25–30 mPMB-27 extent / GNK-53 lateral radius

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Hydraulic dilation demonstrated
Reported without proppant or formation breakdown.

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Wider application potential
Injection wells with positive skin; potential testing in production wells.

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Technical validation
Poster cites microseismic and geomechanical data as confirmation.

VISUAL DATA FROM THE SOURCE

Field Implementation Evidence

Click each figure to enlarge; select a well to view its associated charts.

PMB-27 — Reported injection-rate improvement from 200 to 4,000 BWPD and dilation extending up to 70 m from the wellbore.