Comparative Study on Full-Scale Pore Structure Characterization and Gas Adsorption Capacity of Shale and Coal Reservoirs

 

Comparative Study on Full-Scale Pore Structure Characterization and Gas Adsorption Capacity of Shale and Coal Reservoirs

Introduction :

This study compares the full-scale pore structure and gas adsorption capacity of shale and coal reservoirs to better understand their storage and production potential. By analyzing pore size distribution, specific surface area, and adsorption isotherms, it highlights differences in gas storage mechanisms. Such insights support improved exploration and enhanced gas recovery strategies for unconventional energy resources.

Key Aspects Covered:

Objectives:

• To characterize pore structures of shale vs. coal using techniques like low-pressure gas adsorption (LPGA), mercury intrusion, and SEM.

• To quantify gas absorption capacity and its controlling factors.

• To analyze how pore connectivity and surface area affect gas storage and flow.

Methods:

• BET & BJH analyses for micro-mesopores.

• Scanning electron microscopy (SEM) for microstructure.

• Methane adsorption experiments under reservoir conditions.

Comparative Insights:

• Shale typically has more nanopores and organic-matter pores, boosting adsorption capacity.

• Coal often exhibits larger micropore volumes but may show different connectivity.

• Differences directly impact gas deliverability and recovery technologies.

Applications:

• Gas-in-place estimation.

• Enhanced gas recovery design.

• Reservoir modeling for CBM (Coalbed Methane) and shale gas.

  Background & Importance

  • Shale and coal seams are two major unconventional gas reservoirs — shale gas and coalbed methane (CBM).

  • Both store gas adsorbed onto organic matter and free in pores/fractures.

  • Understanding pore structure is crucial because pore size, shape, and connectivity govern:

    • Gas storage capacity.

    • Adsorption/desorption behavior.

    • Permeability and gas flow.

  • Full-scale pore characterization covers micropores (<2 nm), mesopores (2–50 nm), and macropores (>50 nm).

  Pore Structure Differences

  Feature	Shale	Coal
  Organic Content	High TOC; kerogen-rich	High in vitrinite & inertinite
  Dominant Pore Type	Nanopores in organic matter & clay	Micropores in coal matrix
  Pore Size	Many <10 nm	Mostly micropores (<2 nm), but cleats/fractures add macro-scale pathways
  Pore Connectivity	Lower matrix permeability; relies on natural fractures	Cleats provide natural fracture network
  Surface Area	High due to nanopores	Very high due to micropores

  
  

  • Shale: More complex, multi-scale, heterogeneous.

  • Coal: Simpler, but cleats dominate gas migration.

  Gas Adsorption Mechanism

  • Gas is adsorbed on pore walls (physical adsorption).

  • Methane is the main gas of interest.

  • Adsorption isotherms: Langmuir model commonly used.

  • Capacity depends on:

    • Pore volume & specific surface area.

    • Organic matter type & maturity.

    • Moisture content (especially in coal).

  Analytical Techniques

  🔍 Typical Methods:

  • Low-pressure N2/CO₂ adsorption (BET/BJH): Measures surface area, micro/mesopore distribution.

  • Mercury Intrusion Porosimetry (MIP): Covers macropores.

  • Scanning Electron Microscopy (SEM) + FIB-SEM: Visualizes pore geometry.

  • CT Scanning: 3D pore network imaging.

  • Methane Adsorption Tests: Determines Langmuir volume and pressure.

  Comparative Results:

  Example Insights (from published studies):

  • Shale: Higher total gas content due to free gas + adsorbed gas in nanoscale pores.

  • Coal: Higher adsorption capacity per unit mass, but lower total free gas.

  • Desorption: Coal releases gas by depressurization; shale needs fracturing to enhance flow.

  Implications for Production: 

  • Shale gas: Requires hydraulic fracturing to connect low-permeability nanopores.

  • CBM: Natural cleat system can allow drainage by dewatering.

  • Enhanced Recovery: CO₂ injection can boost methane recovery — CO₂ adsorbs better than CH₄, pushing CH₄ out.                                                                                                                                                                                          

    

  Challenges

  • Complex multi-scale pore networks make modeling hard.

  • Pore connectivity prediction is uncertain.

  • Accurate characterization needs combining multiple methods.

  • Adsorption/desorption hysteresis affects prediction of production decline.

  Future Directions

  • Nano-imaging and digital rock physics.

  • Molecular simulation of adsorption.

  • CO₂ sequestration combined with CBM production.

  • Machine learning to predict gas content from core data.

  ✅ Summary

  A comparative study of shale vs. coal pore structure and gas adsorption capacity:

  • Helps in resource estimation, production planning, and enhanced recovery design.

  • Requires multi-scale, multi-method analysis.

  • Directly impacts unconventional gas development strategies.