Abstract

The injection of carbon dioxide (CO2) in deep, unmineablecoalbeds can enhance the recovery of coalbed methane (CBM) and at the same timeit is a very attractive option for geologic CO2 storage asCO2 is strongly adsorbed onto the coal.

Existing CBM numerical simulators which are developed for the primary CBM recovery process, have many important features such as:

  1. a dual porositysystem;

  2. Darcy flow in the natural fracture system;

  3. pure gas diffusionand adsorption in the primary porosity system; and

  4. coal shrinkage due to gas desorption; taken into consideration. However, process mechanisms become more complex with CO2 injection. Additional features such as:

    1. coal swelling due to CO2 adsorption on coal;

    2. mixed gasadsorption;

    3. mixed gas diffusion; and

    4. non-isothermal effect for gasinjection; have to be considered.

This paper describes the first part of a comparison study between numerical simulators for enhanced coalbed methane (ECBM) recovery with pure CO2 injection. The problems selected for comparison are intended to exercise many of the features of CBM simulators that are of practical and theoretical interest and to identify areas of improvement for modeling of the ECBM process. The first problem set deals with a single well test withCO2 injection and the second problem set deals with ECBM recoveryprocess with CO2 injection in an inverted five-spot pattern.

Introduction

The injection of carbon dioxide (CO2), a greenhouse gas (GHG), incoalbeds is probably one of the more attractive options of all undergroundCO2 storage possibilities: the CO2 is stored and at thesame time the recovery of coalbed methane (CBM) is enhanced.1 Therevenue of methane (CH4) production can offset the expenditures ofthe storage operation.2,3

Coalbeds are characterized by their dual porosity: they contain both primary (micropore and mesopore) and secondary (macropore and natural fracture) porosity systems. The primary porosity system contains the vast majority of the gas-in-place volume while the secondary porosity system provides the conduitfor mass transfer to the wellbore. Primary porosity gas storage is dominated by adsorption. The primary porosity system is relatively impermeable due to the small pore size. Mass transfer for each gas molecular species is dominated by diffusion that is driven by the concentration gradient. Flow through the secondary porosity system is dominated by Darcy flow that relates flow rate to permeability and pressure gradient.

The conventional primary CBM recovery process begins with a production well that is often stimulated by hydraulic fracturing to connect the wellbore to thecoal natural fracture system via an induced fracture. When the pressure in the well is reduced by opening the well on the surface or by pumping water from the well, the pressure in the induced fracture is reduced which in turn reduces the pressure in the coal natural fracture system. Gas and water begin moving through the natural and induced fractures in the direction of decreasing pressure. When the natural fracture system pressure drops, gas molecules desorbfrom the primary-secondary porosity interface and are released into the secondary porosity system. As a result, the adsorbed gas concentration in the primary porosity system near the natural fractures is reduced. This reduction creates a concentration gradient that results in mass transfer by diffusion through the micro and mesoporosity. Adsorbed gas continues to be released as the pressure is reduced.

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