Numerical Simulator Comparison Study for Enhanced Coalbed Methane Recovery Processes, Part I: Pure Carbon Dioxide Injection
- David H.-S. Law (Alberta Research Council ARC Inc.) | L.G.H. van der Meer (TNO-NITG) | W.D. Gunter (Alberta Research Council ARC Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Gas Technology Symposium, 30 April-2 May, Calgary, Alberta, Canada
- Publication Date
- Document Type
- Conference Paper
- 2002. Society of Petroleum Engineers
- 5.4.3 Gas Cycling, 5.5.8 History Matching, 5.3.2 Multiphase Flow, 5.6.4 Drillstem/Well Testing, 1.2.3 Rock properties, 5.3.4 Integration of geomechanics in models, 5.8.3 Coal Seam Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.10.1 CO2 Capture and Sequestration, 5.8.8 Gas-condensate reservoirs, 3 Production and Well Operations, 5.4.2 Gas Injection Methods, 5.4.6 Thermal Methods, 5.1 Reservoir Characterisation, 5.4 Enhanced Recovery, 5.5 Reservoir Simulation
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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 CBMrecovery 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 togas desorption; taken into consideration. However, process mechanisms becomemore 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 numericalsimulators for enhanced coalbed methane (ECBM) recovery with pureCO2 injection. The problems selected for comparison are intended toexercise many of the features of CBM simulators that are of practical andtheoretical interest and to identify areas of improvement for modeling of theECBM 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.
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 thegas-in-place volume while the secondary porosity system provides the conduitfor mass transfer to the wellbore. Primary porosity gas storage is dominated byadsorption. The primary porosity system is relatively impermeable due to thesmall pore size. Mass transfer for each gas molecular species is dominated bydiffusion that is driven by the concentration gradient. Flow through thesecondary porosity system is dominated by Darcy flow that relates flow rate topermeability and pressure gradient.
The conventional primary CBM recovery process begins with a production wellthat is often stimulated by hydraulic fracturing to connect the wellbore to thecoal natural fracture system via an induced fracture. When the pressure in thewell is reduced by opening the well on the surface or by pumping water from thewell, the pressure in the induced fracture is reduced which in turn reduces thepressure in the coal natural fracture system. Gas and water begin movingthrough the natural and induced fractures in the direction of decreasingpressure. When the natural fracture system pressure drops, gas molecules desorbfrom the primary-secondary porosity interface and are released into thesecondary porosity system. As a result, the adsorbed gas concentration in theprimary porosity system near the natural fractures is reduced. This reductioncreates a concentration gradient that results in mass transfer by diffusionthrough the micro and mesoporosity. Adsorbed gas continues to be released asthe pressure is reduced.
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