CO₂-Enhanced Coal Bed Methane Recovery

There are vast, deep coalbeds in Alberta, Canada which are unmineable but contain trapped methane. The Alberta Research Council (ARC) is leading a group of provincial, national and international organizations to exploit the coalbed methane by testing a novel process of injecting carbon dioxide. This process is called Enhanced Gas Recovery (EGR). It is similar to the established practice of using CO₂ injection to enhance production from oil reservoirs. With EGR, the injected CO₂ is adsorbed in the coal, to be stored in its pore matrix, releasing the trapped methane that can be collected and sold.

Future work in this area could lead to the design of efficient null-greenhouse-gas emission power plants that would be fuelled either by mineable coal or by methane released from the deep unmineable coal. In such a process, the CO₂ produced from power plant would be injected into the coalbeds to produce more methane, so continuing the cycle. In addition, a geological sink would be established in the coalbeds, virtually eliminating any release of CO₂ to the atmosphere. An abundance of deep coalbeds in Canada and the USA makes geological storage of CO₂ applicable to many areas where coal-burning power plants are located.

Coalbed methane power plant cycle schematic
Schematic of a coal bed methane power plant cycle; a lifecyle approach to producing fossil fuel

Previous Work on EGR

Burlington Resources has successfully injected CO₂ into relatively high permeability coalbeds in the San Juan basin in the USA for several years. They are stimulating coalbed methane production and recovery. The injected CO₂ is adsorbed into the coal matrix and remains in the ground after completion of gas production. However, further testing and demonstration are needed to apply this process to low permeability reservoirs such as those found in Alberta, Canada and elsewhere in the world.

Alberta Project

The ARC-led project has two main objectives:

To reduce greenhouse gas emissions by subsurface injection of CO₂ into deep coalbeds;
To enhance coalbed methane recovery factors and production rates as a result of CO₂ injection.

The overall project is divided into three phases:

I. The proof of concept study - initial assessment and feasibility of injecting CO₂, nitrogen, and flue gases into Mannville coals.
II. The design and implementation of a micro-pilot test following Amoco Production Company procedures.
III. The design and implementation of a full-scale pilot project.

The Phase I proof of concept study was completed in July 1997. Based on the success of Phase I, the project passed the first go/no-go decision and proceeded to Phase II, consisting of three tasks: (1) geology, geotechnical and engineering, (2) numerical modelling and (3) a micro-pilot field test. Phase II was successfully completed in April 1999.

ARC’s partners in Phase II included Sproule International Ltd., Canadian Association of Petroleum Producers, IEA Greenhouse Gas R&D Programme, Alberta Department of Energy, Environment Canada, US Department of Energy, UK Department of Trade and Industry, Gulf Canada Resources, Burlington Resources, BP Exploration (Alaska) Inc., Suncor Energy, Canadian Fracmaster, Air Liquide Canada, TransAlta Utilities, EPCOR Utilities, Western Economic Partnership Agreement, PanCanadian Petroleum Limited, Netherlands Institute of Applied Geoscience and Mobil Oil Canada.

Phase II Results

The field test was carried out in an existing Gulf Canada well at Fenn Big Valley, Alberta. The test was designed to meet three primary goals: (1) to accurately measure data from a single well test, involving a series of CO₂ injection/soak cycles followed by production of CO₂ and methane; (2) to match the measured data with a comprehensive coal gas reservoir simulation model to obtain estimates of reservoir properties and sorption behaviour; (3) to use calibrated simulation models to predict the behaviour of a larger scale pilot project or full field development. Phase II is a preliminary and necessary step leading to the planning of a full-scale 5-spot pilot test.

The field test was a success. All three primary goals established for the test have been met: the data set that has been collected is of high quality; accurate estimates of reservoir properties and sorption behaviour have been obtained; and from use of calibrated simulation models, it has been concluded that a full-scale pilot CO₂ or flue gas sequestration/EGR project is possible at the Fenn Big Valley location.

Implications of the Tests

From an economic perspective, flue gas injection offers better economics than pure CO₂ injection (unless there is a credit for CO₂). Since it takes 2 cubic feet of CO₂ for each cubic feet of methane produced, the CO₂ would account for US $2.00 per thousand cubic feet of methane sold (assuming CO₂ at US$1.00 per thousand standard cubic feet, or US$19 per tonne). In addition, considering both economic and CO₂ sequestration factors, there might be an advantage to optimising the CO₂/N₂ composition of the flue gas.

Flue gas injection has merit, as the CO₂ will remain sorbed in the coal while the majority of the nitrogen will be produced along with the hydrocarbons. Technical issues that need to be addressed in the next phase of the development are flue gas conditioning, compression and delivery, and N₂/CH₄ separation. In addition, flue gas injection appears to enhance methane production to a greater degree than is possible with CO₂ alone while still sequestering CO₂.

In terms of numerical modelling tool, the three software products evaluated so far were adequate for predicting primary production of coalbed methane. However, only one was suitable for modelling flue gas injection. None of the reservoir simulation software products were capable of accurately predicting the produced gas composition observed during the field test. Improved understanding of the process mechanisms, for example, multiple gas sorption and diffusion, and changes in coal matrix volume due to sorption or desorption of CO₂, are needed to guide the future development of the simulation models.

Phase III

Based on the Phase II results, the project has passed the second go/no-go decision and proceeded to Phase III. Phase III is divided into two parts, in stages from 1999 to 2001. Phase III-A begins by evaluating options for the treatment of flue gases, compression, and the associated economics to optimize CO₂ storage and methane production both at the pilot and commercial scales. ARC expect to drill and complete a second well and perform a simulated flue gas micro-pilot test. This will be the world’s first pilot test of injecting flue gas into a coal seam.

In October 1999, the second well was successfully drilled and completed at Fenn Big Valley. Core samples were collected to allow accurate determination of the gas-in-place volume, gas composition, and gas storage capacity. A second micro-pilot test will be performed in December 1999, by injecting a simulated flue gas stream consisting of N₂ and CO₂. The combination of gases may result in greater hydrocarbon recovery without hindrance to the CO₂ sequestration. The second micro-pilot will allow us to finalize the design of the full-scale project to be installed in the year 2000 and operated until 2001.

Cutting core smaples
Cutting coal core samples in the field

In parallel, during 1999/2000, geological studies will be carried out to evaluate the geology of other coal deposits in Alberta, such as those in the Ardley and Edmonton groups. The Ardley coals are located at shallower depths and may be more permeable than the Mannville coal allowing lower injection pressures and reduced costs. The Edmonton coals are located at shallow depths in close proximity to major power plants and would be convenient for CO₂ sequestration. The reservoir properties in these other areas, in particular the natural fracture permeability, cannot be determined by study of available geologic data. As a result, two formation evaluation wells will be drilled into Ardley and Edmonton coal seams during 2000.

If Phase III-A is successful, the project will proceed to Phase III-B, which is the implementation of an isolated 5-spot pilot with four injection wells and one production well, sized between 20 and 40 acres. The goal of the large-scale pilot is to visibly demonstrate that CO₂ sequestration and EGR is possible. A product of the pilot will be complete specifications of the technology required to perform large-scale projects. The specifications will include those for a flue gas collection and treatment module, a compression module, and a gas production module. The methods used to collect and interpret the data and to determine the degree of technical and economic success of the pilot will be fully documented.

The pilot will be performed at the Fenn Big Valley site unless the data from the 1999/2000 formation evaluation tests strongly suggests that the pilot should be located at a shallower, more permeable location. Three additional wells will be drilled in 2000. These are the two remaining injection wells and the production well. The 1998 and 1999 micro-pilot wells will be converted to injection wells. Injection will begin in 2000 and will continue for 12 months into 2001. If the pilot is successful, full-scale development can begin in 2002.