Injection R D & D

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Degree of Coal Swelling and Loss of Permeability Associated with Sequestration of CO2, H2S and Flue Gas - Selecting Optimum Coals for Sequestration

Coal seams are being currently investigated as potential sequestering sites for carbon dioxide. Coal is a microporous material that possesses a very high surface area and hence sorption capacity for gas. In the subsurface coal, commonly has economically significant amounts of sorbed methane (coalbed methane). Because coal has a greater sorption affinity for carbon dioxide than methane, injection of carbon dioxide with simultaneous production of methane may be viable.

Partners:
Quick Silver Resources Inc.
EnCana

Project Manager:
Marc Bustin
University of British Columbia


Enhancing the Capacity of CO2 Storage by Removing the Remaining Water in Depleted Oil Reservoirs

The objective of this proposal is to develop CO2 storage injection techniques for efficiently displacing and producing the water retained in reservoirs after an EOR process, thus enhancing the CO2 storage capacity of these reservoirs. Depleted oil reservoirs with different conditions and oil production histories will be investigated for CO2 storage injection. This project will find the answer to the question: how should CO2 be injected in different reservoirs to achieve a maximum storage capacity? The techniques to be developed in this project are crucial for CO2 storage injection in a depleted oil reservoir once it is selected for CO2 storage.

Partners:
Saskatchewan Research Council
Petroleum Technology Research Centre

Duration: April 1, 2004 - March 31, 2008

Project Manager:
Mingzhe Dong
Chemical and Petroleum Engineering, University of Calgary


Experimental Investigation of CO2/Coal Interaction

The objective of the project is to investigate the interaction between dense (high pressure) CO2 and coal, for the purpose of CO2 storage and enhanced coalbed methane recovery.

Injecting CO2 into coal seams has been discussed as one method of disposing of greenhouse gases. There has also been interest in using CO2 for enhanced coalbed methane (ECBM) recovery, thereby recovering natural gas while simultaneously disposing of greenhouse gases. The Alberta Research Council has led the way in investigating ECBM in Alberta (1). Limited experimental data have shown this concept to be technically viable (2,3).

Gaseous CO2 is stored in coal by physical adsorption, just as methane is. CO2 adsorption capacities are higher than methane adsorption capacities by a factor of two or more, depending on coal rank. This would suggest coal as an attractive geologic medium for CO2 storage.

Partners:
TIPM Laboratory

Project Manager:
Apostolos Kantzas
TIPM Laboratory
University of Calgary


 Optimizing CO2 Storage in Oil Reservoirs

The objectives of this Research Project are:

  1. Increase the CO2 storage in oil reservoirs at the enhanced oil recovery stage by changing the field operating parameters (to the practical extent possible) with the aim of optimizing the total oil production revenues and potential CO2 storage credits.
  2. Evaluate the various options for increasing CO2 storage at the post-enhanced oil recovery stage with economic constraints.
  3. Evaluate the overall storage capacity if CO2 injection begins at an early stage of the oil development cycle (i.e. before primary and/or water flood)

In the short to medium term, storing CO2 in oil reservoirs should be a clear favourite among the many options of geological storage. The reasons for this are many, namely: (1) the reservoir is well defined, as it has records of production history; (2) reservoir access is certain, as the ownership is known; (3) the integrity of the reservoir is assured, as it has stored hydrocarbons before and therefore it should be capable of storing CO2 as well; and (4) it produces an oil revenue stream that can potentially offset the cost of storage. However, when it comes to CO2 storage capacities, the numbers become less certain. We believe more research efforts are required to understand the mechanisms of oil production and CO2 storage and the economic interplay between the two. Essentially, the species: oil, water, CO2 and other mixed gases (if present) must compete for the pore space. In addition, the issues are complicated by the fact that at each stage of the oil development cycle (primary, water flood and enhanced oil recovery) the occupants of the pore space change depending on production strategies.

Partners:
Alberta Research Council (ARC)
CMG

Project Managers:
Sam Wong
Alberta Research Council


 Investigations on the Greenhouse Gas Storage Capacity of Oil Reservoirs

This project focuses on CO2 and flue gas storage in naturally fractured reservoirs. As a specific example, the naturally fractured Midale field operated by Apache Canada Ltd. will be used. The optimal storage condition is the major concern but the increase of oil recovery during the operation will also be considered from the project cost and Apache’s on-going investments points of view. In addition to the Midale field, there are several more potential depleted oil reservoirs in Canada, which are under consideration for CO2 injection/sequestration such as Virginia Hills Beaverhill Lake pools.

The project participants postulate that the rock matrix in naturally fractured reservoirs is a convenient long-term storage medium for CO2 . Therefore, the objectives are to:

  • identify the effects of the matrix properties (permeability, wettability, amount of water and size) and
  • clarify the importance of the content of the CO2 in the injected gas (pure versus impure CO2), and the state of the CO2 (supercritical or subcritical) on the storage of CO2, and
  • identify the CO2 entrapment (physical, chemical, and physicochemical) mechanisms and
  • optimize the storage process based on the injection rate of CO2.

In all these efforts, incremental oil recovery would be a concern as it is the key parameter to offset the cost of the process.

Partners:
Apache Canada Ltd.
Natural Sciences and Engineering Research Council (NSERC)

Duration: Jan 2006 - Oct 2009

Project Manager:
Tayfun Babadagli, PhD, PEng
Professor of Petroleum Engineering
University of Alberta

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