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Derakhshanfar M.,IPAC CO2 | Nasehi M.,IPAC CO2 | Ahmadi F.,IPAC CO2 | Baimyrza Z.,IPAC CO2 | Sherk G.,IPAC CO2
Society of Petroleum Engineers - Canadian Unconventional Resources Conference 2011, CURC 2011 | Year: 2011

Geological storage of CO2 in underground formations has the potential to be a major component of any viable solution to reduce atmospheric emissions of greenhouse gases. There are different options for long-term storage of CO2 in subsurface formations currently being considered by both government and industry. In general, the potential sinks for geological storage of CO2 include storage in depleted oil and gas reservoirs, deep saline aquifers, coal beds and salt caverns as well as injection for enhanced oil recovery (EOR). Suitable geological conditions as well as availability of CO2 sources provide a vast potential for geological storage of CO2 in Saskatchewan, Canada. This paper examines and summarizes the potential sinks for geological storage of CO2 in Saskatchewan. More specifically, the potential for CO2 storage in locations throughout Saskatchewan along with estimated storage capacities are discussed in detail. The possible sinks in each storage category have been identified through creation of a database of the available information, screening the sinks according to the appropriate criteria for each category, and evaluating their potential in terms of CO2 storage capacity. The database includes a significant number of oil pools in different stages of development, saline aquifers, and coal beds throughout Saskatchewan. Southeastern Saskatchewan contains deep saline aquifers in addition to several light and medium oil pools which offer a great potential for CO2 EOR and storage. Extensive unmined coal beds also exist in the southern and western parts of the province which can be possible candidates for coal bed methane production and CO 2 sequestration. The identification and analysis of the potential sinks for geological storage of CO2 in Saskatchewan will contribute towards the development of integrated CCS infrastructure. This will also help to meet climate change mitigation objectives by reducing CO2 emissions through developing practical applications for geological storage of CO 2. Copyright 2011, Society of Petroleum Engineers.


Nasehi M.,IPAC CO2 | Asghari K.,University of Regina
Society of Petroleum Engineers - SPE International Conference on CO2 Capture, Storage, and Utilization 2010 | Year: 2010

Waterflooding has been used in oil recovery for many years and is an important technique in conventional oil recovery. In the case of viscous heavy oils, due to the low mobility of heavy oil and high mobility ratio between the displacing fluid (water) and the displaced fluid (heavy oil), reported recoveries have been very low and have been associated with very high volumes of produced water. Use of CO2 in heavy oil waterflooding, as a solvent that might effectively reduce the viscosity of heavy oil and causes it to swell, is the focus of this study. This paper presents the results of eleven core-flooding experiments designed to study the effect of CO2 utilization in waterflooding of heavy oils. Injection strategies used in these experiments involved different combinations of CO2 and brine, including intermittent injection of separate slugs as well as injecting carbonated water. In reported experiments, following the completion of waterflooding tests, CO2 slugs of 10% and 25% pore volumes, or carbonated water was injected into the cores followed by a shut-in period. Water injection was resumed at the end of shut-in period, and any additional oil produced was collected. Heavy oil samples with viscosities of 1000 to 2000 cp were used and experiments were carried out at pressures of 500 and 1000 psi (3.45 and 6.9 MPa), temperature of 30°C, and water injection rates between 1 and 50 feet per day. Carbonated water used in these experiments was prepared by dissolving CO2 in brine (1% wt. NaCl) at 820 psi over 4 days. Results of this study indicate that the use of CO2 significantly improves recovery of heavy oil by waterflooding. Incremental recoveries in the range of 5 to 27.5% OOIP were achieved by CO2 in combination with waterflooding. It was also found that the increase in the operating pressure results in increased oil recovery. Furthermore, the injection of larger CO 2 volume increased the oil recovery. It was also found that during the post CO2 waterflooding, greater recovery improvements are achieved from lower permeability systems. Comparison between the lower and the higher viscosity oils also showed that the use of CO2 results in greater recovery improvements for the higher viscosity oil system. Copyright 2010, Society of Petroleum Engineers.


Condor J.,IPAC CO2 | Suebsiri J.,IPAC CO2 | Wilson M.,OEE | Asghari K.,University of Regina
SPE Latin American and Caribbean Petroleum Engineering Conference Proceedings | Year: 2010

This paper addresses the process of using CO2 for enhanced oil recovery technique (CO2-EOR) as driver to produce more oil from depleted oil reservoirs, while leading to effective CO2 abatement. Here, a simplified summary of this complex system through a lifecycle emission analysis is presented. This analysis is based on two concepts: (i) the Carbon Footprint of CO2-EOR, and (ii) the Principle of Additionality in CO2-EOR. The data used for this analysis comes from the Weyburn project in Saskatchewan, Canada. The international community has been discussing for some time if CO2-EOR projects should be considered for carbon credits. There are still questions of "additionality" that should be addressed before the net climate impact of storing CO2 in an EOR project is verified. Since CO2-EOR has gained considerable interest within the oil and gas industry due to its potential for increased oil production, it is important to use a real case data to probe if CO 2-EOR is a viable CO2 abatement technology or if on the contrary, it may result in increased emissions. This study concludes that any emissions trading benefits from CO2 storing as part of a CO 2-EOR project should be discounted according to a detailed analysis of the full cycle carbon balance using the principle of additionality. A key exception to this should be when a commercially viable CO2-EOR project results in the development of pipeline infrastructure which would also enable long term geological sequestration without EOR. In this way, CO 2-EOR projects could play an important catalyst role in accelerating the deployment of CCS infrastructure. Finally a sensitivity analysis has indicated that the provision of petroleum tax breaks for CO2-EOR projects on the grounds of their emissions reduction potential is not the best use of public funds. This study provides guidance to whether or not CO 2-EOR projects should be eligible for carbon credits as part of deployment of CCS processes. Also this study contributes by defining an appropriate framework for developing guidelines, standards, and/or best practice manuals for the permanent geological sequestration of carbon dioxide. Copyright 2010, Society of Petroleum Engineers.

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