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Calgary, Canada

Reza Etminan S.,University of Calgary | Pooladi-Darvish M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc | Maini B.B.,University of Calgary | Chen Z.,University of Calgary
Fuel | Year: 2013

Measurement of gas diffusivity in reservoir fluids is of great interest for a number of applications, and among different methods for the measurement, the Pressure Decay method has received special attention due to its simplicity. In this technique, a non-volatile quiescent oil column is brought in contact with a diffusing single component gas from the top and the rate of change of gas pressure in the gas cap is recorded. The interpretation of outcomes is based on solution of a forward problem, which sometimes invokes a complicated boundary condition. In this work, an analytical solution is presented for the most general form of the boundary condition which models the interface. It takes into account all mass transfer key parameters including gas solubility, a diffusion coefficient and a possible interfacial resistance. The effect of resistance against mass diffusion at the interface is usually neglected in modeling. Through this solution, the role of interface resistance is better explained and one can realize how the resistance exactly affects the diffusion process. A detailed sensitivity analysis of each parameter is conducted and specifically in the case of interface resistance, it is illustrated that a numerical value can be reported for the interfacial resistance while it does not affect or hinder the diffusion process physically. This could unnecessarily increase the degree of freedom of the backward problem, and may lead to misleading parameter estimation results (despite a good match of the measurements). Using our new interface boundary condition reveals that some of the previous works on the modeling of interface resistance are subject to underestimation of the rate of gas dissolution which may lead to erroneous estimation of parameters. © 2012 Elsevier Ltd. All rights reserved.

Qanbari F.,University of Calgary | Pooladi-Darvish M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc | Tabatabaie S.H.,University of Calgary | Gerami S.,National Iranian Oil Company
Journal of Natural Gas Science and Engineering | Year: 2012

Reducing carbon dioxide (CO 2) emissions is becoming a significant environmental goal and undertaking worldwide, and is expected to be a major concern in the future. In this regard, sequestration of CO 2 in geological formations is of great interest. However, CO 2 is buoyant under the pressure-temperature conditions of typical geological sites, contributing to the risk of leakage. Storage of CO 2 as hydrate avoids this limitation. Much of the ocean sediments at depths of a few hundred meters below the ocean floor provide appropriate conditions for CO 2 hydrate formation. Furthermore, ocean sediments may provide conditions at which the density of liquid CO 2 is greater than the density of water, making liquid CO 2 gravitationally stable (i.e., non-buoyant).In this study, we investigate storage of CO 2 as hydrate below the ocean floor. We identify conditions where the initial pressure-temperature conditions are suitable for CO 2 hydrate formation and demonstrate the effect of changes caused by injection. In particular, the changes in pressure as a result of injection and the increase in temperature due to hydrate formation, both of which could lead to upward movement of CO 2, are investigated. Sensitivity studies are conducted to determine appropriate conditions for large scale CO 2 storage. In particular, the effects of ocean depth and injection depth in the sediment on flow of CO 2 toward the ocean floor are studied.The results of calculations for static conditions and modeling under dynamic conditions show that CO 2 hydrate formation and gravitational stability of CO 2 in the upper parts of the ocean sediments for some areas of the ocean can restrict upwards flow of CO 2 toward the seabed. If the ocean depth and sediment depth for injection of CO 2 are properly chosen, large volumes of CO 2 can be reliably stored in the sediment. © 2011 Elsevier B.V..

Zeidouni M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc
Journal of Petroleum Science and Engineering | Year: 2012

Deep saline aquifers are widely used for waste disposal and are the main candidates for storage of CO2 as a means of reducing greenhouse gas emissions to the atmosphere. Safety of disposal/storage projects highly depends on the containment of CO2 within the target aquifer. However, since the cap-rock overlying the aquifer may include leakage pathways that permit the injected fluids to leak to subsurface formations and/or to surface, detection and characterization of any such pathways from storage formations into overlying formations are required. A leakage test has been introduced in an earlier paper to characterize a leakage pathway through pressure monitoring in an overlying aquifer separated from the target aquifer by the cap-rock. A leakage pathway can be characterized by the leak transmissibility and location parameters, so a successful test should be able to provide sufficient confidence to evaluate the transmissibility and location parameters. In this work, different strategies are evaluated in order to achieve a successful test. The strategies include increasing the sampling frequency, use of pulsing, and increasing the number of monitoring/injection wells. The information provided by different strategies is evaluated, based on their effects on well-posing the inverse problem. The effects are studied based on information and correlation matrices, as well as the confidence interval. Locating the monitoring well is studied considering the requirements to ensure the safety of CO2 storage projects. Finally, we present a graphical method to obtain prior information on the leak based on the pressure derivative data. The graphical method is obtained based on deriving a new real-time analytical solution for the pressure at the monitoring zone. © 2012 Elsevier B.V.

Zeidouni M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc
Journal of Petroleum Science and Engineering | Year: 2012

Deep saline aquifers can provide the capacity for disposal/storage of undesirable surface fluids. To maintain containment and thereby prevent leakage of the injected fluids, the target aquifer should be overlain by a confining layer (cap-rock). However, there may be pathways in the cap-rock (e.g., transmissive faults, abandoned wells, active wells that partially penetrate the seal, and local seal weaknesses and fractures) that permit leakage of the injected fluids. Leakage to the subsurface formations may adversely affect the existing and potential energy and mineral resources and shallow ground water resources and soils. As such, detection and characterization of leakage pathways from storage formations into overlying formations are required. In this work, we suggest a flow and pressure test and present an inverse methodology to detect and characterize radially shaped leakage pathways based on the pressure data. The flow test is based on the injection (or production) of water into (or from) a target aquifer at a constant rate. The pressure is measured at a monitoring well in an aquifer overlying the target aquifer, which is separated by a cap-rock. Characterizing the leak based on pressure data involves solution of the leakage inverse problem. We investigate the uniqueness of the solution to the inverse problem through the use of the Hessian matrix and an analytical approach. The stability of the solution is analyzed based on sensitivity coefficients and the correlation matrix. The analyses are applied to a base case problem for which the leak characteristics are obtained over a confidence interval. © 2012 Elsevier B.V.

Morad K.,Fekete Associates Inc | Morad K.,Royal Dutch Shell
Journal of Natural Gas Science and Engineering | Year: 2012

Natural gas production from coalbed methane reservoirs makes up a sizable portion of total natural gas production in North America. In other countries such as Australia, China, Russia, UK, to name a few, coalbed methane is receiving a lot of attention and coalbed methane producers are keen to learn from North American experience in screening, exploration, pilot testing appraisal and field development.In this review, a select number of subjects important in describing the behavior of a coalbed methane reservoir and in predicting its future productivity, are reviewed. © 2011 Elsevier B.V..

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