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Laricina Energy Ltd. is a private Canadian oil producing company engaged in exploration in North-Eastern Alberta. The company targets oil sands opportunities outside of the Athabasca mining area and is focusing on in situ plays in the Grosmont and Grand Rapids formations. Its headquarters are located in Calgary, Alberta, Canada. Wikipedia.

Yang D.,Laricina Energy
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2014 | Year: 2014

Improving on initial experience in the Saleski pilot with wells drilled between 2008 and 2010, a second generation well (drilled 2012) delivers economically attractive bitumen rates at efficient steam-oil ratios. This performance de-risks the reservoir and forms a solid basis for development planning. A larger scale follow-up project will help to optimize well spacing, multiple-well operations, management of well interference, artificial lift systems, etc. Despite comparable conditions of cyclic operation, two wells located in the same reservoir perform differently. This is related to differences in drilling conditions, well completions and stimulation methods. After pioneering horizontal drilling into the Grosmont Carbonate formation, the performance of the second generation well in Saleski is significantly improved. This paper presents the performance indicators for the pilot well and discusses the key learning steps that led to the improvement. Copyright © (2014) by the Society of Petroleum Engineers All rights reserved. Source

Babadagli T.,University of Alberta | Edmunds N.,Laricina Energy
Journal of Canadian Petroleum Technology | Year: 2013

With the decrease in conventional oil and gas reserves throughout the world and an ever-increasing demand for fossil-fuel-based energy and resulting high oil prices, focus has been shifting to unconventional and heavy oil and bitumen. Grosmont carbonates in northern Alberta have been estimated to contain at least 300 billion bbl of heavy oil or bitumen. However, recovering this oil is extremely difficult because of the complexity associated with carbonate reservoirs in general (e.g., the Grosmont unit is known to possess a triple-porosity system of matrix, fractures, and vugs, on the basis of core studies). The second problem is the fluid itself, which is highly viscous bitumen that is immobile at reservoir conditions. To extract this bitumen from heterogeneous carbonate rock, both heat and dilution using solvents may be needed. This paper reports the results and analysis of hot-solvent experiments conducted on original Grosmont carbonate cores. Three experiments were conducted using propane and one using butane as solvent. After heating the entire system containing the core sample, solvent gas was injected. The rock was allowed to soak in the hot solvent for a long time. The experimental temperature and pressure were decided on the basis of the results of our earlier work that suggested they be slightly above the saturation line of the particular solvent. An attempt was made to keep the conditions close to the saturation conditions of the solvent being used to maximize the dilution and, hence, the recovery. The oil produced was analyzed for viscosity and asphaltene content. The results in terms of recovery, the degree of dilution, and upgrading achieved suggested that butane was a better solvent for this bitumen. Finally, the optimum conditions for operation of the hot-solvent process were verified for Grosmont carbonates. Copyright © 2013 Society of Petroleum Engineers. Source

Edmunds N.R.,Laricina Energy
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2013 | Year: 2013

Solvent-additive processes (SAP) are a promising, but challenging technology. Perhaps the biggest challenge from an engineering point of view, is that simulators probably work some of the time, but not all of the time; and there is no information about where the line between occurs, or what the correct answer should be, after the line is crossed. Other serious problems are the many degrees of freedom in SAP process design, and the non-linear relationships between process inputs and economic results. There are too many possible designs to try randomly for even a single reservoir, and there is limited theory to interpolate or scale available experimental data. This paper attempts to assemble some known pieces of the puzzle, and to explore how they may fit together to explain and predict SAP performance characteristics First, some familiar PVT relationships are presented, with examples using temperature as the independent variable. This helps to clarify the choice of solvent, as a function of reservoir pressure, and also to understand the effect of the increasing solvent "dose". It is shown that SAP will create a double front, one where the water is condensed, and a second where the solvent is absorbed by, and drains with, the oil. A vapor blanket separates the two fronts. Secondly, simple estimates are given for the temperature distribution in the vapor blanket (i.e. solvent-active zone). Together with PVT data for the same pressure, these allow the thickness of a vapor blanket to be estimated. Finally, SAP mass transport limits are considered, by observing that the second front essentially constitutes VAPEX. The Butler-Mokrys theory is discussed, in view of its failure to predict certain experimental results; it is argued that this results from neglect of capillary pressure effects, which in fact are dominant at the front. A purely empirical correlation by Nenniger is introduced, which can be rearranged to predict the maximum solvent speed, also as a function of temperature. Copyright 2013, Society of Petroleum Engineers. Source

Mai A.,Laricina Energy | Kantzas A.,University of Calgary
Journal of Canadian Petroleum Technology | Year: 2010

At the conclusion of primary heavy oil production, significant volumes of oil still remain in the reservoir under depleted reservoir pressure. Waterfloods are often considered for additional oil recovery. It is accepted that conventional oil waterflooding theory is not applicable for heavy oil. However, there is a lack of understanding of how waterfloods should perform in these reservoirs, particularly after water breakthrough. In this study, waterfloods were performed at multiple rates in cores containing heavy oil and connate water. In some cores, oil was initially free of solution gas, and waterfloods were a primary recovery process. In other cores, waterfloods were performed after primary production. Experiments were performed in linear systems for a high-viscosity oil (11,500 mPa·s at 23°C), at different injection rates. The influence of viscous and capillary forces is studied in primary vs. secondary recovery systems. A common misconception is that capillary forces are negligible in heavy oil; however, this work shows that these forces are significant, and that water imbibition after water breakthrough can lead to improved oil recovery in both primary and secondary waterfloods. Source

Pathak V.,University of Alberta | Babadagli T.,University of Alberta | Edmunds N.R.,Laricina Energy
Journal of Petroleum Science and Engineering | Year: 2011

Thermal and miscible methods are commonly used for in situ recovery of heavy oil and bitumen. Both techniques have their own limitations and benefits. However, these methods can be combined by co-injecting solvent with steam or injecting solvent into a pre-heated reservoir. The current work was undertaken to study the performance of solvents at higher temperatures for heavy oil/bitumen recovery. Glass bead packs and Berea sandstone cores were used in the experiments to represent different types of pore structures, porosity and permeability. After saturating with heavy oil, the samples were exposed to the vapor of paraffinic solvents (propane and butane) at a temperature above the boiling point of the solvent, and a constant pressure of 1500. kPa. A mechanical convection oven was used to maintain constant temperature across the setup. The setup was designed in such a way that a reasonably long sample (up to 30. cm) can be tested to analyze the gravity effect. The oil recovered from each of these experiments was collected using a specifically designed collection system and analyzed for composition, viscosity and asphaltene content. The final amount of oil recovered in each case (recovery factor but not extraction rate) was also analyzed and the quantity and nature of asphaltene precipitated with each of the tested solvents under the prevailing temperature and pressure of the experiment was reported. Optimal conditions for each solvent type were identified for the highest ultimate recovery. It was observed that recovery decreased with increasing temperature and pressure of the system for both solvents, and that the best results were found when experimental temperature is only slightly higher than the saturation temperature of the solvent used. It was also noticed that butane diluted the oil more than propane which resulted in lower asphaltene content and viscosity of oil produced with butane as a solvent. © 2011 Elsevier B.V. Source

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