Yuan J.-Y.,Osum Oil Sands Corporation |
McFarlane R.,Alberta Research Council
Journal of Canadian Petroleum Technology | Year: 2011
The impact of steam quality, circulation rate and pressure difference between the well pair during SAGD initialization using steam circulation was explored through the use of numerical simulations employing a discretized wellbore model. These operating parameters appear to affect uniformity of reservoir heating, occurrence of steam breakthrough and time required to establish communication between the well pair. The simulation results indicate that, for the given tubing and liner sizes and reservoir properties, relatively lower circulation rates at high-steam quality are more favourable for faster initialization and development of uniform temperature between the horizontal well pair. At lower steam qualities, however, higher circulation rates appear more favourable. The use of high-steam quality in combination with high-circulation rates leads to slower rates of initialization, less uniform heating along the length of the wells and possibility of premature steam breakthrough at the heel. It was also found that having a higher steam quality in the lower well than in the upper well could lead to faster initialization and more uniform heating between the well pair. Although a large pressure difference is not encouraged, a small pressure difference, offsetting the natural hydraulic pressure (50 kPa), appears to be more favourable for faster and more uniform initialization. Source
Mohebati M.H.,Laricina Energy |
Yang D.,Laricina Energy |
MacDonald J.,Osum Oil Sands Corporation |
MacDonald J.,TransGlobe Energy Corp.
Journal of Canadian Petroleum Technology | Year: 2014
The Grosmont formation, a carbonate reservoir in Alberta, Canada, has 400 billion bbl of bitumen resource, which is currently not commercially exploited. The carbonate reservoir is karstified by groundwater and tectonically fractured, resulting in three classes of porosity: matrix, vugs, and fractures. The viscosity of bitumen is lowered by four to six orders of magnitude when heated by steam. Since December 2010, the Saleski pilot project evaluated steam-injection-recovery processes by use of four well pairs, two each in the Grosmont C and Grosmont D units. For the first year of the pilot, two well pairs were operated with continuous injection and production similar to successful steam-assisted-gravity-drainage (SAGD) projects in Alberta oil sands. Reservoir observations of steam/oil ratio (SOR) and calendar-day oil rate (CDOR) indicate recovery by gravity drainage is viable, although operating practices from conventional SAGD must be modified for the Grosmont formation. The decision to evaluate cyclic injection and production from single wells was made in early 2012, although it was recognized that cyclic operations created new challenges for the facility (which was built for SAGD operations) and artificial lift. The pilot data indicate that the drilling conditions (balanced vs. overbalanced), completions (openhole vs. slotted liner), and acid treatments of the wells have a significant impact on the individual-well performance. Injectivity into the Grosmont reservoir is high, even into a cold reservoir, because of the existing fracture system. Injection pressures stayed less than 40% of the estimated pore pressure required to lift the overburden. 4D-seismic results indicate that the injection conformance along the well axis is close to 100% and that the heated area is laterally contained around the well. Productivity is comparable to oil-sands project performance. The decline of oil rate is not only dependent on pressure but also on temperature. For cyclic operations, a CDOR of 43 m 3/d (for a 450-m-long well) and an SOR of 3.4 were achieved, demonstrating that with sufficient scale, a commercial project can be established successfully. The pilot has satisfactorily derisked the Grosmont reservoir at Saleski. While cyclic operations have demonstrated economic performance, continuous injection and production similar to SAGD remains an alternative recovery strategy beyond startup in the later depletion stage. Successful future developments will advance the optimization of drilling, completion, artificial-lift, and plant-capacity issues, while the reservoir itself has demonstrated its production capacity. Copyright © 2014 Society of Petroleum Engineers. Source
OSUM OIL SANDS Corporation | Date: 2010-05-18
The present invention relates generally to a method and means of injecting hot fluids into a hydrocarbon formation using a combustion and steam generating device installed at or near the well-head of an injector well. The various embodiments are directed generally to substantially increasing energy efficiency of thermal recovery operations by efficiently utilizing the energy of the combustion products and waste heat from the generator. The generator apparatuses can be installed at the well-head which, in turn, can be located close to the producing formation. The combustion products may be injected into a well along with steam or sequestered at another location.
OSUM OIL SANDS Corporation | Date: 2012-02-02
The present invention discloses a selection process for installing underground workspace in or near a hydrocarbon deposit that is an appropriate workspace from which to drill, operate and service wells applicable to any of a number of methods of recovering hydrocarbons. The present invention includes a number of innovative methods for developing workspace for drilling from a shaft installed above, into or below a hydrocarbon deposit, particularly when the hydrocarbon reservoir is at significant formation pressure or has fluids (water oil or gases) that can enter the workspace. These methods can also be used for developing workspace for drilling from a tunnel installed above, into or below a hydrocarbon deposit. The present invention also discloses a procedure for evaluating the geology in and around the reservoir and using this information to select the most appropriate method of developing workspace for drilling from a shaft and/or tunnel.
Yuan J.-Y.,Osum Oil Sands Corporation |
Nugent D.,Osum Oil Sands Corporation
Journal of Canadian Petroleum Technology | Year: 2013
Thermodynamic steam-trap control, or subcool control, in a typical steam-assisted gravity-drainage (SAGD) production is essential to the stability and longevity of the operation. It is achieved commonly through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing steam from the injector to bypass to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popular in the industry; however it does not prove to hold in many situations. This paper presents a study of the dynamics of SAGD-production control with a resulting algebraic equation that relates subcool, fluid productivity, and wellbore drawdown to the liquid level above a producer. The main conclusions of this study include • There is no minimum subcool value for a pure-gravity-drainage scenario; however, as the wellbore drawdown is considered, there is a minimum subcool value in order to maintain the stability of fluid flow. • For a given productivity, the liquid level increases as subcool increases or as wellbore drawdown decreases. • For each given set of operating parameters, there exists a critical productivity below which SAGD operation would halt. • Before the steam chamber reaches the top of the reservoir, the fluid productivity is limited by the vertical distance between the injector and the producer; the larger the distance, the higher the fluid-production rate can be. A verification of this analysis was conducted by a series of numerical reservoir simulations. Although limited to two dimensions, we expect that this analysis captures the main physics amid the dynamic complexity of SAGD-production control. The resulting algebraic equation can be used for better understanding of the dynamics of subcool control and for determining operation strategies. Copyright © 2013 Society of Petroleum Engineers. Source