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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.


Jiang Q.,Osum Oil Sands Corporation | Thornton B.,Osum Oil Sands Corporation | Russel-Houston J.,Osum Oil Sands Corporation | Spence S.,Osum Oil Sands Corporation
Journal of Canadian Petroleum Technology | Year: 2010

Cyclic steam stimulation (CSS) has been a commercial recovery process since the mid 1980s in the Cold Lake area of northeastern Alberta. The current bitumen production is over 220,000 B/D using CSS from this area. To achieve desired injectivity in the bitumen saturated reservoir, steam is usually injected at a pressure above or close to the fracture pressure of the formation. A relatively high-pressure drawdown is created between the wellbore and formation during the production phase, particularly in the early stage of the production cycle where formation compaction and solution gas drive are the two most important recovery mechanisms. The CSS process has limited application in reservoirs with thick bottom-water or in reservoirs with fine grain sands. The steam assisted gravity drainage (SAGD) process has been field tested and commercially expanded in the Lower Grand Rapids (LGR) and Clearwater formations in the Cold Lake area. In contrast to CSS, SAGD is a continuous steam injection process that relies on gravity and requires a minimum pressure drawdown to drive the reservoir fluids to the wellbore. This provides a significant advantage for SAGD as an option for the reservoirs with bottomwater, top gas or with formations with fine grain sands. Several SAGD projects are in operation in different types of reservoirs in the Cold Lake and Lloydminster areas, some with thick bottomwater zones. A performance review is conducted based on the available data for various CSS and SAGD projects in the Cold Lake area. The selection criteria between CSS and SAGD technologies for Clearwater and LGR are discussed. Reservoir modelling results are presented concerning the impact of well placement, reservoir heterogeneity and operating parameters on SAGD performance, based on Osum's LGR and Clearwater geology in the Cold Lake area.


Yuan J.-Y.,Osum Oil Sands Corporation | Nugent D.,Osum Oil Sands Corporation
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2012 | Year: 2012

Thermodynamic steam trap, or sub-cool control, in a typical SAGD production is essential to the stability and longevity of the operation. It is commonly achieved through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing bypassing of steam from the injector 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 sub-cool estimation of 10°C/m of liquid level is popularized in the industry, however, 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 sub-cool, fluid productivity and wellbore draw down to the liquid level above a producer. The main conclusions of this study include: a. There is no minimum sub-cool value for a pure gravity drainage scenario; however, as the wellbore draw down is considered there is minimum sub-cool value in order to maintain the stability of fluid flow. b. For a given productivity, the liquid level increases as sub-cool increases or as wellbore draw down decreases. c. For each set of parameters, there exists a minimum productivity below which SAGD operation would halt. d. Before the steam chamber reaches the top of the reservoir, the production rate is limited by the vertical distance between the injector and the producer, the larger the distance the higher the production rate can be. A verification of this analysis was conducted via a series of numerical reservoir simulations. Although limited to 2D, we believe this analysis captures the main physics amid the dynamic complexity of SAGD production control. The resulting algebraic equation can be used for better understanding the dynamics of sub-cool control and determining operation strategies. Copyright 2012, Society of Petroleum Engineers.


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.


Qi J.,Osum Oil Sands Corporation | Yuan J.-Y.,Osum Oil Sands Corporation
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2013 | Year: 2013

The Devonian Grosmont Formation is a bitumen saturated carbonate unit located in northern Alberta. It is considered to be Canada's second largest unconventional oil resource after the McMurray Formation oil sands. Production from the Grosmont Formation has been tested by a consortium of Unocal, Canadian Superior, AOSTRA, Chevron and other companies between 1970's to 1980's with some success and significant learning. Since 2010, Laricina Energy Ltd. and Osum Oil Sands Corp. have started a new wave of testing thermal recovery processes for the Grosmont Formation using horizontal wells. The Grosmont C carbonate reservoir contains vugs and fractures at multiple scales, and thus has a different porosity and permeability network than the clastic oil sands. This paper describes a numerical simulation approach to history matching the performance of one of the pilot wells in order to better characterize reservoir properties such as fractures and vugs at multiple scales and their interactions with the rock matrix. CMG's STARS dual porosity dual permeability module was used to simulate this complex system. The results of the simulation suggest that small-scale vugs should be combined with the matrix in order to obtain a better history match of the reservoir and production performance. Parameters describing fracture properties have become critical not only in matching the well behavior, but also in matching reservoir thermal responses. Advantages, limitations, and recommendations for using a dual porosity and dual permeability model for understanding a multiple-scale porous and permeability system are also discussed. Copyright © 2013 by the Society of Petroleum Engineers.


Qin K.,Osum Oil Sands Corporation | MacDonald J.,Osum Oil Sands Corporation
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2013 | Year: 2013

The Upper Devonian Grosmont formation is considered to be Canada's next largest unconventional oil resource play, with an estimated 406 billion barrels of heavy oil in place. A number of production pilots targeting the Grosmont formation have tested various thermal enhanced oil recovery techniques, which include steam flood, combustion, and cyclic steam stimulation (CSS). To date, the CSS process has demonstrated considerable promise based on performance from the Unocal Buffalo Creek Phase 2 pilot and through the application of C-SAGD, a CSS variant designed for the Grosmont, at the Laricina-Osum joint-venture pilot in Saleski. While the methodologies for forecasting CSS production profiles are well understood for clastic oil sands reservoirs, no direct analogue exists for carbonate reservoirs such as the Grosmont. The current profiling model for clastics appears to be suitable for matching and forecasting the production characteristics of CSS and the early cycles of C-SAGD in the Grosmont. However, a few extensions to the current profiling models are required to address differences in cycle length, bitumen ramp up, and oil cut characteristics. For instance, oil cuts are typically low initially and increase with time for the majority of cycles in clastic oil sands, whereas in the Grosmont, there is observed cycle-to-cycle variability. The first few cycles typically show high initial oil cuts, decreasing with time; in subsequent cycles, the oil cuts behave similarly to clastic reservoirs. These differences can be attributed to the presence of secondary porosity and permeability systems in the carbonate formation, such as vugs and fracture networks, and their interactions with the matrix. This paper will describe the modification to existing models for profiling production, based on field observations from the aforementioned pilots. Copyright 2013, Society of Petroleum Engineers.


Jiang Q.,Osum Oil Sands Corporation | Yuan J.,Osum Oil Sands Corporation | Russel-Houston J.,Osum Oil Sands Corporation | Thornton B.,Osum Oil Sands Corporation | Squires A.,Osum Oil Sands Corporation
Journal of Canadian Petroleum Technology | Year: 2010

The Upper Devonian Grosmont Formation is a bitumen-saturated, carbonate unit located in Northern Alberta. It is considered to be among the world's next largest unconventional oil resource plays. Since early 2006, there has been an increased interest in Grosmont resources exhibited by a range of companies, including super-majors. Several in-situ pilot tests were conducted in the central portion of this area in the 1970s and 1980s, using steam and in-situ combustion processes. Similar to field tests in the McMurray Formation oil sands before invention of the Steam-Assisted Gravity Drainage (SAGD) process, none of the early recovery technologies tested proved to be economic. Because the "gravity" drainage process has proved successful in commercial development of the McMurray Formation oil sands since the mid- to late1990s, the recovery potential for the Grosmont Formation should be re-evaluated, based on improved recovery techniques. Results from cyclic steam stimulation (CSS) field tests are compared and analyzed to understand the similarity and fundamental differences in reservoir properties between the McMurray Formation oil sands and the Grosmont Formation carbonate rocks. A preliminary interpretation is provided for laboratory test results for solvent processes applied to Grosmont carbonate cores. The scaling considerations from the laboratory results to field expectations are discussed. The paper also provides a direction for future studies and optimization opportunities for reservoir recovery leading to the commercial development of Grosmont carbonate reservoirs.


Russel-Houston J.,Osum Oil Sands Corporation | Gray K.,Osum Oil Sands Corporation
Interpretation | Year: 2014

We delineated a bitumen-rich paleokarsted carbonate reservoir of the Upper Devonian (Frasnian) Grosmont Formation with a high-resolution 3D seismic survey tied to core and petrophysical log data from 35 wells within a 34.2 km2 study area in northern Alberta, Canada. There were two laterally continuous karst facies: a solution-enhanced vuggy dolostone that resulted from the carbonate dissolution of body fossils and a stratiform breccia that resulted from the dissolution of interbedded evaporites. Three laterally discontinuous karst facies were identified: sinkhole fills, collapsed paleocaves, and solution valley fills. We measured 368 subcircular features (sinkholes and collapsed paleocaves) having a median circle-equivalent diameter of 69 m and representing 5.5% of the total study area. Sinkhole fills include Cretaceous-aged sandstone, mudstone, and coal. Collapsed paleocaves were filled with matrix-supported breccia that had clasts of disoriented blocks of dolomite and a matrix of disaggregated dolomite and Cretaceous-aged mudstone. The paleocaves and sinkholes formed in the solution-enhanced karst facies of the Grosmont C at the interface of an interpreted ancient vadose-phreatic mixing zone. The marine deepwater deposition of the Clearwater Formation during the Albian filled the depressions created by the mechanical collapse of the paleocaves and provided a seal for thermal operations. The fracture density inferred from seismic amplitude variation with angle and azimuth analysis and corroborated by well data showed that fractures are ubiquitous and were enhanced during meteoric karst. The high-vertical permeability resulting from solution-enhanced fractures, the laterally predictable flow units, and a competent seal make this an ideal reservoir for thermal bitumen recovery. © 2014 Society of Exploration Geophysicists and American Association of Petroleum Geologists. All rights reserved.


Patent
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.


Patent
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.

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