Core Property Overview
Oil Exploitation
To drive value from our oil assets, we pursue three types of exploitation: primary, secondary and, more recently, tertiary recovery projects. All three demand intricate reservoir evaluations and very specific and detailed exploitation plans.
Primary Recovery Projects
Primary oil recovery projects are defined as projects where oil can be produced from a number of natural mechanisms such as reservoir gas expansion or pressure support from an underlying aquifer. The reservoirs that we work on tend to be only partially developed due to lower permeability rock, poorly defined boundaries of a pool or, in some cases, simply inefficient pool development. We use our technical skills to employ traditional and new technologies to increase oil recovery factors in these reservoirs. Typically, our primary recovery projects are developed with vertical wells or horizontal wells, which sometimes require fracture stimulation to initiate production. In some cases, we simply upgrade pumping equipment or fluid handling and treating facilities. As each of our projects tends to contain only 4 to 20 million barrels of oil-in-place (as recognized by the regulatory authorities), they are often overlooked by larger competitors. Still, the project economics can be very attractive.
For the primary projects, we use three dimensional (“3D”) seismic, detailed geological studies, reservoir engineering and historical vertical well drilling data to identify and characterize our oil reservoirs.
Secondary (Waterflood) Recovery Projects
Secondary oil recovery projects, also known as waterfloods, rely on the injection of water to increase pressure in a reservoir in order to improve production rates and recovery of the oil-in-place. In some cases, we are working on larger, mature assets where we use our technical background to modify an existing waterflood. On the other hand, we are also working on partially developed pools with lower permeability rock or poorly defined boundaries where waterfloods have not been attempted.
Waterflood projects can have a lengthy start-up as working and royalty interests might need to be negotiated, and regulatory applications must be prepared and submitted prior to construction or modification of field facilities to permit water injection. Once water injection commences, it can take years for the reservoir to repressure and to realize improved production rates. Our waterflood projects tend to have a larger amount of oil-in-place than our primary projects, ranging from 4 to 40 million barrels of oil-in-place (as recognized by the regulatory authorities). While these pools are small on the industry scale, the project economics can be very attractive. As with our primary projects, we find that these smaller scale and longer term projects can be overlooked by larger competitors or our less patient peers.
For our waterflood projects, we use the same evaluation techniques as our primary recovery projects: 3D seismic, detailed geological studies, reservoir engineering and vertical well control. Typically, once water injection has restored reservoir pressures, we accelerate production with the drilling of horizontal or vertical drainage wells.
Tertiary (Enhanced) Recovery Projects
With the addition of the Little Bow property in the 2009 Masters acquisition, we have added a tertiary recovery project to our oil exploitation inventory. Tertiary, or enhanced recovery, is the next phase in recovery techniques after primary and secondary projects and typically involves the injection of specific chemicals to improve oil production and oil recovery factors. At Little Bow, we are seeking to increase the pool’s oil recovery factor to 52 percent from the 40 percent currently being achieved under a waterflood. Our working interest gives us ownership of 24 mmbbl of oil-in-place (as recognized by the Alberta ERCB regulatory authority) in this Glauconite channel sand.
With the Little Bow project, we are working with a chemical injection process known as an Alkaline Surfactant Polymer (“ASP”) flood, which can be suitable for high-permeability, medium-gravity sandstone reservoirs. This particular application involves the injection of alkalines and surfactants in a water solution into the reservoir. The technology uses the characteristics of the cleaner-like alkaline caustic agent and the detergent-like surfactant to lower the capillary pressure that impedes the oil droplets from moving through a reservoir. Polymers are added to the mixture to increase the viscosity (thickness) of water and help flush the remaining oil out of the reservoir.
The majority of our Little Bow laboratory core flood and chemical analyses have been completed, along with reservoir simulations that have shown positive results. Later this year, we anticipate completion of our reservoir studies, project design and detailed cost estimates, and we will then proceed to a decision on this $25 million capital project. Assuming project approval, field construction would proceed in 2011, initial injection would commence in early 2012, and peak oil production would be reached in 2014.
Although ASP tertiary floods are relatively new technology and time consuming to implement, we believe that ASP technology has a very significant upside for southern Alberta’s high-permeability, medium-gravity, Mannville reservoirs.
Natural Gas Exploitation
Our natural gas exploitation business is centred on large undrained gas-in-place resources, or on partially depleted existing natural gas reservoirs. These exploitation opportunities are found across our undeveloped land base throughout our Alberta Plains and West Central Alberta core areas.
By far, the largest development in the natural gas industry in the last two years has been horizontal well fracturing technology. This development now enables the production of low-permeability (“tight”) conventional reservoirs, or very tight resource reservoirs. The delivery of multiple fracture stimulations in horizontal wells is also well suited to the exploitation of tighter partially drained conventional reservoirs with a significant remaining gas-in-place. Although these discrete conventional opportunities do not have the scale being pursued by our larger competitors, the returns using this new technology can be very attractive.
The Alberta Plains core area consists of generally mature natural gas producing properties where Zargon has a high operated working interest and controls the natural gas gathering and processing infrastructure. Many of these reservoirs are only partially depleted and hold significant undrained remaining gas-in-place. The West Central Alberta natural gas properties are less developed and somewhat more disparate in nature, but provide numerous poorly drained gas-in-place reservoirs that may be suited to the application of new stimulation technology.
In addition, Zargon holds 229 and 250 thousand net acres of undeveloped lands in the Alberta Plains and West Central Alberta core areas, respectively. These lands provide Zargon significant option value related to the application of the new stimulation technologies onto gas-in-place opportunities.
Over the next year, we will continue the necessary expenditures to evaluate the natural gas exploitation potential of our lands and our partially depleted reservoirs.