Some oil and gas industry analysts have estimated that heavy oil and bitumen represent more than two-thirds of the world's oil reserves. As global energy demands increase, demand for production from these hydrocarbons will naturally increase. However, compared to conventional oil (obtained from more traditional and easily accessible sources), synthetic crude from bitumen is expensive and complicated to produce. Unlike conventional crude oil, bitumen does not flow freely. At room temperature, bitumen flows like cold molasses.
The two largest known sources of bitumen (Alberta, Canada and Venezuela) each contain more petroleum than the proven conventional oil reserves of the Persian Gulf. In Canada, synthetic crude oil produced from bitumen accounts for about 28 percent of total oil production. Alberta's bitumen deposits were commonly known as tar sands, but industry and government now prefer the more descriptive term, oil sands.
As of January 2009, there were 91 active oil sands projects in Alberta. Of these, five were mining projects and the remaining projects employed various in-situ (in place) recovery methods.
Mineable bitumen deposits are located near the earth's surface and can be recovered by open-pit mining techniques. For every barrel of oil, about two tons of oil sands must be dug up, trucked and processed. Roughly 75 percent of the bitumen can be recovered from the mined sands. After processing, the remaining sand must be returned to the pit and the site reclaimed.
Most in-situ bitumen comes from deposits buried too deeply below the earth's surface for mining techniques to be practical. Effective production of these deposits requires specialized thermal recovery techniques and equipment. There are three commonly used thermal recovery methods for extracting heavy oil: steam assisted gravity drainage (SAGD), steam flooding and cyclic steam stimulation (CSS, sometimes referred to as huff ‘n' puff). New high temperature electric submersible pump (ESP) systems have proven effective in thermal recovery applications, especially in recent SAGD installations discussed below along with the steam flooding method.
Steam Assisted Gravity Drainage
SAGD (Figure 1) is an advanced form of steam stimulation in which a pair of horizontal wells is drilled into the target formation, one a few meters above the other. Low pressure steam is continuously injected into the upper (injector) wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain via gravity into the lower (producer) wellbore, where it is pumped out. Thermally, SAGD is considered twice as efficient as the older CSS process, and it results in far fewer wells being damaged by high pressure.
High temperature ESPs have proven successful in SAGD applications. Key to the success is operating at elevated reservoir temperatures and lower bottomhole pressures that increase production rates and reduce the ratio of the steam injected to the oil produced. Generally, these drawdown pressures are lower than those typically generated by other types of artificial lift systems, resulting in faster recovery and improved financial performance.
Figure 1. SAGD production process
The SAGD production process involves four phases:
Start up/circulation. In this phase, steam is typically circulated for two to four months in both the injector and producer wellbores to heat up the region between the wells. The SAGD process can begin once the near well region is mobilized and there is fluid communication between the injector and producer.
Ramp up. This is the first stage SAGD recovery. Injection and production rates are increasing as the steam chamber grows to the top of the reservoir. Depending on oil viscosity and other operating conditions, this ramp-up or “soak” stage can take up to 18 months.
Plateau. This phase occurs when the steam chamber has reached the top of the reservoir and begins to spread laterally in the formation. This period is characterized by the best peak production rates (i.e., optimized production). Peak rate periods have been known to last as long as 60 months or more, depending on reservoir quality and thickness.
Wind down (or blow
