MARCO CONCEPTUAL

Thermal methods assure some of the highest recovery factors. They also promise the largest potential capital expenditure and operating costs—and therefore risk. Four techniques tested for new thermal production methods currently stand out above the rest:

2.2.1.1 Cyclic steam stimulation (CSS)

It is considered to be the oldest commercial method among all the techniques.

A single well is used to inject steam into the reservoir for the purpose of heating the oil and reducing its viscosity. After the reservoir has been through a soak phase, the operation of the injector well is reversed to produce the oil. The “huff and puff” process is divided into three stages as shown in Figure 2-8.

Figure 2-8: Stages of CSS for a single well (CEAA, 2011)

In order to soften the oil sand before pumping, for several weeks high-pressure steam is injected into the oil sand formation, since the steam helps recover the resource in several ways. The heat softens the oil sand and the water vapour helps to break up the bitumen and heavy oil from the sand. The pressure created in the underground environment causes cracks to be formed that adds drive to move the bitumen to producing wells. After a portion of the reservoir has been satisfactorily saturated, the steam is turned off and the reservoir allowed to sit for several weeks. After it has been allowed to sit and soak up the steam and moisture, the production phase brings the bitumen to the surface. It either flows on its own, or is pumped up the well to the surface. When the rates of production start to decline, the reservoir is pumped with steam once again.

CSS is the preferred method for production when the heavy oil reservoirs can contain the high-pressure steam without fracturing the overburden, therefore a minimum depth of 300 m but have been successfully deployed at depths

between 200 and 300 m. Resource recoveries using this technique are in the range of 20-35 percent (Clark, 2007).

However many problems arises from using this method. The very high cost of injecting the generated heat is one, trying to maintain it in the reservoir without escaping to the surface due to being lighter than rocks or fluids is another, also drawdown to low pressures during production cycles leads to water coming into the production region, giving excessive water production and high heat losses.

2.2.1.2 Steam flooding

In a steam flood, sometimes known as a steam drive, some wells are used as steam injection wells and other wells are used for oil production. Two mechanisms are at work to improve the amount of oil recovered. The first is to heat the oil to higher temperatures and to thereby decrease its viscosity so that it more easily flows through the formation toward the producing wells. A second mechanism is the physical displacement employing in a manner similar to water flooding, in which oil is meant to be pushed to the production wells as shown in Figure 2-9. While more steam is needed for this method than for the cyclic method, it is typically more effective at recovering a larger portion of the oil.

Figure 2-9: Steam flood technique (James and Wing, 2011)

This method posses all of the same problems listed above for CSS method, except for the premature water breakthrough that happen in the low-pressure production phase of CSS depending on the specific geometry of the drive process. Casing shear can be much more serious than in CSS because of the high shear stresses generated in a “2-D” in line drive (In CSS, which is a process that develops radically around a well, the shear stresses drop off with distance from the heated zone leading edge).

2.2.1.3 Steam Assisted Gravity Drainage (SAGD)

SAGD is a more recent development when compared to other thermal methods.

It is becoming a very popular option because of its ability to produce from reservoirs too shallow for other thermal methods. As the SAGD process operates at lower steam pressures than CSS or Steam flooding, less overburden is required for steam containment in the reservoir (Clark, 2007).The SAGD production involves the use of two horizontal wells. The horizontal injector well, located above a horizontal producer, is used to raise and form a suitable environment “steam chamber” to encourage increasing the temperature of the oil. The heated oil then drains downward to the horizontal producer well located parallel and beneath the injector well, as shown in Figure 2-10.

Figure 2-10: SAGD principle (ACR, 2004)

The SAGD is not exempt from challenges and difficulties. Building a well reservoir knowledge and fluid characterization is one factor to help a more productive and informed decision making in using the SAGD, because the viscosity can change significantly within the same reservoir; however accurate evaluation is difficult to be achieved. The quantity of steam injected and fluid produced depend on reservoir characteristics such as permeability, porosity, water saturation, and on the length of the well. Some of the factors that determine the length of a well include geology and the pressure drop between the heel and the toe in the horizontal section. The pressure drop in an injector is a function of steam volume, pressure and pipe size. Using a larger casing will reduce this pressure drop. The selection of the size of the liner and the intermediate casing is also influenced by the size of tubing and other instrumentation strings inside the casings (Knoll and Yeung, 2000). Another issue is sand production control; where the sand has to be monitored for most optimized rate of oil production, as it always the case for all production methods.

2.2.1.4 Toe to Heel Air Injection (THAI)

The THAI process was invented in 1993; it combines vertical air injection with a horizontal production well. In this approach, the heat, which generated by burning part of the oil in place in the formation, expands outward in the formation.

Figure 2-11: THAI diagram (The oil drum, 2009)

For the first three months, steam is injected in the vertical well to heat the horizontal well and condition the reservoir around the vertical well. After the first three months, compressed air is injected in the vertical well and combustion is initiated, as shown in Figure 2-11. The well geometry enforces a short flow path so that the instabilities associated with conventional combustion methods are avoided or reduced. Estimates from experimental tests indicate that the process can recover 80% of original oil-in-place while partially upgrading the crude oil in situ (The oil drum, 2007)