Steam-assisted gravity drainage
Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells are drilled into the oil reservoir, one a few metres above the other. High pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where it is pumped out.
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Description [edit]
In the SAGD process, two parallel horizontal oil wells are drilled in the formation, one about 4 to 6 metres above the other. The upper well injects steam, and the lower one collects the heated crude oil or bitumen that flows out of the formation, along with any water from the condensation of injected steam. The basis of the process is that the injected steam forms a "steam chamber" that grows vertically and horizontally in the formation. The heat from the steam reduces the viscosity of the heavy crude oil or bitumen which allows it to flow down into the lower wellbore. The steam and gases rise because of their low density compared to the heavy crude oil below, ensuring that steam is not produced at the lower production well. The gases released, which include methane, carbon dioxide, and usually some hydrogen sulfide, tend to rise in the steam chamber, filling the void space left by the oil and, to a certain extent, forming an insulating heat blanket above the steam. Oil and water flow is by a countercurrent, gravity driven drainage into the lower well bore. The condensed water and crude oil or bitumen is recovered to the surface by pumps such as progressive cavity pumps that work well for moving high-viscosity fluids with suspended solids.
Sub-cool is the difference between the saturation temperature (boiling point) of water at the producer pressure and the actual temperature at the same place where the pressure is measured. The higher the liquid level above the producer the lower the temperature and higher is the sub-cool. However real life reservoirs are invariably heterogeneous therefore it becomes extremely difficult to achieve a uniform sub-cool along the entire horizontal length of a well. As a consequence many operators, when faced with uneven stunted steam chamber development, allow a small quantity of steam to enter into the producer to keep the bitumen in the entire wellbore hot hence keeping its viscosity low with the added benefit of transferring heat to colder parts of the reservoir along the wellbore. Another variation sometimes called Partial SAGD is used when operators deliberately circulate steam in the producer following a long shut-in period or as a startup procedure. Though a high value of sub-cool is desirable from a thermal efficiency standpoint as it generally includes reduction of steam injection rates but it also results in slightly reduced production due to a corresponding higher viscosity and lower mobility of bitumen caused by lower temperature. Another drawback of very high sub-cool is the possibility of steam pressure eventually not being enough to sustain steam chamber development above the injector, sometimes resulting in collapsed steam chambers where condensed steam floods the injector and precludes further development of the chamber.
Operating the injection and production wells at approximately reservoir pressure eliminates the instability problems that plague all high-pressure steam processes and SAGD produces a smooth, even production that can be as high as 70% to 80% of oil in place in suitable reservoirs. The process is relatively insensitive to shale streaks and other vertical barriers to steam and fluid flow because, as the rock is heated, differential thermal expansion causes fractures in it, allowing steam and fluids to flow through. This allows recovery rates of 60% to 70% of oil in place, even in formations with many thin shale barriers. Thermally, SAGD is twice as efficient as the older cyclic steam stimulation (CSS) process, and it results in far fewer wells being damaged by high pressure. Combined with the higher oil recovery rates achieved, this means that SAGD is much more economic than pressure-driven steam process where the reservoir is reasonably thick.[1]
Invention and development [edit]
The gravity drainage idea was originally conceived by Dr. Roger Butler, an engineer for Imperial Oil around 1969. But it wasn't until 1975 when Imperial Oil moved him from Sarnia, Ontario to Calgary, Alberta to head their heavy oil research effort that he pursued the concept. He tested the concept with Imperial Oil in 1980, in a pilot at Cold Lake which featured one of the first horizontal wells in the industry, with vertical injectors. The latter were established to be inefficient by research at the Alberta Oil Sands Technology and Research Authority (AOSTRA) in the early '80s. This resulted in the first test of twin (horizontal) well SAGD, at their Underground Test Facility (UTF) in the Athabasca Oil Sands, which proved the feasibility of the concept, briefly achieving positive cash flow in 1992 at a production rate of about 2000 bbl/day from 3 well pairs. The idea was greatly furthered by the work of Roger Butler's Ph.D. student at the University of Calgary, Dr. Swapan Das.
The original UTF SAGD wells were drilled horizontally from a tunnel in the limestone underburden, accessed with vertical mine shafts. The concept coincided with development of directional drilling techniques that allowed companies to drill horizontal wells accurately, cheaply and efficiently, to the point that it became hard to justify drilling a conventional vertical well any more. With the low cost of drilling horizontal well pairs, and the very high recovery rates of the SAGD process (up to 60% of the oil in place), SAGD is economically attractive to oil companies.
Current applications [edit]
This technology is now being exploited due to increased oil prices. While traditional drilling methods were prevalent up until the 1990s, high crude prices of the 21st Century are encouraging more unconventional methods (such as SAGD) to extract crude oil. The Canadian oil sands have many SAGD projects in progress, since this region is home of one of the largest deposits of bitumen in the world (Canada and Venezuela have the world's largest deposits).
The SAGD process allowed the Alberta Energy Resources Conservation Board (ERCB) to increase its proven oil reserves to 179 billion barrels, which raised Canada's oil reserves to the third highest in the world after Venezuela and Saudi Arabia and approximately quadrupled North American oil reserves. As of 2011, the oil sands reserves stand at around 169 billion barrels.
Disadvantages [edit]
As in all thermal recovery processes, cost of steam generation is a major part of the cost of oil production. Historically, natural gas has been used as a fuel for Canadian oil sands projects, due to the presence of large stranded gas reserves in the oil sands area. However, with the building of natural gas pipelines to outside markets in Canada and the United States, the price of gas has become an important consideration. The fact that natural gas production in Canada has peaked and is now declining is also a problem. Other sources of generating heat are under consideration, notably gasification of the heavy fractions of the produced bitumen to produce syngas, using the nearby (and massive) deposits of coal, or even building nuclear reactors to produce the heat.
A source of large amounts of fresh and brackish water and large water re-cycling facilities are required in order to create the steam for the SAGD process. Water is a popular topic for debate in regards to water use and management. As of 2008, American petroleum production (not limited to SAGD) generates over 5 billion gallons of produced water every day. [2][3] The concern of using large amounts of water has little to do with proportion of water used, rather the quality of the water. Traditionally close to 70 million meters cubed of the water volume that was used in the SAGD process was fresh, surface, water. There has been a significant reduction in fresh water use as of 2010, when approximately 18 million cubic meters were used. Though to offset the drastic reduction in fresh water use, industry has began to significantly increase the volume of saline groundwater involved. This, as well as other, more general water saving techniques have allowed surface water usage by oil sands operations to decrease by more than threefold since production first began.[4] Relying upon gravity drainage, SAGD also requires comparatively thick and homogeneous reservoirs, and so is not suitable for all heavy-oil production areas.
Alternative methods [edit]
Alternative enhanced oil recovery mechanisms include VAPEX (for Vapor Extraction), Electro-Thermal Dynamic Stripping Process (ET-DSP), and ISC (for In Situ Combustion). VAPEX uses solvents instead of steam to displace oil and reduce its viscosity. ET-DSP is a patented process that uses electricity to heat oil sands deposits to mobilize bitumen allowing production using simple vertical wells. ISC uses oxygen to generate heat that diminishes oil viscosity; alongside carbon dioxide generated by heavy crude oil displace oil toward production wells. One ISC approach is called THAI for Toe to Heel Air Injection.
See also [edit]
Notes and references [edit]
- ^ Speight, James G. (2007). The Chemistry and Technology of Petroleum. CRC Press. pp. 165–167. ISBN 0-8493-9067-2.
- ^ Ralph M. Hall, Statement to the Committee on Science and Technology for the Produced Water Utilization Act of 2008, 110th Congress 2d Session, Report 110-801.
- ^ "Water Use Breakdown in Alberta 2005". Government of Alberta. Retrieved 2005.
- ^ "Volume and Quality of Water used in Oil and Gas 1976-2010". Government of Alberta. Retrieved 4 October 2011.
