This paper reports the results of a numerical simulation study of a SAGD well pair history at Husky's Pikes Peak thermal project in the Lloydminster area. The pressure difference between the injector and producer gradually increased over a period of a year followed by a sudden and significant decline in fluid production rate. Initial numerical simulation identified the problem as being due to damage near the production well, because only this damage pattern matched observations on field production and pressure. A detailed history match of the field data was then conducted. By adjusting the value of skin factor, excellent matches on the production rate and injection and production pressure were obtained. It was shown that, by the time the skin factor had increased by a factor of 8 as a result of damage, and the pressure difference was about 900 kPa, the production rate started to drop significantly. Thereafter, the skin factor increased rapidly, and reached 30 times its original value. An acid treatment was performed on the production well. After the treatment, the skin factor returned to its original value, and the well pair returned to normal production.


SAGD has become the leading technology for in situ recovery of heavy oil and bitumen. The development of the technology has gone through several stages. The concept was first proposed by Butler(1) in the late 1970s. It was then tested at AOSTRA's Underground Test Facility (UTF) starting in the late 1980s. Phase A of the UTF test proved the concept in the field (2, 3). A number of issues were considered during the test: start up, sand control, steam trap control, reservoir heterogeneities, effect of solution gas, and numerical simulation. The result of Phase A was successfully scaled up to longer wells in Phase B (4, 5). Horizontal drilling from the surface, and operation of SAGD from the surface was the purpose of the Phase D study (6).

This report summarizes the results of a SAGD field case study. At Husky's Pikes Peak thermal project, located in the Lloydminster area, one SAGD well pair experienced a sudden decline in fluid production. Numerical simulation identified the problem as being due to damage near the production well. The simulation also revealed the pattern and extent of the damage. After acid treatment of the production well, production returned to normal.

Brief Description of the Field Project

The Pikes Peak thermal project started in 1981 using the cyclic steam stimulation (CSS) technology. Later on, SAGD technology was also employed. The details of the project history and the area geology can be found in early publications (7, 8). In the subject area, the depth from surface to the top of pay zone was around 500 m. The net pay thickness was about 16 to 18 m. Part of the pay in the toe section of a SAGD wellpair drilled in 1999 was underlain by a water zone which was unconfined. The reservoir pressure was 2,300 kPa at the start-up of the subject well pair and the reservoir temperature was 18 °C.

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