Understanding SAGD Producer Wellbore/Reservoir Damage Using Numerical Simulation
Authors: Zhao L. , Anderson D.B. , O&apos;Rourke C. 
Published: March 2010

This paper reports on the results of a numerical simulation study of a SAGD well pair at Husky's Pikes Peak thermal project in the Lloydminster area. The pressure difference between the injector and producer wells gradually increased over a period of a year followed by a sudden and significant decline in the 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 of 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. This case study is an example of how numerical simulation can be used as a tool to diagnose, identify and analyze SAGD operational problems.

Introduction

SAGD has become the leading technology for in situ recovery of heavy oil and bitumen in northern Alberta, Canada. The development of the technology has gone through several stages. The concept was first proposed by Butler(1) in the late 1970's. It was then tested at AOSTRA's Underground Test Facility (UTF) starting in the late 1980's. 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 Phase A results were 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. A high pressure drop between the injector and producer wells identified the problem as being due to damage near the production well. Simulation revealed the pattern and extent of the damage. After an 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 cyclic steam stimulation (CSS) technology. The project was located in the Lloydminster area on the Saskatchewan side, as shown in Figure 1. Later on, SAGD technology was also used. The details of the project history and the area geology can be found in earlier publications(7, 8). In the subject area, the depth from the surface to the top of the pay zone was around 500 m.