Thermal Recovery at North Tisdale Field, Wyoming
Authors: Martin W.L. , Alexander J.D. , Dew J.N. , Tynan J.W. 
Published: December 2007

In the secondary recovery process used in this field, water was injected into combustion zones during active burning and after air injection had ceased. Combustion and steam stimulation treatments were also used at producing wells to improve sweep efficiency and production rates. Results indicated that higher crude oil prices are needed to make thermal recovery processes economic at Tisdale.

Introduction
The forward in-situ combustion process was the most important of several thermal methods applied at North Tisdale field, north central Wyoming. Operationally, a foward combustion process is basically a gas injection project. Air is usually injected at compressor capacity or at maximum permissible pressures. Combustion zones are permissible pressures. Combustion zones are established near the injection wells and propagated through the formation by continued injection of air, thus forcing formation fluids toward producing wells. The process is far from being clearly understood. However, consider-considerable progress has been made toward demonstrating its technical and practical feasibility .
Continental Oil Co. tested air injectivity at North Tisdale field in 1957 and performed the first fireflood ignition in Wyoming in May, 1959. Envisioned in the pilot test was a basic two-step process in which first pilot test was a basic two-step process in which first air would be injected, then water would be injected into the burned zones to create an in-situ hot waterflood and steam drive. This would utilize the residual heat behind the combustion front and improve the economics of oil displacement. Other modifications to the basic process, such as simultaneous or cyclic injection of air and water, were also envisioned in the original proposal. These methods were developed as the project proceeded.
Combustion and steam stimulation treatments were also used at producing wells during the project.

The Reservoir
The Curtis sand reservoir was discovered in June, 1952. Development continued during 1953 and 1954 on a 10-acre pattern that was somewhat irregular because of the rough terrain. Figs. 1 and 2 show the well locations. After 5 1/2-in. J-55 STC casing was set on top of the sand, the wells were completed by drilling 20 to 40 ft into the pay with cable tools and shooting with nitroglycerin.
The reservoir lies on top of a sightly arched and tilted water table that dips about 3 degrees to the north. Sand depth varies from 776 to 1,090 ft in the productive area. Gross sand thickness is about 100 ft, productive area. Gross sand thickness is about 100 ft, and average net effective pay in the developed area is about 50 ft. The original oil content was about 15 million bbl or 1,230 bbl/acre-ft.
The Curtis sand is a member of the Crow Mountain formation of the Triassic period. It is a porous, occasionally friable, orange-and-white sandstone with a field average permeability of 1,034 md, a porosity of 24.5 percent, and initial saturations of 64.6 percent oil and 35.4 percent water. The sour crude oil has a gravity of 21 degrees API and a viscosity of 175 cp at the original reservoir conditions of 290 psig and 73 degrees F.

Why Thermal Recovery Was Selected
Water cuts had increased to 50 percent by the time the original development was completed. The primary producing rate had declined from a peak of primary producing rate had declined from a peak of 312 BOPD to 180 BOPD by 1957, and it was estimated that less than 5.0 percent of the oil in place would be recovered economically.
JPT
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