Hydrocarbon miscible gas flooding is the most common enhanced oil recovery method applied to light oil in Alberta. A number of field applications have been initiated or are being considered for the Beaverhill Lake carbonate and Gilwood sand reservoirs.
A problem common to essentially all applications is the large disparity between the relatively high mobility of injected gases and the mobility of reservoir fluids, The development of gas fingers results in early gas breakthrough which necessitates expensive reinjection of produced gases. Application of foam forming surfactants could reduce the gas mobility and thus achieve more uniform propagation of the injected solvent throughout the pattern.
Extremely high salinity and hardness of formation water is one of the characterist1cs typical of the Beaverhill Lake carbonate and Gillwood sand pools. Poor surfactant solubility in high salinity brines limits severely the numbers of foam-forming surfactants suitable for applications in such pools. The fact that fresh water injection has been underway in some of the pools complicates surfactant selection even further as the surfactant must be effective, not only at high salinity and hardness, but also over a wide range of salinities and hard nesses.
The Petroleum Recovery Institute has asked chemical manufacturers to suggest suitable foam forming surfactants for such conditions, and has received 157 surfactant samples from 45 suppliers from all over the world. Experimental results obtained with some of the surfactants are discussed in this paper.
The Beaverhill Lake carbonates and Gillwood sands pools are part of the oil bearing formations from the Devonian period.1 They cover a large area northwest of Edmonton, between Tawnships 80 and 89. and between the fifth and sixth meridians (Figure 1).
Gilwood sands consist of 19 producing fields, and the Beaverhill Lake carbonates include 27 fields. Some of the relevant reservoir characteristics of these pools are summarized in Table 12–6. A specific examples of more detailed information for Swan Hills is shown in Table 2. 2.
In general, all considered pools contain light Oil, and the hardress am salinity of the formation brine is extremely high. Reservoir temperature vary from 80 to 127 °C, and the upper limit of the pressure range is 37.9 MPa. The salt concentrations In the brines range from 100,000 ppn TDS in the Cranberry-Gilwood. A pool to 290,000 ppm TDS in the Mitsue-Gilwood A pool. Examples of the ionic compositions of the brines are shown in Table 3. Large amounts of divalent ions, such as Ca2+ and Mg2+, are evident with concentrations ranging from 5,800 to 17,000 ppm.
In order to gain insight about the high salinities of these formation brines, the limits of solubility of some salts at different temperatures are listed in Table 4. It can be seen that formation brines of the Beaverhill Lake and Gilwood pools are not far from the saturation limits for these salts.