We have developed a novel method to enhance oil production during cyclic steam injection. In the Top-Injection and Bottom-Production (TINBOP) method, the well contains two strings separated by two packers (a dual and a single packer): the short string (SS) is completed in the top quarter of the reservoir, while the long string (LS) is completed in the bottom quarter of the reservoir. The method requires an initial warm-up stage where steam is injected into both strings for 21 days; then the LS is opened to production while the SS continues to inject steam for 14 days. After the initial warm-up, the following schedule is repeated: the LS closed and steam is injected in the SS for 21 days; then steam injection is stopped and the LS is opened to production for 180 days. There is no soak period.

We have simulated and compared the performance of the TINBOP method against that of a conventional cyclic steam injector (perforated across the whole reservoir). Three reservoir types were simulated using 2-D radial, black oil models: Hamaca (9°API), San Ardo (12°API) and the SPE fourth comparative solution project (14°API). For the first two types, a 20×1×20 10-acre model was used that incorporated typical rock and fluid properties for these fields.

Simulation results indicate oil recovery after 10 years are 5.7–27% OIIP with TINBOP, i.e. 57–93% higher than conventional cyclic steam injection (3.3–14% OIIP). Steam-oil ratios are also decreased with TINBOP (0.8–3.1) compared to conventional (1.2–5.3), resulting from the improved reservoir heating efficiency.

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