Feasibility study of in-situ heat generation for oil reservoirs underlying the permafrost

Abstract

Development of a heavy oil reservoir is a challenging issue in the oil industry. One of the major issues in heavy oil recovery is its high viscosity; so, using heating methods for producing oil have been developed and employed from the early 1950s. The existing relatively thick permafrost layer which overlays the heavy oil reservoirs of the North Slope of Alaska creates additional complexities for development of these heavy oil reservoirs. Applying any heating oil recovery process in regular way to these heavy oil Alaskan reservoirs would potentially jeopardize the permafrost layer. A down-hole heat generation system has been developed that uses a chemical and a special catalyst to generate heat. The effluent of this system would be steam and nitrogen. The system can be installed in a well string and at the bottom of the injector well. This thesis investigates the feasibility of employing this system for development of the heavy oil reservoirs that underlie the permafrost. The results of this study can be used for any steam injection process which uses any device for down-hole steam generation. The STARS module of the CMG reservoir simulation package is used for this study. In the model, live oil with a viscosity of about 30,000 cp is used. By examining several models with vertical and horizontal wells, a 3-D model with two horizontal injector and producer wells is ultimately constructed for final runs. Different sensitivities are run to find out the optimum operational parameters. Based on the results, a lateral well length of 800 ft in the middle of a reservoir with length of a 1250 ft is selected as a base case. Areal grid block size of 10 ft × 10 ft with the layer thickness of 10 ft in a reservoir with thickness of 50 ft is employed. To minimize the down-hole well bore temperature of the producer, just the last 50 ft (out of 800 ft of lateral length) at the toe of the well is opened to flow. Three different steam injection processes are examined: Steam Assisted Gravity Drainage (SAGD), Cyclic SAGD (CSAGD) and Cyclic Steam Stimulation (CSS). Simulation results reveal that the producer well bore temperature in optimum cases for SAGD, CSAGD and CSS is more than 140 ˚F, 110 ˚F and 100 ˚F, respectively. Also, the 10-year simulation period oil recoveries for optimum cases of SAGD, CSAGD and CSS are about 35%, 18% and 12%, respectively. On the other hand, results show applying any steam injection recovery method (SAGD, CSAGD or CSS) can only be recommended when the thickness of the overlying Sagavanirktok sand formation (which separates the permafrost from the heavy oil reservoir) is equal or more than 300 ft. The results also show that the addition of nitrogen has negative effect on the oil recovery. Based on the results, it is recommended to employ SAGD or CSAGD, but employ a system to cool the producer well-string to avoid melting the permafrost. A simple system of cooling the producer well-string is suggested.