Optimizing Waterflood Performance by Utilizing Hot Water Injection in a High Paraffin Content Reservoir

Abstract

Abstract The application of heated water injection in a conventional oil reservoir under secondary recovery has received sparse review in the literature. In general, such a scheme can be difficult to justify. This is often due to both the additional capitalization and fuel costs offsetting the potential advantages that can be practically achieved for the effects of the differential water temperature to that of the formation. However, under appropriate circumstances, hot water injection can provide a significant advantage for secondary recovery that may warrant further investigation. As a case study, the Senex field of northern Alberta, Canada contains a 37°API crude with high paraffin content in a low permeability shelf carbonate. The oil is essentially saturated with paraffin at the reservoir temperature of 36 C. Paraffin precipitation within the reservoir porosity accounts for declining production rates, which have been commonly treated and temporarily reversed with an extended history of chemical and solvent squeezes. Due to the northern latitude of the field, source water has been injected at ambient temperatures to within several degrees of the freezing point for up to 7 months of the year. The impact of this operation on injector and reservoir performance proved to be of concern after an injection well appraisal revealed an extended loss of injection capacity in the early startup of waterflooding operations. Subsequently, the thermal implications for the viscous forces to the reservoir dynamics in waterflooding were studied in a numerical simulator, which demonstrated this mechanism for recovery impairment. In addition, a qualitative assessment of the further thermal implications for deterioration of reservoir performance from paraffin deposition was established. In order to test and further validate the conclusions of this analysis, a pilot hot water injection scheme was initiated in April, 2001. This paper will describe the aspects of planning, testing and modeling that were completed prior to the field implementation of this project. Preliminary field results are also presented. Introduction For highly paraffinic oils, thermal effects can be extensive due to several mechanisms. Ring1 et al and Bedrikovetsky3 discuss the thermal consequences to paraffin deposition. Ring documents a numerical paraffin deposition model for precipitation within the reservoir porosity. He provides a dramatic illustration of a field example where heat treatments in the near wellbore region have been demonstrated to increase productivity by an order of magnitude, across a range from 200 to 2 000 Bbls/d in a single well. He concludes that pore throat restriction from solid particle precipitation is the dominant damage mechanism from 'natural' cooling and to a lesser extent solubility changes due to gas liberation near the wellbore. Of particular interest, it is estimated that precipitated solid paraffin particles travel an average distance in the order of 2 ft within the reservoir implying that particles that form farther away than 20 ft from the wellbore do not contribute significantly to induced skin damage.