Annular Packer Fluids for Paraffin Control: Model Study and Successful Field Application

Abstract

Summary This paper covers the evolution, full-scale model study, and field application of gelled packer fluids for paraffin control in naturally flowing wells. Field application of these insulating packer fluids has resulted in significant increases in the flowing tubing temperature in the seven wells treated to date. The temperature increases from gelled-packer-fluid application alone have eliminated paraffin problems previously controlled with repeated hot-oil treatments. Before this previously controlled with repeated hot-oil treatments. Before this application, chemical inhibition attempts were unsuccessful. The gelled fluid currently used is based on a phosphate ester and sodium aluminate reaction that produces an aluminum phosphate ester association polymer. The gellant is commonly used in oil-based fracturing fluids. polymer. The gellant is commonly used in oil-based fracturing fluids. Introduction The Lisburne formation is a carbonate reservoir that underlies the Sadlerochit sandstone reservoir in the Prudhoe Bay field of Alaska's North Slope. Some low-rate wells in the field have experienced paraffin deposition inside the production string as the crude passes through the permafrost located across the upper 2,200 ft [671 m] of the wellbore (Fig. 1). Temperature logs run on problem wells showed that chemical inhibition had not been effective problem wells showed that chemical inhibition had not been effective because the oil had cooled below the cloud point by the time it reached the chemical injection ports (2,200 ft [671 m]). Paraffin problems were typically treated with hot-oil displacements of diesel or lease crude down the production tubing, with some wells requiring treatments two to three times per month. The need for a longer-lasting paraffin remedy, combined with concerns about the potential for formation damage from overdisplacing a hot-oil treatment, prompted the evaluation of other paraffin-control methods. Most common paraffin control techniques were found to be either unsuitable in the arctic environment or more expensive than continued hot oiling. A literature search suggested that application of gelled fluids similar to those used as insulation in surface casing could be a solution. Free convection has been shown to be a significant heat-loss mechanism in wells completed with typical nongelled annular fluid. Earlier in-house research suggested that gelation of fluids could effectively stop free annular convection, thus reducing heat loss to the formation. Internal yield strengths required to inhibit free convection were found to be relatively low. Gelled packer fluid was first applied in a well originally completed with solids-laden gel in the tubing/casing annulus during May 1985 (Table 1, Well 1). The relatively-low-gel-strength diesel-bed fluid contained organophilic bentonite, an ionizer for the clay, and an emulsifier. Because no pretreatment data were available from this well, additional information was needed to compare treatment effectiveness directly. A controlled field test with solids-free gel was performed on a well with stable production (Table 1, Well 2). Solids-free gel was chosen for this test to prevent the solids from settling out and possibly complicating future recompletion. A commonly available gelled-diesel fracturing fluid was chosen for the solids-free test. The gel was mixed to give a Fann VG35 10-second gel strength of about 32 lbf/100 ft2 [15 Pa] measured at 80 degrees F [27 degrees F]. This first solids-free gelled-packer-fluid job was pumped in June 1987 (Table 1, Well 2). Within 24 hours, the flowing tubing temperature increased 25 degrees F [14 degrees C], from 81 to 106 degrees F [27 to 41 degrees C], where it stabilized (Fig. 2). Temperature logs run just before and after the treatment verified the 0.5 degrees F/100-ft [0.9 degrees C/100-m] change in thermal gradient with the gelled packer fluid in place (Fig. 3). Subsequent computer modeling of this first field test indicated that the temperature effects could be matched best by treating the gel as a solid with a thermal conductivity some-what in excess of convection-free gelled diesel. This confirmed the inhibition of convection in the annulus. With the success of the initial field test, a wellbore model was constructed to screen other less costly and easier-to-handle fluids and to identify the minimum gel strength required to inhibit free annular convection. The fluids tested in the model were evaluated for insulating effectiveness, stability, compatibility with tubulars and corrosion inhibitors, ease of mixing and handling, formation-damage potential, availability, and cost.