Formate-Based Reservoir-Drilling Fluid Meets High-Temperature Challenges

Abstract

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 98347, "Formate-Based Reservoir-Drilling Fluid Resolves High-Temperature Challenges in the Natuna Sea," by R.J. Bradshaw, SPE, R.M. Hodge, SPE, and N.O. Wolf, SPE, ConocoPhillips Co., and D.A. Knox, SPE, C.E. Hudson, SPE, and E. Evans, SPE, M-I Swaco, prepared for the 2006 SPE International Symposium and Exhibition on Formation Damage Control, Lafayette, Louisiana, 15–17 February. In the Belank field, reservoir temperatures average 315°F and reservoir sections are 3,500 to 4,500 ft drilled horizontally. A low-solids, brine-based reservoir drilling fluid was required because the wells use premium screens for sand control. Six wells were drilled with the sodium formate-based reservoir-drilling and completion fluids. The particle-size distribution and concentration of the calcium carbonate (CaCO3) bridging solids were monitored closely while drilling to ensure that filter-cake quality was not compromised. Introduction The Belanak field is an oil-producing field off the coast of Indonesia. Reservoir temperatures average approximately 315°F. Six horizontal-well completions were planned from the Belanak A platform. A water-based drilling fluid was selected for drilling the 8 1/2-in. horizontal reservoir sections, some as long as 4,500 ft and many with tortuous well paths. The bottomhole temperature (BHT) exceeded the temperature range of conventional water-based reservoir-drilling-fluid components. In addition, the remoteness of the platform from the supply base and the limited supply of drill water at the supply base were major issues. As a result, laboratory work on the drilling-fluid design had to consider supply-chain limitations as well as the technical issues that usually dominate fluid design. Fluid design focused on the following.Developing a drilling fluid that would be stable under long-term exposure to temperatures as high as 315°F.Determining the minimum concentration of CaCO3 bridging agent required to generate a clean, treatable filter cake without compromising filter-cake quality.Identifying a suitable scale inhibitor to prevent precipitation-related formation damage if the limited water supply forced the completion brine and drilling fluid to be mixed with seawater instead of drill water. Laboratory Testing Base-Fluid Selection. Discussion between the operator and fluids provider resulted in agreement that the fluid formulation not only should be compatible with the sandscreen completion, but also maintain fluid-loss-control and rheological properties for a minimum of 48 hours' exposure to BHT. Both water-based and nonaqueous-based formulations were considered. Use of natural polymers, such as xanthan gum and starch, for fluid-loss control and viscosity was considered advantageous because of the ability to remove them chemically once the well was completed. However, drilling fluids made with xanthan and starch can begin to exhibit property degradation from prolonged exposure to temperatures greater than 250°F. The required density was determined to be 9.8 to 10.5 lbm/gal. Three base fluids were tested: potassium chloride, sodium chloride, and sodium formate. These brines were selected for economic viability, ease of logistics, and in the case of sodium formate, technical performance.