Use of an Insulating Fluid f or Casing Protection During Steam Injection

Abstract

Abstract Laboratory and field experiments are described which define casing temperatures when high-temperature steam or hot water is injected down tubing with a particular well completion fluid in the tubing-casing annulus. Also discussed is the method used to place and contain this completion material. Field results observed following stimulation of a production well with 646F steam verified laboratory data that indicated thermal deterioration of one well completion fluid. Thermal deterioration in the 15-day field test was sufficient to destroy insulating properties of the fluid tested. By using an insulating fluid in the tubing-casing annulus casing damage can be prevented in wells not adequately completed for thermal stimulation treatments. Introduction High-pressure steam injection frequently causes casing failure in wells completed with J-55 short-thread casing. Failures generally are identified by joint pullout or fracture occurring as the wellbore cools after steam injection. Tensile failures are the result of casing deformation when temperature- generated compressive forces exceed the yield strength of the casing steel. Preventing casing damage in injection or production wells completed with J-55 ST and C, 8-rd casing requires reducing the casing temperature and/or the thermally induced compressive forces. There are many ways to reduce casing temperature while steam is injected down the tubing. A common method is to set injection tubing on a packer to isolate the casing from the injected fluid. This technique has been used successfully to protect casing when injection temperatures are 500F or less. Few failures have occurred under these conditions because resulting casing temperatures did not exceed the temperature at which casing steel yields when fully constrained. At tubing temperatures above 500F the low-pressure annulus is not positive protection against casing failure. This is shown in Fig. 1, which compares the relative failure risk for J-55 ST and C wells when steam at temperatures of 400 to 650F is injected down tubing set on a packer in 7-in. casing. The risk of failure is high as injection temperatures approach 650F. Several instances of casing failure have been observed under these conditions. The alternatives to a low-pressure annulus can be divided into two categories: mechanical insulation attached to the injection tubing, and an insulating fluid to fill the entire annulus between the tubing and the casing. This article discusses the use of an insulating fluid for casing protection.