Silicate Foam Wellbore Insulation

Abstract

When liquid sodium silicate boils, it forms a rigid foam on the heated surface. It is an effective and relatively inexpensive means of insulating steam-injection wells, and might also be useful for preventing paraffin deposition and hydrate formation. Introduction Thermally induced stress that causes casing failure has been a problem in oilfield steam-injection operations for a little more than a decade. Heat transfer in a well has been described analytically, and a number of methods have been devised to reduce wellbore heat losses so that lower casing temperatures can be maintained and higher steam qualities attained at the sand face of a reservoir. The methods include using insulated tubing, pumping a low-thermal-conductivity liquid into the annulus, and coating the tubing with aluminum paint. Insulated tubing is expensive and economics in many instances do not justify its use. Low-thermal-conductivity fluids when placed in a packed-off annulus and subjected to high temperatures packed-off annulus and subjected to high temperatures may gravity segregate, solidify, or become so viscous that the removal of a packer and injection tubing is often difficult. The primary draw-back to the use of aluminum-painted tubing is that it is difficult to prevent oil or other high-emissivity materials from prevent oil or other high-emissivity materials from clinging to its low-emissivity surface when it is being handled and lowered into the well. Such high-emissivity materials destroy its thermal effectiveness. A new insulating material is now available and a technique for its use in steam-injection wells has been developed. The insulating material, silicate foam, is formed by boiling a sodium silicate solution. The foam is an excellent insulator, having a thermal conductivity of approximately 0.017 Btu/hr-ft. degrees F. Fig. 1 is a photograph of the foam's structure. Its physical properties are given in Table 1. The Insulation Process In a field operation, a solution of sodium silicate is placed in a packed-off annulus, and then steam is placed in a packed-off annulus, and then steam is injected down the tubing. The hot tubing causes the silicate solution to boil, leaving a coating of insulating foam, usually about 1/4 to 1/2 in. thick, on the hot tubing surface. Since the foam immediately becomes an effective insulation, none is deposited on the inner wag of the casing. Silicate solution that remains in the annulus after steaming for several hours is removed from the annulus by displacing it with water (if the solution is not removed, it may solidify in the annulus). The water is removed by gas-lifting or swabbing. Fig. 2 is a schematic showing steps of the insulation process. Once the insulation is formed, heat loss is reduced and lower casing temperatures and higher sand-face steam qualities are the result. A comparison showing the foam's effectiveness is presented in Fig. 3, which illustrates the calculated maximum casing temperature in a well with packed-off tubing. The three cases show the relationship between casing temperature and steam-injection time for uninsulated tubing, commercially available insulated tubing, and tubing with a 1/4-in.-thick coating of silicate foam. The calculated casing temperatures are considerably lower for the insulated cases; however, there is not a great deal of difference between the two insulated cases. JPT P. 583

Gelatinous Oil-Base Fluids as Insulators in Geothermal and Oil-Recovery Applications

“…Sodium silicate and calcium silicate foams as used in industry provide insulation in steam injection projects. The thermal conductivity coefficient of sodium silicate foam has been reported as 0.017 Btu/hr-ft-OF (7). No value was located in literature for calcium silicate foam.…”

“…The insulation of wellbores to reduce heat transfer between the tubing, casing and the wellbore has been done through numerous techniques. Some of these procedures involve 1) utilization of insulated tubing (1 -6); 2) placement of insulating materials (silicate and urethane foams) in the annular space between the wellbore and the tubing string (3)(4)(5)(7)(8)(9)(10); 3) pumping into the annulus a low thermal conductivity liquid (11) and 4) packing the annulus with a heat-activated gel-forming fluid (12)(13)(14).…”

New Trend in Oilfield Flow-Assurance Management: A Review of Thermal Insulating Fluids

“…Much of the early attention was focused on steam-injection operations (Penberthy and Bayless 1974;Eisenhawer et al 1981;Aeschliman et al 1983). Many applications were designed to provide insulation through inert gas-filled packer annulus.…”

High-Performance Water-Based Insulating Packer Fluids

“…Originating with enhanced oil recovery (EOR) by utilization of steam injection processes as well as hot water flooding, the transfer of heat to outer annuli has always been problematic and greater than expected even in inert gas filled annuli. [3][4][5][6][7][8] In such cases, wellbore refluxing, vaporization of water at the thermally elevated bottom hole temperature (BHT), and condensation in the aged sections of the annular space resulted in dramatic heat losses in which the insulated sections provided only 30% decreases in heat transfer versus the non-insulated regions.…”