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

Studies have indicated resources of 4.6 trillion barrels of heavy oil, and some have expressed a need of novel methods to recover some of this oil. Thermal methods were the vogue twenty years ago, with only one method, steam injection, surviving to a significant extent. This paper describes economic uses of hydrogen peroxide, which is similar to steam injection but with some advantages. Hydrogen peroxide can generate 100% quality steam insitu in concentrations above 25–30%. Lesser concentrations can generate or propagate steam banks and hot water banks. Two uses of hydrogen peroxide are economic-short term stimulation in selected reservoirs, and formation damage repair. Other uses involving heat bank flooding await cost reductions that may occur due to more use and technical advances in the manufacture of hydrogen peroxide. Introduction Hydrogen peroxide is a relatively stable combination of hydrogen and oxygen, made by a chemical process discovered 50 years ago. Physical properties are listed in Table 1. A small amount of hydrogen is required to manufacture 50% concentration, i.e, about 3% by weight. The main uses of hydrogen peroxide are in chemical processes and paper manufacture. Hydrogen peroxide can be decomposed very rapidly over a platinum screen giving off heat, oxygen, and water. Thus if hydrogen peroxide is injected into a reservoir sand, it will decompose slowly giving off heat and oxygen, then the oxygen will react with residual oil to generate more heat and carbon dioxide. Decomposition is exponential with temperature and pH increase. This process has been reported on in a paper by Moss, et. al. Thirty per cent concentration will generate 1200 BTU/lb (100%+ quality steam) with about 1/3 of the heat coming from decomposition and 2/3 coming from reaction with oil. Thus hydrogen peroxide can be used in a variety of ways to recover oil. In addition it is well known that steam stimulation can result in formation clean-up in the vicinity of the well. Thus 50% hydrogen peroxide can generate up to 2000 F. which can repair formation damage. Economic uses Stimulation. Injection of hydrogen peroxide can be economic if the heat is kept near the well-bore. The heat content of a barrel of 50% peroxide can heat up to 48 barrels of oil to 100 F. above the reservoir temperature. Thus small treatments can be effective if allowing a long soak time to moderate the temperature. A study by Niko and Troost has shown that near well bore heating is effective in depletion reservoirs. Oil recovery was independent of soak time and small slugs were superior for early production. The paper by Briggs, et.al. shows that production from steam stimulation in gravity drainage reservoirs does not decline with each successive cycle as much as massive treatments do in other reservoirs. Thus small treatments will be more effective in heat utilization than massive treatments where much of the oil is forced away from the well, and much of the heat injected is lost. Formation Damage Repair. As mentioned previously, steam stimulation can clean up a well. This may be due to wax and asphalt deposits being melted. In addition to these effects, 50% peroxide can generate up to 2000 F. a foot or so away from the well. Thus after treatment, heat conduction will treat the entire well bore vicinity to at least 1000 F. This temperature can cause clay to shrink, destroy carbonates, and vaporize emulsions. Peroxide treatment can be more effective than other treatments such as with acids and solvents, since these liquids can finger through. Peroxide decomposition causes a finger resistant foam of oxygen bubbles in hot water, and heat conduction to untreated areas gives 100% zonal coverage. Gas wells can be treated with pre-injection of a fuel oil. Flooding with Hydrogen Peroxide As with steam, a variety of heat floods can be achieved with hydrogen peroxide. P. 117^

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