Design Techniques for Chemical Fracture-Squeeze Treatments
- John M. Tinsley (Halliburton Co.) | R.M. Lasater (Halliburton Co.) | John A. Knox (Halliburton Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1967
- Document Type
- Journal Paper
- 1,493 - 1,499
- 1967. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 3.1.6 Gas Lift, 4.1.2 Separation and Treating, 4.3.4 Scale, 4.6 Natural Gas, 2.4.3 Sand/Solids Control, 4.2.3 Materials and Corrosion, 1.8 Formation Damage, 3 Production and Well Operations, 6.5.5 Oil and Chemical Spills
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Chemical squeeze treatments have been used to provide temporary relief from certain production problems. The chemical fracture-squeeze technique, combining the effects of a fracturing treatment and a squeeze operation, has been more successful than conventional squeeze operations. Knowledge derived from well stimulation and reservoir engineering research provides a means for predicting the theoretical effective life of such a treatment. Analysis of theoretical equations and concepts developed allows selection of improved treatment techniques based on specific formation conditions. Theory used in this analysis was developed as an extension of previous electrical model studies made to establish the expected flow and pressure profiles adjacent to a fracture system.
The chemical fracture-squeeze technique can be utilized in the economic application of corrosion inhibitors, emulsion breakers and paraffin and scale inhibitors. Application of this technique is shown to be effective. The slow return rate of injected chemicals, controlled by the resultant flow profiles and treatment variables, permits extended periods of chemical effectiveness. Results of field treatments are given, showing that the concepts outlined above for chemical fracture-squeeze treatments are valid and that applying this technique can help alleviate many current production problems.
Much progress has been made in the last 10 to 15 years in developing chemicals for use in stimulating wells, maintaining production and protecting well equipment from damage due to corrosion. Not too many years ago, some wells seemed to dry up or wear out. In many cases the wells were produced as long as possible without any attempt at maintaining productivity. Even with the advent of new and better stimulation techniques, a rapid decline in production was observed. Methods of removing and, in some instances, preventing damage have been developed. Among those factors responsible for uneconomical production are scale, paraffin, corrosion, bacteria, water blocks and emulsions.
Soluble scale-prevention chemicals have been developed that can be placed in a formation along with fracturing sand. As the water produces back across this bed, the solid material dissolves slowly and can provide longterm protection from scale. However, bottom-hole temperature and salinity of produced water vary widely and both these factors influence the rate of solubility. Scale inhibitor composition is also a controlling factor. Some of the solid material may be crushed, increasing the surface area exposed to water and increasing the rate at which it dissolves. Some of the material may never be contacted by water and can be lost. However, this type of treatment has been very successful in many instances and has helped maintain economical production for extended periods of time.
Liquid scale inhibitors, which are more widely applicable and more stable, have been developed in recent years; however, because they are liquids, their use has been restricted to treatment down the annulus, using metering pumps to provide proper concentrations in the produced fluid. This has prevented use in wells containing packers, in dually completed wells and in gas-lift and flowing wells. Wells that operate with an open annulus may also experience severe corrosion problems due to introduction of oxygen.
Corrosion inhibitors have been developed that can be fractured into a well as particulate solids to be slowly dissolved in the produced fluid. These materials are not usually effective in wells with a bottom-hole temperature in excess of 120F since solubility rate may be too fast if that temperature is exceeded or if aromatic content of the oils is unusually high.
Corrosion inhibitors have been developed that can be fractured into a well for long-term feedback, but development of a material with proper solubility or feed rate has been difficult. Corrosion inhibitors are available in many different forms. Liquids have been lubricated down the annulus or sticks or pellets dropped down tubing. Inhibitor squeeze treatments developed a few years ago led to development of inhibitors with particularly strong film-forming properties. This technique basically involves displacing a highly concentrated solution of the inhibitor into the formation through the tubing. Kerver and Hanson studied the adsorption properties of inhibitors on various types of formations. They showed that, even though the inhibitor was displaced radially into the true permeability, it could be produced back for a long period of time because of slow desorption from the rock. Methods developed for monitoring the return of these inhibitors generally have established 1 to 6 months as the effective limit before retreatment is necessary. Inhibitors displaced into the interstices of the formation sometimes cause emulsions that either hamper production or cause treating problems on the surface.
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