Inhibitors squeeze treatment

E. J. Mackay and K. S. Sorbie. Modelling scale inhibitor squeeze treatments in high crossflow horizontal wells. J Can Petrol Technol, 39(10) 47-51, October 1998. 

Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment," J. Pet. Technol.. June 1985, 1019-1034. 

Nasr-El-Din, H. A., Rosser, H. R. and Al-Jawfi, M. S., 2000. Formation Damage Resulting from Biocide/Corrosion Inhibitor Squeeze Treatments, SPE paper 58803 presented at the 2000 SPE International Symposium on Formation Damage held in Layette, LA 23 - 24 February, 2000. 

M. M. Jordan, K. S. Sorbie, P. Chen, P. Armitage, P. Hammond, and K. Taylor. The design of polymer and phosphonate scale inhibitor precipitation treatments and the importance of precipitate solubility in extending squeeze lifetime. In Proceedings Volume, pages 641-651. SPE Oilfield Chem Int Symp (Houston, TX, 2/18-2/21), 1997. 

Near-well treatments, in which chemicals are injected into producing and sometimes injector wells, where they are intended to react with the reservoir rock. Well stimulation techniques such as acidization, for example, are intended to increase the formation s permeability. Alternatively, producing wells may receive squeeze treatments in which a mineral scale inhibitor is injected into the formation. In this case, the treatment is designed so that the inhibitor sorbs onto mineral surfaces, where it can gradually desorb into the formation water during production. 

Sulfate scaling poses a special problem in oil fields of the North Sea (e.g., Todd and Yuan, 1990, 1992 Yuan et al., 1994), where formation fluids are notably rich in barium and strontium. The scale can reduce permeability in the formation, clog the wellbore and production tubing, and cause safety equipment (such as pressure release valves) to malfunction. To try to prevent scale from forming, reservoir engineers use chemical inhibitors such as phosphonate (a family of organic phosphorus compounds) in squeeze treatments, as described in the introduction to this chapter. 

Sorbie, K. S., M. Yuan and M. M. Jordan, 1994, Application of a scale inhibitor squeeze model to improve field squeeze treatment design (SPE paper 28885). European Petroleum Conference Proceedings Volume (vol. 2 of 2), Society of Petroleum Engineers, Richardson, TX, pp. 179-191. 

The Squeeze treatment is a method of continuously feeding an inhibitor into an oil or gas well. A quantity of the inhibitor is pumped into a well and is followed by sufficient solvent to force the inhibitor into the formation or to mix the inhibitor in oil, aromatic solvent, or water at the proper ratio, and then to pump the mix into the tubing and displace it to the bottom, followed by sufficient fluid to overdisplace the mixture into the formation by 3500 to 11,500 L. The inhibitor is absorbed by the formation from which it slowly escapes to inhibit the produced fluids. Protection applied in this manner has been known to last for a year (Li et al. 2006). 

Squeeze treatment A method of continuous feeding an inhibitor in an oil well by pumping a quantity of inhibitor into the well. The inhibitor is absorbed by the formation from which it slowly escapes to inhibit the produced fluids. 

Sometimes a short batch is forced down with a nitrogen displacement or compressed gas to speed up the fall rate and reduce shut-in time. An inhibitor squeeze is sometimes used to try to get a longer return time and simulate a continuous treatment. However, there is always the concern of formation damage with squeezes and with tubing displacements. 

Squeeze treatments with a calcium carbonate scale inhibitor may be accomplished separately from acidizing. They may be recommended following acid treatment or acid cleanup of the formation. 

Volatilization has already been discussed under vapor phase inhibitors in connection with boilers and closed containers. Another application is the inhibition of gas condensate corrosion. However, the treatment here is essentially the same as used in batch or squeeze treatments. 

Wells with low bottom-hole pressure cannot withstand the hydrostatic head. They can be treated the same as above, however, except the inhibitor-diluent mix is atomized with nitrogen and then displaced and over-displaced with nitrogen. Squeeze treatment with nitrogen is costly because of the equipment required. It may be possible to use high-pressure natural gas for the squeeze instead of expensive nitrogen. 

Uses Dispersant, fluid loss control aid, scale inhibitor, aids cuttings suspension, removal from the hole for oil field applies. scale inhibitor for production squeeze treatments... 

Protection of production tubing requires that the inhibitor be squeezed, added continuously, or have film persistency so that batch treatment is feasible. Shear stresses impose the same requirements on inhibitors to withstand velocity effects. The tubing will be wetted more completely on the low side... 

If a chemical string is not feasible, batch treatments using persistent film inhibitors may be used. The inhibitor is designed to form a tough film that is not too soluble in the production stream so it will last for a sufficient time between treatments. The batch may be displaced with liquids, gas, or nitrogen. Squeeze inhibitors must be designed to be stable in the formation, and not cause severe emulsion problems. The adsorption characteristics should be controlled for proper feedback of the inhibitor. Pumped wells, can be treated by continuous addition or batching down the annulus. 

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