Field Performance of a Liquid Scale Inhibitor Squeeze Program
- Dennis M. Spriggs (Amoco Production Co.) | G.W. Hover (Amoco Production Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1972
- Document Type
- Journal Paper
- 812 - 816
- 1972. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 4.3.4 Scale, 3 Production and Well Operations, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.10 Drilling Equipment, 4.2.3 Materials and Corrosion, 5.4.1 Waterflooding
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Although much has been written on the theory of preventing scale deposition, little in the way of field experience has been published. The production performance of the West Texas wells discussed here indicates that the inhibitor squeeze program has been effective in preventing scale buildup on the formation. preventing scale buildup on the formation. Introduction
Scale in producing oil wells is a recognized problem in the oil field. This problem is magnified in waterflood areas where volumes of water produced are increased over primary levels. A great deal of progress has been made in scale mitigation products in recent years. Much has been published about the theory of preventing scale deposition and the process of squeeze treating (see References). Only a few case histories are available, however, on long-term, successful programs of squeeze-treating producing oil wells with a liquid scale inhibitor.
The data presented here have been obtained from a long-term program of squeeze-treating producing oil wells with a liquid scale inhibitor on two West Texas waterfloods that produce from the Grayburg formation (dolomite) in the Foster field, Ector County, Tex.
The development of the scale inhibitor program that is presently used in the Foster-South Cowden Coop Area and the South Foster Unit in the Foster field began in late 1967, when a solution was being sought for the problem of scale deposition in producing oil wells. This scale deposition was producing oil wells. This scale deposition was causing severe wellbore damage. Scale removal workovers had demonstrated only short-lived successes, and scale had been identified on both down-hole equipment and in returns during cleanout operations on wells in the area. The scale was composed of calcium sulfate and calcium carbonate, with most of it being calcium sulfate. The inhibitor program developed was designed to prevent the growth of these types of scale.
Selection of Scale Inhibitor Type
There are two types of scale inhibitors that can be used for applications of this nature: liquid scale inhibitors and solid scale inhibitors. Solid scale inhibitors were quite popular at one time, but, for several reasons, liquid inhibitors have received total acceptance for this program. Solid inhibitors must either be placed during fracturing or be dumped into the wellbore and allowed to dissolve slowly. Fracture stimulating a well each time a new treatment of scale inhibitor is needed is not economically attractive because it necessitates an expensive stimulation every 1 to 2 years. Dumping the solid inhibitors into the wellbore is not adequate since it does not insure that the inhibitor will properly contact the produced fluids. Liquid inhibitors, on the other hand, are quite flexible and easier to handle.
Another important drawback to the use of solid scale inhibitors is that they are usually of the polyphosphate type and subject to chemical reversion. polyphosphate type and subject to chemical reversion. Improper placement of a solid polyphosphate inhibitor or a change in produced fluid volumes during the treatment could result in overtreatment. This over-treatment can cause the polyphosphates to revert to an orthophosphate which, if precipitated into a scale, is harder to remove than the carbonate and sulphate scales for which the wells were treated to begin with.
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