Selective Acid Stimulation To Improve Vertical Efficiency in Injection Wells - A Case History
- C.W. Ellenberger (Standard Oil Co. of California) | R.J. Aseltine (Standard Oil Co. of California)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1977
- Document Type
- Journal Paper
- 25 - 29
- 1977. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.4.1 Waterflooding, 1.14 Casing and Cementing, 1.8 Formation Damage, 5.6.5 Tracers, 6.5.2 Water use, produced water discharge and disposal, 2.4.3 Sand/Solids Control, 4.2.3 Materials and Corrosion, 5.1.1 Exploration, Development, Structural Geology, 3.2.4 Acidising, 2.2.2 Perforating
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Vertical efficiency in three Los Angeles Basin waterfloods was significantly improved using selective stimulation of water-injection wells with moderate amounts of HCl-HF acid. Case histories of four injection wells are presented and the stimulation techniques are discussed.
The economic success of a waterflood in a multilayered reservoir is dependent on good vertical efficiency in the injection wells. Ideal vertical efficiency is indicated by injection profiles that result in the optimum amount of water being injected into each sand layer. For various reasons, injection profiles are often less than ideal.
This paper discusses four case histories of profile improvement in water-injection wells using selective acid stimulation techniques. Each well discussed had plugged perforations or formation damage preventing injection perforations or formation damage preventing injection into most of the interval open to injection. Removal of the damage by use of selective acid placement techniques resulted in improvement of injection profiles and an increase in total injectivity for each well.
Reservoir Characteristics and Well Conditions
The injection wells are in three different reservoirs in the western part of the Los Angeles Basin. The wells were chosen to test the selective stimulation techniques because of their poor injection profiles, Gross intervals open to injection ranged from 400 to 1,400 ft. All the wells had cemented casing that was jet perforated in the injection intervals.
Each reservoir is composed of interbedded sand and shale intervals that are, for the most part, continuous across the fields. The shale intervals are believed to prevent major crossflow within the formation. prevent major crossflow within the formation. Discounting permeability variations, the conditions make the reservoirs attractive for waterflooding.
Analysis of the mineral composition (Table 1) of the sand shows quartz and feldspars predominating. Clays are present in quantities up to 11.7 percent by weight of the total rock composition. Montmorillonite is present in quantities up to 1.0 percent. Mica is present in each reservoir in quantities up to 9 percent. Other clay minerals exist in lesser amounts. The wells chosen for the selective stimulation treatments exhibited low injectivity and poor profiles. In all four cases, 40 percent or more of the total injection rate was being injected into a single zone. In all cases, certain zones open to injection were taking no water (see Table 2). Low injectivity and poor profiles were believed to be a result of plugging by solids profiles were believed to be a result of plugging by solids suspended in the injection water, formation clay swelling caused by fresh injection water, completion damage, or ineffective perforations.
Injection water was obtained from various sources. Pool A used fresh water containing less than 15 ppm Pool A used fresh water containing less than 15 ppm suspended solids, with particles larger than 2 microns amounting to only 10 percent of the total. Pool B used water similar to that of Pool A until July 1975, followed by injection of filtered produced water with less than 5 ppm oil and 5 ppm suspended solids, with only 10 percent ppm oil and 5 ppm suspended solids, with only 10 percent of the particles larger than 2 microns. Pool C used unfiltered produced water with an average of 80 ppm oil and 50 ppm suspended solids, with 15 percent of the particles larger than 2 microns. The produced water used in Pools B and C is a mixture of waters from many zones and differs from the water originally present in each pool.
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