Pseudolimited Entry: A Sand Fracturing Technique for Simultaneous Treatment of Multiple Pays
- Louis C. Stipp (Tenneco Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1968
- Document Type
- Journal Paper
- 457 - 462
- 1968. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 2.2.2 Perforating, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating
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Tenneco Oil Co. has used the pseudolimited entry technique to simultaneously and effectively sand-water fracture the multiple, hard, tight Dakota gas pays in the San Juan basin. Application of this technique involves (1) the use of ball sealers to insure that a satisfactory number of perforations are open prior to fracturing, (2) employment of a low (approximately 300 psi) perforation differential to insure simultaneous, effective stimulation of all perforated pays of approximately equal fracturing pressure and (3) the use of bridge plugs when necessary to insure stimulation of zones having significantly different fracturing pressures.
The use of the pseudolimited entry technique essentially has eliminated sand-outs, poor treatment coverage and other problems associated with other fracturing techniques. As of March, 1966, the absolute open flow potentials (AOFP) of the nine wells completed by this method averaged over 4,000 Mcf/D or 78 percent above those AOFP's of conventionally treated offset wells. Constantrate pressure drawdown testing' also has supported the results attained.
The results and continued use of this technique have proved it to be an effective method for stimulating the Dakota pays of Northwest New Mexico.
Fracturing multiple pays with conventional techniques (densely perforated zones, treatment control through the use of bridge plugs or ball sealers) can result in expensive or marginal completions. Fracturing the Dakota formation in the San Juan basin with conventional methods offers few exceptions to this.
The Dakota formation in the San Juan basin is approximately 200 to 300 ft thick. As shown by Fig. 1, it often is composed of multiple, hard, low-porosity, gas- bearing sands separated by shale. At a given location, the lower Dakota usually is composed of a series of sands of approximately equal fracturing pressures. These pressures often vary markedly between locations. The middle and upper Dakota sands are less numerous. They have approximately equal fracturing pressures significantly different from those of the lower sands; those of the middle and upper sands also can vary over a short distance. Fracturing pressures of all the Dakota sands are difficult to predict quantitatively.
The Dakota frequently is sand-water fractured with conventional multistage treatments, employing bridge plugs or ball sealers for treatment control and diversion. Normally, the amount of propping agent used is between 50,000 and 100,000 lb of sand. Treating rates usually are between 35 and 50 bbl/minute. In many cases individual sands will be perforated with so many holes that the treatment will be accepted into the sand that has the lowest fracturing pressure.
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