Ball sealers

Onset of the diversion stage (27.4 m3), with the skin now increasing due to the closure of some perforations by ball sealers (the rest of the curve would have shown that the relative skin value reached -2.5 at the end of the diversion stage). 

An effective acid diversion technique is needed to overcome uneven acid distribution and obtain good sweep efficiency during stimulation. Mechanical and chemical means are available for acid diversion. Mechanical means include straddle packers and ball sealers, however, they have limited use in openhole, gravel packed and slotted liner completions and are normally expensive [66]. Chemical means can be used in cased and openhole wells. The type of chemical diversion technique depends on the lithology and other reservoir characteristics (temperature, salinity, and hydrogen sulfide content). In carbonate reservoirs, emulsified acids [J6] and viscosity controlled acids [67] have been used to improve sweep... 

Temporary skin (r)— by creating temporary local skin in portions of the interval that have already been acidized, with ball sealers or stages of solid chemical diverters. 

They are not necessarily stand-alone methods, as coiled-tubing injection and ball sealers can be combined with isolation packer systems. 

Ball sealers. A popular mechanical diversion method is the use of ball sealers. Ball sealers are not an entirely reliable method of diversion. However, under the right conditions, they may provide the most effective diversion available. Ball sealers were introduced in the mid-1950s. They are just what the name implies— balls that are pumped in an acidizing treatment, intended to seat on perforations to create a temporary seal. The add is thereby diverted to other perforations as the treatment progresses. 

Ball sealers are added to treatment fluids with special equipment (a ball gun) when diversion is needed. Balls are removed from perforations at the end of a treatment, once injection is terminated and pressure in the wellbore drops, allowing the ball sealers to fall out of perforations. Balls either flow back during production and are collected or drop into the well rathole. 

Ball sealers are most effective in newer wells with a limited number of perforations. In older wells with damaged or compromised perforations or with a large perforation density (more than four shots per foot), the effectiveness of ball sealer is reduced. Also, ball sealers are effective only when casing is well cemented and no vertical channeling will occur behind pipe during acid injection. Similarly, channels from the perforations into the formation, such as conductive natural fractures, will reduce the effectiveness of ball sealers. 

Furthermore, the nature of the perforations has an effect on the efficiency of ball sealing. The more smooth and symmetrical a perforation is, the better the ball sealer will seat and create diversion—or the better will be the ball action, as it is called. The more irregular a perforation is, the less chance it will have of being adequately sealed. Still, a significant amount of leakage will enable diversion, albeit less efficiently. Unfortunately, the quality of perforations in this regard is not often known. 

Ball sealer diameters typically range from Vs" to l /4", although more than 90% of balls pumped today are %" in diameter. Newer ball guns are designed to deliver the ys"-diameter balls, which have the broadest application with respect to perforation diameters and injection tubing sizes. The rule of thumb for selecting ball size to achieve an adequate seal is that the ball diameter should be about 1.25 times the perforation diameter. 

Other factors to consider in the use of ball sealers are as follows ... 

Injection string diameter should be at least three times the ball sealer diameter. Therefore, it is best to pump an acid treatment through tubing at least 2%" in diameter. 

The minimum injection rate also depends on the ball density relative to the acid. Ball densities typically vary from about 0.9 specific gravity (s.g.) to about 1.4 s.g. Ball sealers with densities less than 1.0 s.g. are called buoyant hall sealers ot floaters. Newer ball sealer products are of the floater or neutral density variety. The concept was developed at Exxon. Ball sealers with specific gravities greater than water or acid (>1.1 s.g.) are called sinkers for obvious reasons. Older ball sealers are of the sinker variety. 

An important consideration in selecting the proper ball sealer is the settling velocity of the ball in the carrying fluid. The settling velocity of a ball sealer in a Newtonian fluid can be defined as follows ... 

Settling rate in 15% HCl, for example, can vary from about 24 feet per minute (ft/min) for a 1.1 s.g. ball to almost 90 ft/min for a 1.4 s.g. ball. For buoyant ball sealers, or floaters, the settling rate will be negative— meaning that the ball will rise, rather than sink or settle. In 15% HCl, a 0.9 s.g. ball will have a rise rate of about 65 ft/min, while the rise rate of a 1.0 s.g. ball would be about 42 ft/min. One benefit of using floaters is that the rise rate can usually be easily overcome. For example, in 2%" tubing, the velocity of acid movement at 1 bpm is 173 ft/min (5.615 cubic feet per minute divided... 

Ball sealers are available in different materials, but usually of a rubber type. Rubber-coated neoprene (RCN) is the most common. Selection depends on density and temperature limit requirements. 

Gabriel, G. A., and S. R. Erbstoesser. 1984. The design of buoyant ball sealer treatment. Paper SPE 13085, presented at the Society of Petroleum Engineers Annual Technical Conference and Exhibition, Houston. 

New water-soluble perforation ball sealers provide enhanced diversion in well completions. Paper SPE 49099, presented at the Society of Petroleum Engineers Annual Conference and Exhibition, New Orleans, LA, 27-30 September. 

Diverter choices are also limited. Ball sealers are usually not effective in horizontal wells, because they tend to the bottom side of the pipe. Foam diversion can be effective, to some extent. In any case, it is known that any attempt to divert acid fluids with a nondamaging diverter is better than no diversion at all. 

Remember that the need for deep penetration is often overrated. Most conventional acidizing treatments with some degree of retardation or fluid-loss control (viscosity), using ball sealers for diversion, can effectively bjqjass formation damage within several feet of the wellbore. In any case, simpler acid systems are preferable. 

The most effective diversion method in fracture acidizing is to use ball sealers. No other method is considered reliable. Otherwise, the natural diversion that may occur as a result of injection of the alternating stages of viscous pad and add may be beneficial. 

For successful acidizing of horizontal wells producing from carbonate formations, the keys are treatment placement and efficient use of acid fluids. It is necessary to utilize one or more methods of acid placement or diversion, to impart treatment coverage over as much of the target interval as possible. This is especially challenging in open-hole completions or those utilizing slotted or predrilled uncemented liners. Such completions preclude use of ball sealers and most solid-particulate diverters. 

Diverter stage Ball sealers 50% excess of perfs ... 

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