Abstract

The Niagaran formation in the Michigan basin is comprised of Silurian Pinnacle reefs. It is a heterogeneous carbonate formation with the majority being dolomite. There are two Niagaran plays in Michigan, the Northern Play and the Southern Play. Past stimulation treatments on the Niagaran have consisted of mainly hydrochloric acid at concentrations of 15–28%. Most treatments were kept to matrix conditions due to water zones in close proximity. These treatments usually yield marginal results due to the acid being spent mostly near well bore. Gelled, crosslinked or emulsified acid are good solutions for this problem but can also leave some damage behind. Acid gelled with surfactants can yield similar results and be easier to clean up.

This paper will provide some background on the Niagaran formation and historical treatments. The paper will explain the chemistry behind viscoelastic surfactant-based acid systems and will provide detailed descriptions of the benefits of these types of systems. Production data from a well treated with both conventional acid and a viscoelastic acid system will be discussed. The paper will then conclude with a few words on the economics behind viscoelastic systems.

Introduction

Oil producing formations like the Michigan Basin's Niagaran Reef are getting more attention now than in the recent past. This attention is fueled by the recent down turn in gas pricing along with the fact that oil prices appear to be making an earlier comeback. When dealing with oil formations that produce less than spectacular amounts of oil per day, it is important to perform effective stimulation jobs that don't damage the formation.

Acidizing carbonate formations such as the Niagaran is an easy and usually inexpensive solution to stimulation. Finding the optimum acid blend for the formation, however, can sometimes be challenging. Regular hydrochloric acid mixed at concentrations of 15–28% works well in the Niagaran but may dissolve more near-wellbore formation rock and not reach out into the reservoir as desired. As a result, gelled, crosslinked or emulsified acids systems have demonstrated successes. One of the main benefits of using gelled, crosslinked or emulsified acid systems is that by encapsulating the acid, the contact time between the acid and formation rock can be delayed. This allows more time for the acid to reach out into the reservoir before spending itself by dissolving formation rock. The same effect could be accomplished with a weaker acid system, but by using an encapsulated acid system, strength isn't sacrificed. The only drawback to using encapsulated systems is breaking them. This is not an exact science. If they are not properly broken, they can leave damaging gels or emulsions, plugging off pore spaces and restricting formation fluid from flowing to the well bore. One solution to this problem is gelling systems with surfactants. A viscoelastic surfactant-based gelling system can achieve the same results as an encapsulated system but with better control over the break.

Viscoelastic surfactant-based systems use large loadings of surfactants to create a polymer-style gel. The benefit of this gel over normal polymer gels is that it is sensitive to pH and hydrocarbon. This means that in an acid system, as the pH changes, so do the gel characteristics. By the time the acid system has reached a neutral pH, the gel will have broken back to a liquid form. If for some reason some gel remains, the system's hydrocarbon sensitivity means it will break when it comes in contact with formation fluids.

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