Summary
Throughout a well's lifetime, formation damage can occur during the activities of drilling, completion, injection, or well-stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more-severe form of formation damage.
This report discusses the improper use of mud acid [at 9 wt% hydrochloric acid (HCl)/1 wt% hydrofluoric acid (HF)] in restoring the injectivity of Well N-510. The subject well was stimulated with two acid-stimulation treatments in an attempt to improve the poor results of a previous cleanout job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage that resulted in the severe decline of well injectivity.
Integration of chemical-analysis techniques performed on return fluids and coreflood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation-damage mechanism that occurred during each treatment. On the basis of these studies, it was found that the poor results of the cleanout job were caused by precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-sulfate-content water. Most of this precipitation occurred in the wellbore vicinity during the preceding stages of the well flowback.
Calcium sulfate precipitation had a negative impact on the performance of the conducted acid-stimulation treatments. In the presence of this precipitation, the two successive mud-acid-stimulation treatments created another form of damage (i.e., in-situ fluoride-based scale). Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale, and as a result, it contained a high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value.
The interactions between different acid systems and the constituents of the downhole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications for future stimulation treatments, conducted under similar conditions, so as to prevent the formation of these scales.
Damage Mechanism of Oil-Based Drilling Fluid Flow in Seepage Channels for Fractured Tight Sandstone Gas Reservoirs