Reservoirs matrix damage

To illustrate the matrix damage problem in the reservoir and scale formation in production wells an application using the numerical code is presented. In this example, sulfate scaling occurs by mixing of injected water (seawater rich in sulfate and poor in Ca", Sr" and Ba ) with a connate water rich in Sr and Ba" cations. From this mixing strontium sulfate salt (SrSOj) and barite (BaS04) precipitations are expected. This kind of scaling is typical from the North Sea (Osborne et al., 1994) and also common in Campos Basin, Brazil (Silva et al., 2001). 

Actual responses of tuo carbonate petroleum reservoirs to matrix injection of hydrochloric acid are compared with a recently proposed experimental model for wormholing. This model is shown to be applicable in undamaged primary porosity reservoirs, and should be useable in damaged double porosity ones. Formations of no primary porosity are shown to respond very differently. 

Effect of pH. The pH of the flowing fluid is an important factor in the fines migration process (5, 12, 52, 58). Mungan (52) noted that injection of strong acids or bases could cause permeability damage. Under very high or very low pH conditions, the permeability damage is caused by dissolution of the matrix material, which produces fine particles of varied mineral composition. Somerton et al. (58) found that the water sensitivity of reservoir sands was related to the pH response exhibited by the rock after the contact with fresh water. Most sandstone cores showed an increase in the effluent pH after the switch was made... 

Acidizing treatments are used to remove wellbore damage, enhance matrix permeability or both. The acid reacts with the rock matrix and, as a result, the permeability of the formation will increase. Reagents commonly used to stimulate carbonate reservoirs are hydrochloric (15 or 28 wt%), formic (9 wt%), and acetic (10 wt%) acids [J]. Recently, Fredd and Fogler [2, 3] introduced ethylenediamine tetraacetic acid (EDTA) as an alternative fluid to acidize carbonate formations. 

In damage assessment, it is necessary first to find information on the reservoir geology, as well as the mineralogy. An understanding of the rock type (sandstone or carbonate) and other features, including permeability and porosity, is critical. This includes the nature of porosity (matrix versus naturally fractured) and how permeability is distributed (i.e., how it varies) across the producing interval—or the injection interval, as the case may be. 

Well performance is largely dependent on reservoir quality and the nature of the formation matrix, as well as on the presence and type of damage. 

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