Near-wellbore formation damage removal

It is sometimes necessary to break down perforations by temporarily pumping acid above fracturing pressme to initiate production or injection of a subsequent treatment, such as hydraulic fracturing. Typically, HCl is used in concentrations ranging from 5% to 20%, with 15% HCl being standard. As this is a routine procedure in certain areas, it will not be discussed in further detail here. 

The primary purpose of matrix acidizing in sandstones is to remove formation damage caused by clay and other siliceous fine particles plugging near-wellbore permeability. Particles may be naturally occurring or may have been introduced into 

HF is the only common add that dissolves siliceous minerals appreciably. Therefore, sandstone acidizing formulations include HF or one of one of a variety of HF precursors, or compounds that generate HF. The most commonly used formulations are mixtures of HCl and HF. These are referred to as mud add, from the early days of sandstone acidizing. Acid concentrations can vary from the low end (e.g., 3% HCl 0.5% HF) to the high end (12%-15% HCl 3%-5% HF or more). 

For sandstones with high carbonate mineral content ( 15%-20%), HCl-HF mixtures should be avoided. HCl alone should be used in such cases. However, carbonates are often present in sandstones as grain cementation. Removal of carbonates with acid can diminish rock competence. Modern HF-containing buffered acid systems, which have low total acidity (relatively mild pH) and thus low reactivity with carbonates, are a good option in such cases. 

HCl is also applicable for removing certain scales, such as calcium carbonate, iron carbonate, iron oxides, and iron sulfide. Organic acids, such as acetic acid and formic acid, are sometimes used in place of HCl, especially in high-temperature applications, where HCl corrosion can be severe. 

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HF reaction is controlled by surface reaction kinetics. HF reacts preferentially with high surface-area particles. It usually spends within a short distance from the wellbore if such minerals are abundant, which they usually are. Treatment typically does not exceed the wellbore by more than 1-2 ft (except in naturally fractured formations), and it can be much less. Nevertheless, removal of very near-wellbore formation damage can result in severalfold increases in well productivity, as indicated by the substantial reduction in productivity resulting from severe, very near-wellbore damage, as shown in table 4-1. 

There is considerable potential, therefore, for mineral scale, such as barium sulfate (see the next section), to form during these procedures. The scale may be deposited in the formation, the wellbore, or in production tubing. Scale that forms in the formation near wells, known as formation damage, can dramatically lower permeability and throttle production. When it forms in the wellbore and production tubing, mineral scale is costly to remove and may lead to safety problems if it blocks release valves. 

As previously discussed, the most common purpose of matrix addizing is to restore near-wellbore permeability in or through a damaged formation zone. Because it is bypassed, rather than directly removed, formation damage in a candidate for carbonate acidizing need not be acid removable by contrast, it does need to be add removable in a candidate for sandstone acidizing. 

Matrix acidizing has application in both carbonate and sandstone formations. In sandstone formations, matrix acidizing treatments should be designed primarily to remove or dissolve add-removable damage or plugging in the perforations and in the formation pore network near the wellbore. 

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