Hydrochloric acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However, there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction rate with carbonate rocks, which limits acid penetration in the formation. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity, their low dissolving capacity may still limit the wormhole penetration leading to insufficient stimulation of the formation. Therefore, opportunity exists to mix HCl with an organic acid to achieve productivity enhancement by optimizing the wormhole penetration and profile.
Organic acids that are utilized in stimulating carbonate formations include formic, acetic, and more recently, citric and lactic. Selecting a suitable organic acid for a specific acidizing treatment is more difficult due to complex thermodynamic equilibrium and reaction kinetics. The reactions between organic acids and carbonate are less understood than those of HCl with carbonate rocks. Organic acid/carbonate systems are complicated because of the presence of CO2, organic ligands, and potential precipitation of the reaction products; the organic salts of calcium and magnesium. Therefore, more testing and modeling are needed to better understand these reactions.
This paper discusses the required information to properly design an organic acid or HCl plus organic acid treatment. In additional to reaction kinetics, data such as carbonate dissolving capacity at reservoir temperature and pressure, solubility of reaction products, and the effect of HCl to organic acid ratio are needed to better design field treatments. Recommendations are given on what and how laboratory evaluation should be carried out to obtain this information.
Oil and gas companies are developing carbonate reservoirs of deeper and deeper depths in order to meet the demand of increasing worldwide energy consumption. Enhancing productivity from these reservoirs poses a challenge in stimulation fluids due to the increase in bottom hole temperature. The rapid reaction rate between HCl and carbonate limits the penetration of HCl into the formation, especially at low pumping rates. The reaction of HCl often needs to be retarded by gelling,1 emulsifying,2 or adding viscoelastic surfactants.3 In addition to the high reaction rate, HCl is very corrosive to well tubulars. Expensive corrosion inhibitors can protect the tubulars at high temperatures only for a short period of time. These drawbacks make organic acids, such as formic and acetic, potentially attractive for stimulating high temperature wells.
Organic acids have been used in well stimulation because of their low corrosivity 4 and lower reaction rate with the rock. However, they have the following limitations:
they cannot be used at high acid concentrations. This is because of the limited solubility of their calcium salts. For instance, acetic and formic acids are typically used at concentrations less than 13 and 9 wt%, respectively to avoid precipitation of calcium acetate and calcium formate,5
Organic acids have a low dissociation constant. They normally do not react to their full acid capacity because of the release of CO2 from carbonate dissolution,
the degree of hydrogen ion generation decreases with increasing temperature,6,7 and
the cost of organic acid is significantly higher than that of HCl for equivalent mass of rock dissolved.