Acid stimulation experimental data collected on 231 crude samples from various oil fields were used in this study to formulate an empirical model for quantifying the amount of asphaltic sludge precipitating as a consequence of an acidizing job. Data showing the individual effects of acid strength, acid type, solvent preflush, iron control additives, ferrous and ferric ion concentrations, mutual solvent concentration, corrosion inhibitor type, and surfactant types have been used as the basis for formulating an empirical model for the weight percent of asphaltene sludge. The acid-induced sludge model has been validated with stimulation data from the Endicott field. The model is then used to study the effect of various factors on sludging.
A 15% HCL concentration is confirmed to be the threshold for serious acid-induced sludge. Hydrofluoric acid exhacerbates sludging except at low concentrations less than 3%. Asphaltene sludging is promoted by the presence of ferrous and ferric ions. Ferric ions cause more sludging. The addition of iron control additives like citric acid, EDTA, and NTA is found to cause sludging. Erythorbic extractant causes less sludging than any of the iron control additives commonly used. The three surfactant types investigated (Fluoro-surfactant, Non-emulsifier, wetting agent) are found to have an identical effect on sludging. The use of a mutual solvent concentration greater than 5% is found to increase the sludging tendency.
Acid-induced asphaltene sludging is becoming an increasing cause of oil well stimulation treatment failure. The proposed model predicts quantitatively the effect of various acid additives on crude oil sludging, and may be used as a designing tool for an acidizing job with minimum sludging potential.
Introduction
Asphaltene deposition is one of the most difficult problems encountered during the exploitation of oil reservoirs. Miscible and immiscible flooding operations exhibit suitable environments for such precipitation. In some cases, asphaltene precipitation can occur during natural depletion and oil transportation and, commonly, during well stimulation.5 Changes in temperature, pressure, and composition during oil production can destabilize the colloidal dispersion of asphaltenes in oil.4 Crude oils are typically categorized as either paraffinic or asphaltenic depending on the nature of the predominant heavy species. Asphaltenes are contained in crude oils in the form of a colloidal dispersion. Amorphous in structure, the asphaltene micelle consists of higher molecular weight compounds surrounded and peptized by neutral resins and aromatic hydrocarbons. The micelle consists of sheets of polycyclic rings containing 6–14 rings per sheet. These sheets are stacked to form the asphaltene particle. The particle has a diameter of 30 to 65 angstroms and a molecular weight ranging from 1,000 to 50,000.4
Aggregated asphaltenes can cause a variety of problems in injection and production wells, surface facilities, pipelines, and in refinery operations. Within the formations, aggregation of asphaltenes results in a decrease in absolute permeability, and may change the relative permeability profile. In many occasions, asphaltene deposition has threatened the economic recovery of the oil and increased the cost of production of many oil fields around the world considerably. There has been a considerable effort focused on predicting the appearance and extent of asphaltene precipitation. The amount of asphaltene present in oil is readily quantified by a simple solvent precipitation test; but whether that asphaltene causes problems depends on whether or not it reaches instability during its removal from the reservoir and subsequent transport. Detecting the onset of asphaltene precipitation presents greater technical challenges than quantifying the amount initially present in the oil, especially at reservoir conditions. Methods have been developed based on filtration, refractive index, and solubility, to name only a few.6–7
