Treatment evaluation leads to problem identification and to continuously improved treatments. The prime source of information on which to build an evaluation are the acid treatment report and the pressure and rate data during injection and falloff. Proper execution, quality control, and record keeping are prerequisites to the task of accurate evaluation. Evaluation of unsatisfactory treatments is essential to recommending changes in chemicals and/or treating techniques and procedures that will provide the best treatment for acidizing wells in the future. The most important measure of the treatment is the productivity of the well after treatment.

In formations with over 1% carbonate, an HCl or acetic acid preflush dissolves the carbonate to prevent waste of HF acid and formation of the insoluble precipitate calcium fluoride. Calcium and sodium chloride workover brine also must be flushed away from the wellbore with HCl acid or ammonium chloride brine. Preflushes also displace and isolate incompatible formation fluids (either brine or crude oil). Higher concentrations of ammonium chloride ( 3%) are recommended where swellable smectite and mixed layer clays are present.[1][2] For successful HF acidizing, more than 120 gal/ft of HF/HCl acid is usually required.

Once you determine that a well is a good candidate for matrix acidizing and have selected appropriate acids, you are ready to design the treatment. Essentially, the design process is a systematic approach to estimating and calculating injection pressure and rate, volumes, and concentrations. If acid can easily reach nearby plugging solids, small volumes of 25 to 50 gal/ft of HF-type acid can dissolve this damage; however, with more severe damage, more time and volume are needed to reach the plugging solids. Effective acid diversion reduces acid volumes needed. Permeability and mineralogy determine the compatible concentration of HCl or acetic acid in the preflush stage and HF and HCl acid in the HF-/HCl-acid stage.

An acid additive is any material blended with acid to modify its behavior. Because acid is so naturally corrosive, the development of an additive to reduce acid attack on steel pipe was the first requirement for successful acidizing. Development of a suitable corrosion inhibitor started the acidizing service industry in 1932. Comprehensive testing and application of corrosion inhibitors is still necessary in successful acidizing. Many acid additives are available, but those that are usually necessary are corrosion inhibitors, surfactants, and iron control agents.

Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.

When cement is bullheaded into the annulus to displace mud, the differential pressure between the cement and the formation fluid can lead to a significant loss of cement filtrate into the formation. If, however, large volumes of cement filtrate invade the rock, the possibility of formation damage exists. Depending on the specific composition of the cement and its pH, the filtrate may be supersaturated with calcium carbonate and calcium sulfate. As the cement filtrate invades the formation and reacts with the formation minerals, its pH is reduced from 12 to a pH buffered by the formation minerals. This rapid change in pH can result in the formation of inorganic precipitates such calcium carbonate and calcium sulfate.

In this study, several process alternatives for the permanent sequestration of carbon dioxide (CO2) as solid carbonates are evaluated. Although the formation of mineral carbonates is thermodynamically favorable, it does not occur significantly because of kinetic limitations and the formation of products that hinder the evolution of the process. In the complete paper, the authors propose biomimicking approaches to precipitate solid carbonates while limiting the amount of energy required or using the byproducts to generate valuable materials. Permanent sequestration of CO2 as solid carbonates is a feasible solution to the increased levels of CO2 in the atmosphere. Mineral carbonation--the process of capturing CO2 in the atmosphere in the form of solid carbonates through the reaction of CO2 with silicates--is a spontaneous, thermodynamically favorable process.

Industry operations are shifting toward high-temperature (HT) downhole settings, expensive tubular metallurgy, and extended reach wells, while health, safety, and environmental requirements become stricter. Consequently, conventional stimulation treatments, such as applications using hydrochloric acid-based fluids, will no longer meet the industry's needs as operational environments evolve. A new stimulation fluid developed by AkzoNobel, Dissolvine StimWell, is based on glutamic acid diacetic acid (GLDA) and has been successfully applied in the field. GLDA has high thermal stability and low corrosion potential, and is an effective stimulation fluid without adverse environmental impact. A vertical gas well in a deep, sour carbonate reservoir was successfully stimulated using GLDA.

Iron precipitation is a serious problem in acidizing treatments, causing formation permeability damage by restricting flow channels. Solutions have included buffers, reducing agents, and chelating agents. Experience has shown that chelating agents are the most effective; however, limitations of current chelating agents include poor stability at elevated temperatures, higher cost, low solubility in acidic medium, tendency to precipitate calcium products, and negative health and environmental effects. This work introduces sodium gluconate as an efficient and environmentally friendly iron-chelating agent. Corrosion is a major challenge in any acidizing treatment.

Sour gas is being produced from a number of carbon-steel-completed wells in the US, Canada, France, and Saudi Arabia. The gas stream contains various levels of hydrogen sulfide and carbon dioxide (CO2) and is produced from high-temperature reservoirs with temperatures ranging from 160 to 410 F. The combination of hydrogen sulfide with high temperatures introduces challenges related to corrosion and iron sulfide (FeS) scale formation. FeS is found naturally in different forms. The gas-production systems studied in this paper have large concentrations of hydrogen sulfide, so iron is a limiting reactant in these systems. FeS formation is favored thermodynamically.