Challenges in sandstone acidizing still exist, although great improvements have been made in the last decade. Factors that contribute to these challenges include: multiple types of co-existing formation damage; uncertain rock mineralogy; multiple fluids and pumping stages; complex chemical reactions between fluids and formation minerals; and fast reaction kinetics at elevated temperatures. Others are: inadequate zonal coverage; limited live acid penetration; rock deconsolidation due to acid-rock interactions; acid emulsion and sludge tendencies; corrosion; and health, safety, and environmental (HSE) concerns. These factors contribute to the low success rate of sandstone acidizing treatments especially in acid-sensitive, and clay- and carbonate-rich sandstone formations at high temperatures.
In this paper, we review some current practices used to address these challenges in the industry and present a new multi-pronged approach that would improve the success rate of sandstone acidizing treatments. The system requires the use of a geochemical simulator to "design for success" by selecting the safest fluid for the formation and for optimizing the fluid volumes and injection rates, and a breakthrough fluid that uses novel chemistry to simplify treatments and minimize the risk of acid-induced formation damage.
Batch reaction studies indicate that the new fluid reacts more slowly with aluminosilicates than conventional mineral acids, thus preventing secondary and tertiary precipitates. Core flow tests demonstrate that the new fluid prevents the near-wellbore deconsolidation problems generally experienced with HF-based systems in high-temperature sandstone acidizing treatments. These laboratory results were corroborated with field core samples and geochemical simulations, especially with high-clay and high-carbonate sandstone formations.
Extensive laboratory tests also demonstrate that the fluid results in less emulsion and sludge tendencies; lower corrosion rate to tubulars and equipment; better HSE footprint due to its almost neutral pH; and better tolerance to damage and formation uncertainties.
Traditionally, hydrofluoric (HF) acid-based systems have been found to be effective in dissolving aluminosilicates in sandstone formations. Depending on the rock mineralogy and treatment temperatures, various formulations have been used in the industry with mixed results; sometimes leading to rapid decline in post-treatment production. These formulations are usually composed of hydrochloric acid (HCl) and HF at various concentrations, ranging from low strength to high strength to retarded. Examples of these HCl:HF formulations include: 6:1.5, 9:1, and 12:3 systems. In retarded systems, HCl is replaced with an organic acid like acetic acid.
The relatively poor results of conventional systems may be attributed to several reasons. First, there is a high risk of secondary and tertiary precipitation in the zones that are not adequately covered by the preflush due to inadequate fluid volumes due to poor job designs, and inefficient placement in the zones of interest. Second, the main treatment fluid may end up in the most permeable zones, leaving the less permeable zones either under-stimulated or unstimulated. Third, the treatment fluids could deconsolidate acid-sensitive rock in the near-wellbore area and subsequently lead to the production of formation fines. Additionally, these treatments are operationally very complex and time-consuming due to multiple fluids and stages. These issues are exacerbated at higher bottomhole temperatures due to the accelerated reaction kinetics and corrosion inhibition difficulties at elevated temperatures.
A number of existing high-temperature sandstone acidizing systems were reviewed and a new system developed to improve the success rate of these treatments. Extensive laboratory tests were performed, and results reported in this paper, to validate the effectiveness of the system.