Acid in oil emulsions stimulate carbonate formation of limestone and dolomite. These emulsions consist of internal inhibited acid phase and an external hydrocarbon phase mixed with an emulsifier. In this current technology, the corrosion inhibitor is dissolved in the acid phase and encapsulated by hydrocarbon in the outer phase. The facts that the corrosion inhibitor is inside the emulsion will retard it from dispersing on metal surface of the tubing to create a metal protective film. In this paper, a method is proposed where the corrosion inhibitor is replaced from being in the internal phase to be in the external phase of the emulsion. This situation will allow the corrosion inhibitor to directly disperse onto the tubing metal surfaces to form the protective film required to prevent the tubing from any acid attack. Acid in oil emulsion with corrosion inhibitor being in the external phase of emulsion was successfully created in the lab and resulted in a much better thermal stability at room and reservoir conditions. In this lab study, thermal stability of emulsion with corrosion inhibitor in the external phase resulted in more stable emulsion than those with corrosion inhibitor in the internal phase. At reservoir temperature of 248oF emulsions with corrosion inhibitor in the external phase acid start to separate after 60 minutes and at 150 minutes was completely separated. Emulsions at same conditions with corrosion inhibitor in the internal phase acid start to separate after 30 minutes and at 110 minutes were completely separated from hydrocarbon phase. When corrosion inhibitor removed completely from the emulsion, it start to separate at 140 minutes and at 180 minutes separation was only 20%. Corrosion inhibitor being in the external phase will enhance emulsions retardation and hence deeper penetration in the reservoir. In addition this new method will protect the well tubing and stimulation equipment much better than before. Introduction This paper provides a method of enhancing the corrosion inhibition of well tubing while using an acid-in-oil emulsion downhole in a hydrocarbon recovery or delivery system. In addition, this paper provides a method for acid stimulation of a carbonate formation while simultaneously protecting the well tubing more efficiently. Acid-in-oil emulsions are typically used to stimulate or enhance hydrocarbon production in existing carbonate reservoir rock formations, such as limestone, dolomite or calcareous-magnesium. Typically, the emulsified acid enters the formation and where employed successfully creates a barrier causing the acid to release slowly at a distance from the wellbore. The reaction of the released acid with the formation rock takes place simultaneously at different places inside the formation, resulting in channels that are joined together to form continuous wormholes. When pumping the acid-in-oil emulsions through steel tubing and piping, a corrosion inhibitor is usually added to reduce the corrosive effects of the acid. In operation, the corrosion inhibitor coats the steel surfaces as the emulsion is pumped into the wellbore and the surrounding rock.

Summary Acid-fracturing treatments are used commonly to enhance the productivity of carbonate formations with low-permeability zones. Various forms of hydrochloric acid (HCL) are used to create deep etched fractures. However, regular HCl reacts very fast with limestone and high-temperature dolomite formations and, unless retarded, will produce a fracture with low conductivity. In addition, concentrated HCl-based acids are very corrosive to well tubulars, especially at high temperatures. To address problems associated with concentrated acids, various retarded acids were introduced. Organic acids were used also in some cases. These organic acid systems were used successfully to acid fracture several wells in a deep gas reservoir in Saudi Arabia. Field data, however, indicated that there is a need to create deeper and more-conductive fractures. To achieve this goal, it was decided to conduct a field trial with a newly developed acid system. The new acid system is an ester of an organic acid in the form of solid beads. The ester reacts with water (hydrolyzes) at bottomhole temperature and produces lactic acid, which reacts with carbonate minerals and etches the surface of the fracture. The system was examined thoroughly in the laboratory and showed promising results. The treatment was conducted in the field without encountering operational problems. After successful placement of the solid beads in the fracture, the well was shut in for 24 hours to give ample time for the ester to hydrolyze and for the generated acid to react with the formation rock. The well was allowed to flow, and samples of the fluids produced were collected to understand chemical reactions that occurred during the treatment. The treatment has resulted in a slight increase in gas production, and no significant improvement was noted over a 9-month period. Consequently, the well was matrix acidized with 28 wt% HCl and responded positively to the treatment. This paper will discuss major reactions that occurred during these treatments and how they impacted well response. Lessons learned and recommendations to improve the results of this new acid system will be given.

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Throughout well lifetime, formation damage can occur during the activities of drilling, completion, injection, or well stimulation treatments. Typically, remedial treatments to restore the well performance involve injection of reactive fluids capable of removing such damage. Therefore, understanding damage mechanism and type is critical for fluid selection and effective treatment design. Without this knowledge, the conducted stimulation treatment could cause a more severe form of formation damage. This report discusses the improper use of mud acid at (9 wt% HCl/1 wt% HF) in restoring the injectivity of N-510. The subject well was stimulated with two acid stimulation treatments as an attempt to improve the poor results of a previous clean-out job, conducted to remove mud filter cake. These treatments were designed to remove the damage that has been limiting the well injectivity. However, it was found that these acidizing treatments created a new formation damage which resulted in severe decline in the well injectivity. Integration of chemical analysis techniques of return fluids and core-flood experiments was used to assess the effectiveness of all conducted treatments. This report demonstrates the techniques used to identify the source and type of formation damage mechanism that occurred during each treatment. Based on these studies, it was found that the poor results of clean-out job were due to precipitation of calcium sulfate. This precipitation was a result of the mixing between spent cleanout acid, having a high amount of calcium, and the high-content sulfate water. Most of this precipitation occurred in the well-bore vicinity during the last stages of the well flow-back. Calcium sulfate precipitation had a negative impact on the performance of the conducted acid stimulation treatments. In the presence of this precipitation, the two successive mud acid stimulation treatments created another form of damage, i.e. in-situ fluoride-based scale. Initially, the fresh injected mud acid dissolved most of the calcium sulfate scale and as a result it contained high amount of dissolved calcium ions. However, upon the spending of injected mud acid in the formation, calcium fluoride precipitated as a result of the increase of solution pH value. The interactions between different acid systems and the constituent of down-hole environment, resulting in the precipitation of calcium sulfate and calcium fluoride, are discussed. In addition, this report provides recommended modifications to future stimulation treatments, conducted under similar conditions so as to prevent the formation of these scales.