Summary Acid treatments of deep wells completed by use of chromium (Cr) -based tubulars represent a real challenge to the oil industry. On one hand, Cr-based tubulars are used to protect against carbon dioxide (CO2) corrosion, but on the other hand, the protective layer [chromium(III) oxide (Cr2O3)] dissolves in hydrochloric acid (HCl). This makes protection of Cr tubulars during acidizing very challenging, especially at high temperatures. At temperatures greater than 200°F, there is a need to add corrosion-inhibitor intensifiers, most of which depend on heavy metals [copper (Cu) or antimony (Sb)] or are not effective at temperatures greater than 300°F [e.g., potassium iodide (KI)]. Over the last decade, a new chelant was developed, glutamic acid N, N-diacetic acid (GLDA), which can dissolve carbonate minerals from both carbonate and sandstone formations. This chelant can form wormholes in carbonates (both calcite and dolomite) and does not destabilize clay particles present in sandstone formations. In the present paper, the corrosion rate of GLDA solutions is compared with that of other chelants and simple organic acids that are used for carbonate dissolution, such as hydroxyethylethylenediaminetriacetic acid (HEDTA), acetic acid, and formic acid. All corrosion tests were conducted at high temperatures and pressures and extended for up to 6 hours at temperature and pressure. The Cr and nickel (Ni) -based coupons representing tubular metallurgy were examined thoroughly after the tests, and the spent fluids were analyzed for key cations [Cr, Ni, molybdenum (Mo), iron (Fe), and manganese (Mn)]. Compared with formic acid, acetic acid, and even HEDTA, GLDA is much less corrosive to Cr-13 alloys. The results of this work show that GLDA at 20 wt% causes almost no corrosion with Cr-13 up to 300°F. Unlike GLDA, HEDTA was found to be corrosive at a pH = 3.8, and requires attention when used in wells completed with Cr-13-based tubulars. On more-corrosion-resistant Cr- or Cr-Ni-based alloys, such as super Cr-13, Duplex-2205, Inconel-625, and Incoloy-925, the corrosion rate of GLDA is still far below the acceptable limit of 0.02 to 0.05 lbm/ft2 up to 350°F. In wells with corrosive sweet and sour gases, tubulars consisting of low-carbon steel, Cr-based steel, or corrosion-resistant Cr-Ni alloys can be effectively protected by a combination of GLDA with a minimal amount of a suitable corrosion inhibitor. Because of its favorable environmental profile, this mixture meets all the Oslo-Paris Convention for the Protection of the Marine Environment of the Northeast Atlantic (OSPAR) requirements for use in the North Sea. On the basis of these results, GLDA solutions can be used to stimulate carbonate and sandstone wells completed with Cr- and Ni-based tubulars, while maintaining the integrity of the tubulars.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor many reasons acidizing treatments represent a real challenge to the oil and gas industry. On one side acidizing can significantly improve the productivity of the well, but on the other side the intrinsic corrosive character of the acids form a severe threat to the well's integrity. Therefore traditional acidizing treatments with fluids involve significant loadings of corrosion inhibitors and corrosion inhibitor intensifiers to help mitigate the corrosion. However, the additives can cause their own damage to the formation, reduce overall effectiveness of the acidizing fluid, and come with significant additional costs to the overall acidizing program.Recently studies with a new environmentally friendly stimulation fluid, glutamic acid diacetic acid (GLDA), were presented for both carbonate and sandstone reservoirs. The studies have shown that GLDA can dissolve calcite & dolomite, does not destabilize clays particles, and can significantly improve permeability in both carbonate and sandstone formations across wide field conditions. In the present paper the corrosion rate of GLDA is compared with other chelates and simple organic acids that are used for carbonate dissolution, such as hydroxyethylethylenediaminetriacetic acid (HEDTA), acetic, citric and formic acid. All corrosion tests were conducted at high temperature and pressure and extended for up to 6 hour at temperature and pressure.The results show that GLDA at 20 wt% has the least impact on low carbon steel, in comparison to the other stimulation fluids examined in this study. A very minimal amount of corrosion inhibitor loading was needed to keep the corrosion rate below the acceptable rate for GLDA, even at elevated temperatures or in the presence of corrosive gases like H 2 S and CO 2 . On more corrosion resistant Cr-based metals, like Cr-13 and duplex, the corrosion rate of GLDA is far below the acceptable limit with no corrosion inhibition even at 300°F. Based on the results, GLDA solutions can be used to stimulate carbonate and sandstone wells completed with various types of metallurgies with no or very minimal amount of corrosion inhibitors and effectively maintain the integrity of the tubular & internals.

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Acid treatments of deep wells completed with Cr-based tubulars represent a real challenge to the oil industry. On one hand, Cr-based tubulars are used to protect against CO 2 corrosion, but on the other hand, the protective layer (Cr 2 O 3 ) dissolves in hydrochloric acid (HCl)-a common stimulation fluid. This fact makes protection of Cr tubulars during acidizing very challenging, especially at high temperatures. At temperatures above 200°F, there is a need to add an intensifier. Most of them depend on heavy elements (Cu, Sb), or are not effective above 300°F (e.g., KI).Over the last decade, we developed a new chelate, glutamic acid N, N-diacetic acid (GLDA) that can dissolve carbonate minerals from carbonate and sandstone formations. This chelate can form worm holes in carbonates (both calcite and dolomite) and does not destabilize clay particles. In the present paper, the corrosion rate of GLDA is compared with other chelates and simple organic acids that are used for carbonate dissolution, such as hydroxyethylethylenediaminetriacetic acid (HEDTA), acetic and formic acid. All corrosion tests were conducted at high temperatures and pressures and extended for up to 6 hour at temperature and pressure. The coupons were examined thoroughly after the tests, and the spent fluid was analyzed for key ions (Cr, Ni, Mo, Fe, and Mn).The results show that GLDA at 20 wt% gives almost no corrosion with Cr-13 up to 300°F. Unlike GLDA, HEDTA was found to be corrosive at pH=3.8 and requires attention when used in wells completed with Cr-13 based tubulars. On more corrosion resistant Cr-based metals, like super Cr-13 and Duplex the corrosion rate of GLDA is still far below the acceptable limit of 0.02 to 0.05 lbs/ft 2 up to 350°F. In wells with corrosive sweet and sour gases tubular consisting of low carbon steel, Cr-based steel or corrosion resistant Cr-Ni alloys can be effectively protected by a combination of GLDA with a minimal amount of corrosion inhibitor. Due to its favorable environmental profile this mixture meets all the OSPAR requirements for use in the North Sea. Based on our results, GLDA solutions can be used to stimulate carbonate and sandstone wells completed with Cr-based tubulars, while maintaining the integrity of the tubulars.

The impact of multiple erosion pits and crack initiation was investigated for a 500 megawatt (MW) steam turbine unit with three low pressure (LP) rotors on the steam end and generator end of the stage LO blades. These units have been subjected to two-shifting operation and have been retrofitted with new high pressure (HP) turbine units over the life history of the turbines. Droplet erosion damage was exacerbated by operating conditions causing multiple crack initiation sites concentrated above the root platform. A method of accumulated damage was employed using pit counting and the number of cycles referenced back to turbine revolutions in line with the accumulated damage model developed from the damage function analysis and Palmgren-Miner approaches. The number of rotational cycles were calculated from the starts and running hours for preand post-retrofit scenarios and compared and correlated to the number of pits formed during the completed cycles. The macro crack size represented the critical crack size or a damage number of one. It was found that there was a significant shift in the number of rotations before and after the HP turbine retrofit to achieve a damage rate of one. An accumulated damage model was developed for the post HP turbine retrofit and the LP turbine last stage blades fitted fi-om new, based on the empirical evidence from the analysis. Assessments on the erosion distribution in the zoned areas revealed evidence of cracking, manifesting 18 mm away from the highest probability distribution with a standard deviation of 2 mm. The area where cracking first initiated on multiple samples was found to coincide with the mechanical change in the section blending in with the blade trailing edge. The damage model was implemented on a ive running plant and successfully applied over a period of two years using the most conservative approach, based on the lower bound values.