A New, Low Corrosive Fluid To Stimulate Deep Wells Completed With Cr-based Alloys
- Corine De Wolf (AkzoNobel) | Hisham A. Nasr-El-Din (Texas A&M University) | Arjen Bouwman (AkzoNobel) | Edwin Bang (AkzoNobel) | Ed Naylor (AkzoNobel)
- Document ID
- Society of Petroleum Engineers
- SPE International Conference & Workshop on Oilfield Corrosion, 28-29 May, Aberdeen, UK
- Publication Date
- Document Type
- Conference Paper
- 2012. Society of Petroleum Engineers
- 1.8 Formation Damage, 3.2.4 Acidising, 5.8.7 Carbonate Reservoir, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 5.4.10 Microbial Methods, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion
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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 CO2 corrosion, but on the other hand, the protective layer (Cr2O3) 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/ft2 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.
Since the 1890s the oil and gas industry has been using acid treatments as a method to optimize production. Already in the early days, corrosion prevention during acidizing was recognized as one of the major challenges that needed to be solved. The popularity of the technique profited tremendously from the development of corrosion inhibitors that could cope with the conditions present in oil wells (Kalfayan 2008).
From the first commercial use in the 1930s up till now, HCl has remained the primary acid for stimulation of carbonate formations, whereas mixtures of HCl and HF became the standard in sandstone acidizing. To deal with the corrosive nature of these strong acids, corrosion inhibition has become an integral part of the whole acidizing treatment, resulting in dedicated studies to optimize the functionality of the corrosion inhibitors under field conditions (Nasr-El-Din 2002). However, the use of corrosion inhibitors is not without risk for the formation. For example, excessive use of corrosion inhibitors may cause incompatibility problems with the other additives, change the wettability of the rock or result in severe emulsion problems, resulting in slow or incomplete cleanup after the treatment (Schechter 1992). Acid corrosion inhibitors should therefore be evaluated in the laboratory both for their ability to protect the metal and for their formation damage characteristics prior to application in the field (Crowe 1985).
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