INTRODUCTION
This paper reviews the effect of low molecular weight organic acids ( acetic, propionic, butyric) on corrosion rates in the presence of CO2. Recent papers point out concentrations of acetic acid in produced fluids as low as 100 ppm in the gas phase can cause corrosion attack as a result of thinning of the iron carbonate corrosion product layer. The effect of the mineral content of the produced water is also discussed. Laboratory methods for determining the concentration of low concentrations of organic acids are discussed. Laboratory and field data are presented.
Carbon dioxide was reported as a corrosive agent in oil and gas production in 1943 by Bacon and Brown1. The effect of organic acids and CO2 on the corrosivity of produced water was shown by Menaul in 19442. Hackerman and Schock3 compared the corrosion rates from three similar gas condensate wells with different corrosivities. They studied the corrosion rate in producing wells using weight loss coupons and by examination of the coupon surfaces using photomicrographs. They also ran laboratory corrosion tests in the presence of CO2 and found naphthenic acids acted as a corrosion inhibitor. They postulated the difference in corrosivity of the three wells could be due to the presence of naphthenic acids in the produced condensates. Attempts to correlate organic acids with corrosivity of production were made. Shock and Sudbury4 state the following guidelines regarding CO2 and organic acid corrosion:
a. Pitting corrosion will result in wells producing > one atmosphere partial pressure of CO2 or the produced water is in the pH range 4.0 to 4.5.
b. Severe attack will occur under the above conditions if organic acids are also
present.
c. Moderate general corrosion will result in wells producing organic acids and the partial pressure of CO2 is 0.2 atmosphere or less.
d. No corrosion will occur if organic acids are not present and the partial pressure of CO2 is<0.2 atmosphere.
The goal of the work of Shock and Sudbury was to formulate rules to predict the corrosion of wells producing CO2 and organic acids. As the above rules indicate, they had significant insight into the roles of CO2 and organic acids. They needed however a complete water analysis and a constant supply of organic acid in the corrosion tests to have a better understanding of the complexities of organic acids in CO2. Based on the limited laboratory and field data available at the time CO2 was considered the culprit causing corrosion. Obukhova5 in 1973 reported the presence of formic, acetic, propionic, butyric acid, and CO2 contributing to high corrosion rates ( 1.3 ? 5.7 mm/yr) in gas condensate wells in the Northern Caucasus fields. The organic acid content could be as high as 500 mg/L, with acetic acid being 50 to 90% of the total.
A paper by Carthers and Kharaka6 discusses the presence of organic acids in reservoir fluids and the geochemistry of their origin. Barth7 discusses the presence of low molecular weight organic acids in Norwegian shelf reservoirs and compares them with those found in American reservoir formation waters. Garber et al8 found an average of 119 mg/L acetate and 15 mg/L formate in separator water from 18 different Gulf of Mexico (GOM) gas condensate wells. These authors state, in their experience, organic acids are consistently found in GOM wells.
Detailed Studies of Organic Acids in CO2 Production
In the remainder of this paper acetic acid is used in the discussion since it is the dominant low molecular weight organic acid found in produced fluids. In the 1980?s more detailed studies were made to better understand the effect of ionic content on the corrosivity of systems contain
