General

The anomalies experienced when using iron counts as a corrosion-monitoring method result mostly from the varying, usually uncontrollable, conditions found in almost every production system. Because the term iron count refers to the concentration of iron dissolved in the water expressed as milligrams per liter (mg/L), milligrams per kilogram (mg/kg), or parts per million by weight (ppmw), those monitoring corrosion using iron counts must specify whether the iron content is based on the total fluid produced and whether the iron is reported as soluble iron, ferrous iron, or total iron. The usual oilfield iron count is total iron content of an acid-treated sample. When iron counts are used to monitor corrosion trends, the same species must be determined consistently for a given sampling point in a system. For comparison of systems producing varying amounts of water, a more meaningful tool is the iron production rate that takes into consideration the water flow rate at the time of sampling. The iron count is converted to an iron production rate, usually expressed in kilograms of iron per day (kg/d) or pounds of iron per day (lb/d).

The analyst should evaluate available test methods for iron content to determine the most suitable method regarding detection limits, accuracy, precision, and interferences. Specific analytical procedures are not addressed in this standard. The exact method of sampling and sample treatment required to separate and analyze for ferrous, ferric, soluble, and total iron content of a water sample are adequately covered in the analytical procedures described by Rydell and Rodewald,1 Eaton et al.,2 and ASTM⁽¹⁾ D1068.³ If techniques are used to analyze for the individual species of iron, the final report must indicate the form of iron being reported. If only the typical total acid-soluble iron content is determined, the final report should indicate that the result is "total iron."

For the purposes of this standard, it is presumed that iron counts are performed on aqueous samples. Analysis of hydrocarbon samples for iron content is possible and the technique is practiced by some corrosion engineers. One suggested technique for "iron in oil" is described by Rydell and Rodewald.1

The mechanical arrangement, physical conditions, and chemical environment in almost every system or part of a system must be evaluated under comparable conditions before the iron content of each sample can be correctly interpreted. The iron counts measured are not of any value if these variables are not considered in the interpretation.

Monitoring corrosion by the use of iron counts may be done easily, inexpensively, and quickly in the field. Iron production rates, unlike test specimen corrosion rates, may give some indication of corrosion upstream or downhole from the sampling point. Iron counts are useful when surface-monitoring devices, such as test specimens, may not reflect downhole conditions, such as when paraffin forms on test specimens and when downhole conditions are greatly different from surface conditions. The principal reason for the historical popularity of iron counts as a standalone corrosion-monitoring method is that in many small production facilities other forms of corrosion-monitoring facilities have not been installed. However, iron count measurements should be combined with other corrosion-monitoring methods whenever possible.

Generally, iron counts from fluids containing dissolved sulfides or dissolved oxygen are not reliable because of precipitation of iron sulfide or iron oxide solids that may deposit on metal surfaces as well as remain suspended in solution. Although the iron counts may vary over time as temperature, hydrogen sulfide (H2S), or oxygen levels vary, the iron count value actually represents the solubility of iron and not the severity of corrosion upstream from the sampling point. Therefore, the use of iron counts as a corrosion-monitoring method must be validated for each specific use.

Proper safety precautions when dealing with sour systems are addressed in API⁽²⁾ RP 54.4 Appendix A (nonmandatory) covers safety considerations when handling H2S, and information on the toxicity of this gas.

⁽¹⁾ ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959.

⁽²⁾ American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070.