?Many high-pressure/high-temperature (HP/HT) wells have been drilled and completed onshore Texas and Louisiana and in the Gulf of Mexico. However, the presence of small amounts of hydrogen sulfide (H2S), typically in the parts-per-million (ppm) range, has caused considerable difficulty in the completion of such wells in compliance with the National Association of Corrosion Engineers (NACE) specifications for MR0175/ISO 15156.


The primary and most recognizable limitation this standard imposes is the 0.05 psia H2S partial-pressure threshold for sour service. For example, for a well with 15,000-psig bottomhole pressure, there need only be 3.5 ppm H2S for the standard to be invoked. The problem is that it is almost impossible to accurately measure this amount of H2S.


Because of the difficulty in accurately measuring H2S, some companies have argued that high pressure wells should be considered sour from the start. Other companies, however, have chosen to ignore the possible presence of H2S to avoid the complications created by complying with the NACE specification.


A typical example is a steel casing tieback string that ties the production liner back to the surface. This string is the first production casing outside of the tubing that can be exposed to H2S if there is a leak. Historically, this string has been designed to be compliant with the NACE standard.


In HP/HT wells, the production tieback is often casing with outside diameters that can be as large as 10 3/4 inches, with wall thicknesses sometimes exceeding 1 inch. This size is required to contend with the combined axial loads and collapse or burst loads. Also, there is a requirement for a subsurface safety valve in this location that has an outside diameter larger than the tubing, so the tieback string must have an inside diameter that is large enough to accommodate the valve.


In designing HP/HT wells, API 5CT Grade Q125 casing can be required for strength. However, since Q125 steel has no resistance to sulfide stress cracking, a heavier wall C110 steel casing, which is currently a non-API sour-service grade, can often handle the mechanical design. The problem is that NACE MR0175/ISO 15156 prohibits C110 steel from being run to the surface, thus restricting its use to depths where the temperatures are ?150 degrees Fahrenheit. Using T95-grade steel is the only way to meet the standard for all temperatures, all the way to the surface. This restriction in materials is extreme, and it creates serious technical issues.


For example, even if 85?8-inch outside diameter 1-inch wall thickness C110 steel would suffice for the tieback casing, it could not be used because it cannot be run to surface. Instead, T95 steel would have to be used. The T95 steel would have to have a wall thickness of 1.187 inches to maintain the appropriate mechanical loads, which translates to a reduction in inside diameter. The decrease in inside diameter generally causes dimensional issues and constraints, such as insufficient room for the subsurface safety valve, which cannot be easily overcome. Increasing the wall thickness also leads to manufacturing limitations of the steel. At some point, the wall thickness required simply cannot be manufactured.


Some oil companies are choosing neither option. Instead, they are running C110 steel to the surface. However, less conscientious companies ignore these issues and run API 5CT Q125 casing that has no resistance to sulfide stress cracking. While it is recognized that the NACE standard has a provision to tests alloys for specific well applications, and use the results to justify the use of those alloys that are not compliant, the reality is that, except for a few major oil companies, this is rarely done. Instead, companies select alloys based on manufacturers’ test data and brochures.


If NACE MR0175/ISO 15156 is to be upheld as a standard, the industry must begin to put it on a scientific footing instead of relying on old rules.


Selection of the 0.05-psia limit was an empirical choice based on experience and has worked for many years.


However, it is now recognized that, at high pressures, the partial-pressure approach is not correct, and fugacity along with reduced solubility of H2S due to methane influences must be used to evaluate potential for sulfide stress cracking. Until the industry carries out a formal scientific study that elucidates the correct means to address the potential for cracking based on H2S content, fugacity and pressure, the inability of the NACE standard to correctly predict the sulfide stress cracking of high-strength components will result in the increasing irrelevance of the standard.