Working With Coiled Tubing in H2S and CO2 Wells: A Global Perspective

Abstract

Abstract The use of coiled tubing (CT) in wells containing hydrogen sulfide gas (H2S) has associated problems because of the potential for sulfide stress cracking (SSC) of the CT material. Carbon dioxide (CO2) can also contribute to general corrosion or intensify any H2S-related corrosion because of chemical reactions resulting in acid. However, with the right precautions, equipment, and procedures, this type of operation can be carried out safely and successfully. The various problems associated with working with CT in H2S and CO2 wells are discussed and a general best practice taken from locations working regularly with H2S and CO2 is presented. This paper shows the equipment, chemical inhibitor, quantity and method of inhibitor application, and other precautions taken to carry out the work safely and successfully. An alternative approach is also highlighted for some situations whereby any H2S is bullheaded into the well before coiled-tubing intervention. This alternative approach avoids any contact of H2S with CT to prevent corrosion. A number of case histories are shown for different H2S and/or CO2 locations around the world, which detail the type of operations, quantity of H2S and CO2, procedures used, frequency of operations, and the overall success of these methods in ongoing operations. This paper presents a review of methods and equipment currently being used around the world to work in potentially corrosive and dangerous H2S and/or CO2 wells. Introduction The prevention of CT failure is of utmost importance for both safety and economic reasons; CT failures in acid or sour environments can generally be avoided if certain precautions are used. Previous research done in SPE 93786 (McCoy 2005) and SPE 99557 (McCoy and Thomas 2006) has identified acceptable working ranges of pH and partial pressure of H2S gas (PH2S) with both 90 and 100 grades of CT. This paper will build on this previous research and highlight the correct procedures and equipment to use when working in H2S and CO2 environments. Case histories from the previous two years will also be presented and summarized to show the type and frequency of work that has been done in these conditions. Several recent cases are also presented that highlight the need to follow these guidelines when working in sour wells. Coiled Tubing Corrosion in Acid and Sour Environments Oilfield production fluids containing the acid gases H2S and/or CO2 can be corrosive to CT because of the resultant lowering of the pH of the aqueous phase. Low-pH aqueous fluids accelerate corrosion by providing a plentiful supply of hydrogen ions. Any brines in the production fluid will also increase the overall corrosivity to the CT, as well as provide an aqueous medium for contamination. Thus, H2S and/or CO2 in brine is more corrosive than the same gasses present in oil. Alternatively, because an aqueous phase is necessary, the risk of corrosion or cracking in dry gas wells containing these gases is low. Basically, H2S mixed with water will produce sulphuric acid when oxidized or a weaker acid when no oxidizer is present. CO2 produces Carbonic acid when mixed with water. H2S is noncorrosive in the absence of moisture. Other than wall thinning from general corrosion, there are several failure modes that can occur when CT is exposed to H2S-containing fluids. These are detailed in Appendix A and can all be directly related to hydrogen entry into the tubing metal structure. Unless otherwise stated, this paper will concentrate on the issues associated with SSC-type failures. Suitable Coiled Tubing Selection Grade 80 CT will tend to show less susceptibility to SSC as compared to higher-strength grades but is not immune to problems in H2S-containing environments.