With the discovery of oil and gas in water depths greater than 1000ft (305 m) the material selection process has become more difficult and complicated when compared to the similar process for land based operations. The costs associated with a failure in deep water are expensive and have environmental implications. Deepwater projects consist of both direct vertical access (DVA) wells and subsea projects that are completed several miles away form the host platform and tied back to it via a flowline and riser. Historically, materials were needed to handle corrosive service consisting only of H2S, CO2 and chlorides. With deep-water wells and subsea systems that are being drilled and completed and subsea systems being installed, chemicals are required to minimize paraffin, asphaltene, hydrates, and scale formation and provide corrosion inhibition. These chemicals however, may have adverse effects on metallic and non-metallic materials. The problem is compounded when materials have to be selected to handle produced fluids, annular fluids, and the injected chemicals. In subsea systems the effects of hydrogen embrittlement from the cathodic protection system also have to be taken into account. This paper will cover approaches taken for selecting materials for subsea production applications.


Projects in the deep water of the Gulf of Mexico have moved the consideration of materials selection into the arena of high reliability. No longer can equipment and the alloys from which they are manufactured be chosen on a limited life expectancy. In the past alloy selection could be based on a two to five year life after which time, the equipment could be pulled and changed. Now, a 20- year life with high reliability is common. A minor problem with a part either due to corrosion or poor design can result in a multi-million dollar work over that is unacceptable for the project viability. This type of reliability requirement has resulted in project consideration of the effect of produced fluids, annular fluids, injected chemicals, and the interaction of all these fluids on the materials selection for the equipment used in production operations. The use of these fluids impacts alloy selection for packers, S SSV's, injection lines, wellhead components, jumpers, the production manifold, sled components, and the flowlines. Not only is the typical corrosion environment of a project a necessary input for alloy selection, but also operational fluid injection and production information is needed.

This paper covers some of the considerations that come into the alloy selection for wellheads and valve bodies. A similar exercise occurs for every component in a subsea system. In the selection of materials for wellhead equipment the following considerations have had to be taken into account: (Ref 12).

· Composition of produced fluids in contact with valve body and internal parts - all wetted parts from downhole to the flowline require identification

· Service temperature

· Operating pressure ranges

· Galvanic effects due to contact of dissimilar materials

· Crevice corrosion resistance at seal and flange faces

· Wear and galling resistance of moving parts

· Temperature and chemical resistance for non-metallic materials

· Cathodic protection (CP) on materials

· Effectiveness of coatings on materials

· Weldability for weld overlay

· Material availability and cost

· Compatibility of materials with injected fluids


Consideration for wellhead and Christmas equipment for subsea applications include such factors as environment of the produced fluids, pressure, operating temperature, and PSL (Produ

This content is only available via PDF.
You can access this article if you purchase or spend a download.