The industry trend towards drilling hotter, deeper, and more corrosive wells has not been accompanied by the technical information required to evaluate and certify tubular connections for such service. In some of the wells, the pressures exceed 20,000 psi, the temperatures are around 450F, casing tensile loads exceed one million lbs., and there are high concentrations of CO2 and H2S present. These conditions require a high degree of integrity in tubular connections. Current efforts by manufacturers to analyze and test available connections to establish their service ratings under such conditions have been limited. This paper discusses one tubular good user's view of what testing needs to be done by manufacturers to determine the service conditions within which a connection can be expected to operate successfully.
Drilling has come a long way from "Colonel" Drake's 1859 well in which he drilled 69 feet in four months. Today, for example, we have the Soviet Union's SG-3 well which is targeted for 49,000 feet (15,000 meters). The SG-3 well was spudded in 1970 and had reached somewhere around 36,000 feet in 1982. The industry as a whole is tending to deeper and deeper wells.
Depth is not the actual cause of concern, however. The loads and environments associated with depth are. The high temperatures, high pressures, high tensile loads, and aggressive environments that these wells pressures, high tensile loads, and aggressive environments that these wells have to endure are critical to the success of the well. Endure is a keyword too; to be an economic success, a well must be safely completed and must be capable of long-term sustained production. This is especially true for the hot, deep, or corrosive wells where costs to repair are quite high. Figure 1 shows how drilling costs have risen as a function of depth drilled. Sustained, trouble free operation is the only way we can guarantee a good economic picture.
Operations at these higher temperatures and pressures make the situation quite complex. Drilling or produced fluids, for example, which contain small amounts of CO2 would not significantly affect steel under normal conditions, but under high pressures and temperatures it may be quite detrimental. Increased stresses in these applications also complicate the sulfide stress cracking problem.
While American Petroleum Institute (API) connections on API tubulars haveserved the industry well for many years, the lack of verified performance data over the complete range of sizes, weights, and grades under more severe conditions is limiting the use of these non proprietary connections and tubes. In an attempt to satisfy the need for improved reliability under more severe environmental conditions, there has been a proliferation of "proprietary" connections and tubular materials. These connections and materials, however, have their own set of limitations which often have notbeen clearly defined. Several of these proprietary connections have failed either in the field or the laboratory under conditions below their rated capabilities. Several hypotheses may explain these unexpected failures.
Connection designs have been extrapolated too for to different size, weights, grades, or materials.
Inadequate testing has been performed to validate the performance(design) model used to extend these designs beyond the size, weight, grade or material tested.
Production quality control or post-manufacturing inspection has notbeen adequate.
The connections have not been applied or installed properly in the field.