Down Hole Tubing And Casing Material Selection
Selecting the appropriate materials for downhole tubing and casing in offshore production wells is crucial to ensure the long-term reliability and integrity of the wellbore. Offshore wells present unique challenges due to harsh environments, high pressures, and corrosive fluids. The selection process involves considering factors such as mechanical properties, corrosion resistance, temperature resistance, and cost-effectiveness.
Production wells, injection wells, and conversion/turnaround wells are the three main types of wells. Each type of well presents its own set of issues that necessitate a specialized approach to material selection.
The safety and efficiency of oil and gas extraction as well as integrity rely heavily on tubing and casing. Offshore, corrosion-resistant alloys (CRA) are used because reservoir fluids running through production tubes are generally corrosive. Corrosion-resistant alloys (CRAs) are much more expensive than carbon steel because they contain varying proportions of Ni, Mo, Cr, Cu, and other metals for corrosion resistance (CS). The casing is often much larger in diameter and heavier in weight than tubing because of its primary function of ensuring the well’s structural integrity. In most cases, reservoir fluids don’t come into contact with the casing, thus cheaper carbon steel or lower-alloy CRAs can be used. Carbon steel may not be the best material for every application, and the CRAs that are deemed acceptable will change depending on the specifics of the environment.
Production casing and production liners are two popular well designs depicted, A Production liner is suspended from a lower piece of production casing, whereas production casing ties back to the surface. Well, collapse is avoided and secondary spill containment is ensured with the help of a production liner and production casing. For this reason, carbon steel casing approved for sour service is the standard to follow. Casing made of carbon steel is commonly used, but this material may not be ideal for every good configuration.
While carbon steel is used for almost all casing and liners, the material chosen for the tubing should be used wherever possible in the tiny piece of casing that comes into contact with the reservoir fluids. Some well designs have this part perforated and used for production, while others use it solely to maintain the integrity of the wellbore and cement it in place. It is not anticipated that the created fluids will come into contact with the surface, outer, or intermediate casing, all of which are used for structural integrity.
While making a material choice, safety in deployment is of paramount importance. Capital expenses (CAPEX) and operational expenses (OPEX) are weighed to find the optimal balance that reduces total lifetime cost, which is then used to refine the selection process even further. The material selection procedure also takes into account constraints like lead time, quality assurance, and schedule.
Methodology for Selecting Materials for Use Downhole
It is possible to identify whether a CRA is necessary with knowledge of only a few criteria, such as the presence of carbon dioxide (CO2) or the location, design life, or existence of elemental sulfur, but this is insufficient knowledge to determine which CRA should be selected. CO2 is the primary indicator of whether carbon steel material can be effectively used for manufacturing tubing because CRAs are fundamentally resistant to corrosion owing to CO2. The rate of tubing wall loss and the subsequent need for workovers are both influenced by CO2 partial pressure (and temperature).
The number of workovers anticipated for the well can be calculated using this data and the well’s design life. The generic location-based workover prices supplied in Table 1 show how much of an impact location has on workover costs when tube replacement is necessary.
Offshore, corrosion inhibition is a high-risk operation that requires a lot of OPEX and often requires the use of carbon steel tubes with downhole corrosion inhibition instead of a CRA. Because of its strong corrosivity, elemental sulfur necessitates the rapid installation of CRA tubing regardless of the offshore location. Due to the importance of factoring in workover cost, location is generally the single most influential influence in material selection.
Choosing an Alloy That Won’t Rust
Due to the longer expected service life and lower operating costs associated with CRAs, they are the standard for offshore production well tubing. Because it will be subjected to the same corrosive conditions as the production tube, the exposed casing is typically made from the same material.
Martensitic stainless steel (MSS), duplex stainless steel (DSS), super austenitic stainless steel (SAS), and high nickel alloys (HNiAl) are the four families into which CRAs fall according to their corrosion resistance and cost. All CRA casing and tubing alloys are secret formulas with the sole exception of API 5CT L80 13Cr steel.
The presence of elemental sulfur and other conditions, such as H2S partial pressure, chloride concentration, and temperature, are used to determine which CRA family will be used. After considering these factors, together with any specific usage history or statistics, a final decision is made.
Production and shut-in environment variables like temperature (bottom hole and shut-in), pH, chloride concentration, and H2S partial pressure will guide the final material choice. It’s crucial to be able to tell the differences between the various temperatures. One of the most common factors in deciding which materials to use is the bottom hole temperature (BHT). However, when the well is shut in and the temperature has dropped to that of the seafloor, the corrosive nature of the produced fluids at the well’s top may alter, suggesting the use of a different material there.
The choice of materials may need to be reconsidered if new specifications or needs are introduced. They have more to do with time constraints, material characteristics, and financial factors.
Materials can be chosen according to the methodology mentioned, however, fitness for service testing is necessary if there is no data to show the alloy is suitable for use in the environment. Typical approaches used to determine fitness for duty include:
- Compliance Testing for a Sour Service
- Method A Cracking Testing by NACE
- Testing Using NACE TM 0177 Method C
- Tensile Testing at Low Strain Rates (NACE TM 0198)
Conclusion
The process of choosing materials is complex. Outright improper materials can be weeded out and a general selection can be made with the help of a primary evaluation based on environmental and operating conditions. Risk assessment, where a balance must be found between tolerable risk and acceptable expense, is often used to make the final selection when there are multiple viable possibilities.
