Top of Line (TOL) corrosion occurs in multiphase wet gas systems when water vapor contained in the gas phase condenses on the internal upper pipe walls. This happens due to the heat exchange occurring between the pipe and colder surroundings (river water, seawater or cold air) if the pipe is not thermally insulated or buried at a reasonable depth. The condensed liquid then becomes enriched by the corrosive species naturally present in the gas stream and assumes a low pH because it does not contain any buffering species such as bicarbonate or iron. The predominant concern is carbon dioxide (CO2), which reacts with water to form carbonic acid (H2CO3), although hydrogen sulfide (H2S) can also present significant challenges. As TOL corrosion occurs in wet gas lines operated in stratified flow, the corrosion inhibitor or other corrosion protection chemicals such as mono-ethylene glycol (MEG) injected into the system remain at the bottom of the line and are not able to protect the top of the line.
The difficulty in selecting the materials of construction for the topsides portion of seawater injection systems is associated with uncertainty around the reliability and performance of their associated oxygen removal systems.
Common material selection options for seawater injection systems include carbon steel, stainless steels, copper-based alloys, and composites. Other materials, such as titanium and high nickel alloys, may be used in niche applications, but their increased cost ensures that these are not the first line materials of choice.
Corrosion modeling can be performed very early in project development to estimate the feasibility of carbon steel use. It can also augment many different aspects of the design and operations of sweet flowlines. To achieve this, data used for corrosion modeling must be sourced and attributed to the task in question.
CO2 corrosion modeling is a common practice to evaluate carbon steel flowlines and piping, both with and without inhibition, to ensure they achieve their intended design life. Modeling is also used to help determine if a corrosion resistant alloy should be used and can also be utilized to determine corrosion allowance and inhibition requirements.
Reservoir souring is defined as the generation of hydrogen sulfide (H2S) by bacteria in the reservoir following water injection. A number of factors can influence rates of reservoir souring at producers, including, but not limited to, the location of injection and production wells; reservoir geology; formation water, aquifer water and injection water composition; pressure and temperature; biological control in the injection and production systems; and drilling practices. Proactive and reactive souring control methods can be adopted to prevent, control or alleviate SRB activity or H2S production (Note summary to left).
For most offshore facilities and subsea components such as trees and manifolds, carbon steel is a common material of construction. Effective external corrosion control is essential for the longevity and safe operation of these components.
For long-term external corrosion protection of subsea steel components, cathodic protection (CP) along with corrosion coatings are commonly used. As the offshore environment moves into deeper waters, the cost of interventions subsequently increases. Therefore, the engineer is challenged with balancing a highly reliable CP system, sometimes achieved with excess anode mass, with CAPEX and weight restrictions. The optimal CP system will need to minimize weight and cost and maximize reliability.
Of all the corrosion resistant alloys (CRA) used in oil and gas developments, martensitic stainless steels (MSS) are some of the most common. These steels not only have the advantages of normal steels: high strength, cost effective, easy to manufacture, available in a wide variety of product forms, but they also have good CO2 corrosion resistance at higher temperatures as a result of their 11% minimum chromium content. One of the most common types of MSS used in the oil and gas industry is 13% chromium steel. NACE and API standards both reference several different varieties of 13 chromium steels for use in oil and gas projects.
The offshore use of flexible pipe in oil and gas production has been steadily increasing since first used in the 1970’s. Initially used in North Sea and North Slope applications, the use of flexible pipe is beginning to expand to other locations as new fields are discovered in ever more challenging locations. In particular, the expansion of the industry into deeper waters has been accompanied by the need to accommodate demands such as higher operating temperatures and pressures, higher carbon dioxide (CO2) and hydrogen sulfide (H2S) acid gas concentrations, different completion and acidizing fluids, and water injection. One of the most significant challenges is that materials exposed to H2S need to be qualified for sour service. Metals are often limited by their yield strength or hardness and any welds in H2S, and polymers are limited by H2S permeability and degradation resistance.