American Petroleum Institute (API) 5CT high strength steels are extensively used for casing strings inwells subjected to high cyclic hydraulic fracturing loads. While non-sour grades of API steel such as P110 casing strings have been used satisfactorily for well construction, standard API P110 connections have seen higher rates of failures than pipe body failures in shale wells that require hydraulic fracturing.
The increased use of dynamic risers as an enabling technology for the movement of the oil and gas industry into the deepwater basins of the world has presented new technical challenges related to the prevention of corrosion failures and other forms of degradation. This has been particularly evident when considering production from the next generation of high pressure/ high temperature (HP/HT) subsea developments in locations such as the Lower Tertiary trend in the Gulf of Mexico. In order to avoid potential riser failures or replacement campaigns for anticipated service lives that may extend to 30 years or more, process facility components such as risers and flowline systems must now be subjected to more enhanced integrity monitoring through the whole of their service life.
Introduction Wells can be organized into three primary categories: production, injection, and conversion/turn-around. Material selection must be tailored to each well type, as each offers unique challenges from a materials performance perspective.
Tubing and casing are critical to the production of oil and gas and well integrity. Reservoir fluids flowing through the production tubing are often corrosive, making necessary the use of corrosion resistant alloys (CRA) offshore.
Corrosion modeling is a vital tool in the pre-Front End Engineering Design (pre-FEED), FEED, and operational stages of the life of pipeline and equipment systems. Corrosion and materials engineers often rely on corrosion prediction models to select appropriate materials for construction, incorporate sufficient corrosion allowance into a design, and evaluate chemical corrosion inhibitor requirements or recommend other corrosion mitigation methods.
Corrosion modeling is a vital tool in the pre-Front End Engineering Design (FEED), FEED, and operational stages of the life of pipeline and flowline systems. Corrosion and materials engineers often rely on corrosion prediction models to select appropriate materials for construction, incorporate sufficient corrosion allowance into a design, and establish the need for chemical corrosion inhibitors or other corrosion mitigation methods.
The region in which a pipeline transitions from offshore to onshore is called a shore crossing. Often, this shore crossing zone is not very well-defined and there is much uncertainty in terms of scope and responsibilities between onshore and offshore design teams. This inconsistency can lead to issues when designing cathodic protection (CP) systems for near shore and shore crossing areas.
It is often necessary to predict the performance of a specific material in a particular environment to determine the inherent corrosivity of the system. Such tests are often substantially different from those used for corrosion inhibitor qualification, particularly in the case of the corrosion testing of corrosion resistant alloys. Predicting corrosivity is especially important when designing subsea equipment, most of which is extremely challenging to repair or replace once it is installed. Corrosion testing is a widely used method of evaluating a material’s ability to withstand specific environmental conditions.
Corrosion in MEG systems predominantly results from carbon dioxide (CO2) and hydrogen sulfide (H2S) in the produced gas phase. However, it can also be associated with the presence of dissolved oxygen (O2) in the MEG. Corrosion results in the presence of dissolved iron, which may then deposit as scale. This can plug valves and compromise the performance of heat exchangers and MEG regeneration and reclamation systems.
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.