Now its time to assess the TOLC risk and the corresponding locations in the system where TOLC may occur. From there we can determine the appropriate mitigation and control strategies.

In Part 2 of this GATEKEEPER series, we will look at the different approaches available to assess risk in the system and will discuss the mitigation options available to us.

In determination of consequence and risk assignment, multiple aspects are considered such as the impact of failure on the health and safety of personnel and community in the impacted area, environment, cost of recovery (cleaning, maintenance, extent of operation, repairs) and business.

Oil well stimulation is commonly undertaken using aqueous solutions of hydrochloric acid (HCl), hydrofluoric acid (HF), organic acids or mixture. The use of these acids will open new channels near the wellbore region for the oil and gas flow through and will result in increased production.

In this GATEKEEPER, the philosophy around the materials selection and corrosion monitoring is discussed as the primary design barrier to corrosion and cracking in critical parts of a subsea system.

Acidizing involves pumping acid into a wellbore or geologic formation that is capable of producing oil and/or gas. The purpose of acidizing is to improve a well’s productivity or injectivity after production has declined 4.

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.

Top of Line Corrosion (TOLC) occurs in deepwater wet gas systems when water vapor condenses on the upper internal walls of the flowline due to the heat exchange occurring between the hot fluid and the colder environment.

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.

This GATEKEEPER will discuss the basic factors influencing corrosion modeling, while a later installment will elaborate on the different corrosion models available and their respective advantages and limitations.

Corrosion in field conditions can be extremely slow, thus accelerated test methods have been designed to enable evaluation and prediction of long-term corrosion behavior. In general, corrosion testing is conducted by exposing small samples of a material to the desired environment for a relatively short period of time, then evaluating the type and severity of corrosion in order to select materials or chemicals that will maximize the life of the part in question.

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.

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.

Umbilical functionality is critical to proper operation of subsea production systems, and for this reason it is important to properly select materials and corrosion protection options for this service.