INTRODUCTION
Oil and gas production facilities around the globe extract, process and transport an incredibly wide range of fluids. The fluids can contain a variety of species including water, Carbon Dioxide (CO2) and Hydrogen Sulphide (H2S) which can combine to form a corrosive medium. The majority of facilities are constructed from mild steel which, depending on the exact composition of the fluid, can corrode at rates exceeding 25 mm/y (1,000 mpy). In order to minimize safety and environmental risks, it is essential the fluids remain contained inside the equipment. To do this, as well as maximize the uptime and lifetime (and hence profit) of the facilities, they must be maintained in a fit-for-service condition. To keep facilities fit-for-service it is important to know the condition of the equipment at all times.
This paper provides an overview of the range of inspection and corrosion monitoring methods available to oil and gas facilities in CO2 and/or H2S corrosive environments. Every technique has benefits and limitations and it is the role of corrosion and inspection engineers to determine which technique(s) provide the most cost effective value. It is suggested that any credible mechanical integrity program will use a mixture of monitoring and inspection techniques to provide both tactical (short term) and strategic (long term) information.
Oil and gas production facilities around the globe extract, process and transport an incredibly wide range of fluids. Operational temperatures range from ambient (as low as 50°C) to over 200°C whilst operating pressures vary from high vacuum to 69 MPa (10,000 psig). Almost all operations produce water (condensed or brine) at some stage in their life. The production fluids can also contain a variety of species including Carbon Dioxide (CO2), Hydrogen Sulphide (H2S), mineral salts (e.g. NaCl), organic acids (e.g. Acetic), mineral acids (e.g. HCl & HF) and Oxygen (O2) which can dissolve in the water to form a corrosive medium. The majority of facilities are constructed from mild steel which, depending on the exact composition of the fluid, can corrode at rates exceeding 25 mm/y (1,000 mpy).
By far the most common and troublesome corrosive species are CO2 and H2S. Systems containing predominantly CO2 are often referred to as sweet while those containing predominantly H2S are referred to as sour. CO2 corrosion can attack large areas of equipment at rates as high as 6 mm/y (240 mpy). H2S corrosion is usually localized but the rates can be as high as 300 mm/y (12 in/y).
In order to minimize safety and environmental risks, it is essential that the fluids remain contained inside the equipment. To do this and also maximize the uptime and lifetime (and hence profit) of the facilities, they must be maintained in a condition appropriate for the service required. This condition is often described as Fit-for-Service (FFS). To keep facilities fit-forservice it is important to know the condition of the equipment at all times. The current condition of the equipment can be determined using inspection techniques. Inspection involves quantifying wall thicknesses and identifying defects such as cracks, pits or bulges using one or more of the available techniques. Inspection is regarded as the most accurate way to determine current equipment condition but it has an obvious disadvantage; any damage that is detected has already occurred. Inspection is therefore regarded as a lagging indicator.
What is needed is a leading indicator; something that will identify degradation is occurring and provide enough warning so that mitigation can be implemented well in advance of the problem becoming critical. This is what corrosion monitoring
