The second article in this series from ICorr Fellows who have made a significant contribution in the field of corrosion science is by Don Harrop, Past President and Honorary Fellow of ICorr and the European Federation of Corrosion (EFC).

Corrosion Inhibitors in Upstream Oil and Gas Production

The use of corrosion inhibitors to mitigate the threat of internal corrosion affecting the design and operation of upstream oil and gas production infrastructure and facilities has proved to be a successful, resilient, flexible and cost-effective means of managing that threat over the past 60+ years.

A corrosion inhibition system generally requires relatively low capital outlay but carries a continuous whole life operating cost associated with ongoing cost of chemical, deployment and injection system management and associated maintenance, and supporting corrosion monitoring and inspection. Viewed on an NPV (net present value) basis, usually makes the use of Carbon and Low Alloy Steels (CLASs) together the most economically attractive option at the design stage of project – the base case consideration, a position unlikely to change in the future.

The history of the use of corrosion inhibitors has not been without it troubles, certainly in the early years when going through a learning curve of sound fundamental understanding of how they function versus meeting user demand. However, issues should they arise are now generally associated with insufficient or poor attention to managing inhibitor application and not per se inhibitor performance. Application is not just about the technology and method but how it is then consistently managed: it is a “cradle to grave” commitment and certainly not a “fit and forget” option.

The benefits of chemical corrosion inhibition can be summarized as:
Cost effective – can be sensitive to how the economics are calculated but generally it is the most capex efficient option.
Extend use of materials with established and favourable engineering properties – primarily talking about use of CLASs.
Flexible response – can be adjusted to meet changing operating conditions.
Retrofit treatment – response to unexpected increase in system corrosivity, a change in service conditions and/or life extension.
Assurance – where there is limited access/opportunity for inspection and/or corrosion monitoring
Can be applied to sweet (H2S free) and sour (H2S containing) systems, but the presence of even very low levels of oxygen (ppb level) can adversely affect performance of most inhibitor species, as can high temperatures (>~150 C).

What are they?

Commercially supplied corrosion inhibitors are formulated products. Typically, they contain 10% to 25% active inhibitor species – N, S O or P functional long chain organic compounds. A product’s primary constituent is the carrier solvent which is key to effective inhibitor deployment in a system. The formulation is a critical element affecting efficacy of performance versus specific application, and why there is not, at least so far, a “silver bullet” corrosion inhibitor suitable for all applications. Consequently, undertaking appropriate testing/screening of products is an important precursor to making a final choice for field application. Other formulation considerations to note are: low toxicity to humans and compliance with environmental legislation (e.g. OSPAR regulations in Europe), high flash point for reduced hazard when handling, temperature stable for storage in hot (60 C) and cold (-40 C) climates, non-corrosive to metals used for storage and application of the neat product – may require the use of stainless steel lines and internally lined storage vessels, compatible with elastomers that are used in the injection system – does not cause excessive swelling, cracking or hardness changes, and non-foaming and non- emulsifying to treated fluids.

Strict adherence to a definition of a formulated inhibitor product being truly or exclusively soluble verses dispersible when considering application can be a grey area and care needs to be exercised. A formulated inhibitor will partition to a varying degree between the liquid phases present – viz. oil and water – and the ratio thereof will influence the actual concentration of inhibitor present in the aqueous phase even if an inhibitor product is designated as water soluble. Produced product solvent, temperature, pressure and flow conditions will also affect partitioning behaviour.

Selection and application

The operating conditions and constraints under which an inhibitor will be required to work must be understood and defined, not least because:
They will determine the methodology and scope of the test programme required for sound inhibitor selection.
They will determine the criticality and order of importance of factors affecting performance – e.g. if compatibility with another production chemical(s) is likely to be an issue, then it needs to be decided which one can a compromise on performance be accepted if unable to find a fully compatible optimum solution.
If the operating system to be treated has already experienced a level of corrosion damage this can be more challenging to manage to an acceptable level of inhibition.
Flow regime will influence the effectiveness of deployment in the field and influence the location of potential corrosion hot spots – e.g. sharp bends; dead legs.
Poor system cleanliness can be detrimental to inhibitor performance – e.g. build-up of solids, presence of wax or scale.

In recent years much effort has been directed at the development of test methods for studying and evaluating corrosion inhibitor performance. This has resulted in increased sophistication, especially when combined with use of ex situ and in situ surface analysis techniques, while being manageable and not excessively expensive to establish and run in a conventional laboratory environment. Good background reading and reference can be found in: EFC Publication #39 – The Use of Corrosion Inhibitors for Oil and Gas Production; ASTM G-170-06, 2012 – Standard Guide for Evaluating and Qualifying Oilfield & Refinery Corrosion Inhibitors in the Laboratory; NACE International Publication 1D196, Item No. 24192, 1996 – Laboratory Test Methods for Evaluating Oilfield Corrosion Inhibitors: Technical Committee Report, Task Group T-1D-34; UK Health & Safety Executive, Research Report RR1023, 2014 – Reliable Corrosion Inhibition in the Oil and Gas Industry.

Whether one or several test methods will be needed to generate data suitable for making a final selection for field deployment will depend on the complexity of the field conditions. For field conditions that are particularly complex, and the infrastructure/facilities are of high criticality, then it may be deemed necessary to conduct final inhibitor testing/selection using a large diameter flow loop able to simulate multiphase flow. There are only a limited number of such facilities available; for example, in the USA at Ohio University and the University of Tulsa, and in Norway at the Institutt for Energiteknikk (IFE).

Inhibitor performance is commonly expressed and measured in terms of efficiency – the percentage amount an inhibitor can reduce the uninhibited corrosion rate when present at a given concentration, usually the optimum concentration to achieve maximum efficiency. (NB. The uninhibited corrosion rate is often that measured in the lab or predicted using a corrosion model as actual field measurement may not be possible or desirable!) Given the organic structure and molecular size of inhibitor molecules, inhibitor efficiency typically is in the range 95% to 99% due to the spatial limitation of how well they can closely pack by adsorption on a steel surface to form a protective monolayer film. However, it is a common expectation at the design stage that an inhibited corrosion rate of 0.1mm/y to ≤0.5mm/y is consistently achievable which in turn will drive the monitored inhibited corrosion rate KPI throughout field operating life. This residual inhibited corrosion rate must be safely accommodated as a corrosion allowance within wall thickness for a given design life or required remaining field life.

The most effective and resilient and directly manageable method of inhibitor application is by continuous injection. However, underdosing and/or extended interrupted injection (>24hr) can adversely affect inhibitor film persistency/coverage that may result in localised corrosion or complete loss of protection.

In conclusion

It is perhaps not unreasonable to claim that the advent of oilfield corrosion inhibitors back in the 1950’s and their subsequent development has resulted in a significant enabling technology for the cost-effective development and successful growth of oil and gas production. Looking back, some may even claim inhibitors to be ‘a game changer’ technology! Going forward, with new projects exploiting reservoirs with fluids of increasing complexity and more aggressive environments, consistently achieving high inhibitor efficiency of performance and application will be paramount to economic project delivery and integrity risk management.