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Offshore and subsea corrosion and integrity management

asked Aug 18, 2014 in Quality Assurance by ekwuemesam (3,660 points) | edited Aug 18, 2014 by ekwuemesam
Knowledge sharing on offshore and subsea corrosion and integrity management based on past experience and lessons learned.

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answered Aug 18, 2014 by ekwuemesam (3,660 points) | edited Aug 19, 2014 by ekwuemesam

As there are no codes or standards on offshore/subsea corrosion and integrity management, therefore common practices and experience come into play to strategize and define methods for monitoring and evaluating corrosion and integrity management.

The first step in the Corrosion Management Strategy program that is usually based on corrosion modeling analysis. The Norsok M506 software which is widely accepted as an international standard for corrosion model.

The Corrosion Management Strategy typically includes the followings:

  • Corrosion assessment appraisal and localized activity
  • Material selection for initial design and considerations for materials performance
  • Asset corrosion (including environmental cracking) and integrity related functions
  • Appraisal of design interfaces, mechanical connections, mixed materials, welding, etc.
  • Process safety impacting corrosion and degradation
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answered Aug 19, 2014 by pasmith (3,320 points)

There are several corrosion assessments based on modeling and incorporation of industry data, perceived issues as they are considered relevant. Additionally material and corrosion matters will be related to mechanical integrity, localized corrosion evaluations, identifying where necessary the need for field or accelerated laboratory testing, as well as inspection and on line monitoring.

Corrosion Modeling Assessment

Corrosion modeling is typically performed using Norsok M506 modeling methodology to estimate the base case uniform CO2 corrosion rate. It is considered by industry to be quite conservative, but offers a good interpretation of general (uniform) corrosion rates.

The M506 model does not give guidance or interpretation for localized corrosion; however, the analyses has much general value, especially regarding extreme cases of high or very low CO2 corrosion susceptibilities.

Generally we can infer that any corrosion resistant alloys (CRAs) selected will not require corrosion inhibition, but for any mixed systems including carbon steels corrosion control will require an inhibition approach incorporating an appropriate level of monitoring, inspection, and maintenance.

The detailed corrosion analyses must look specifically at all localized corrosion threats such as microbial, galvanic, mesa, or crevice corrosion type mechanisms coming into effect in addition to base CO2 corrosion. These will mainly be operative in contact with carbon steel (piping and vessels) and so that interface must be attended, ideally by a combination of coating, monitoring and chemical combination. Other physical reasons for using CRA must be assessed for specific geometries such as dead legs, erosion, corrosion under deposits, external marine atmospheric corrosion, etc.

Steel and Inhibition

Regarding steel based parts, necessitated by higher pressures, certain systems will require corrosion inhibition using vendor recommended chemicals. These may be off the shelf, or specifically tailored to address mixed chemicals (cocktailing) performance. As a rule, the dosages applied will need to be of an adequate residual allowing for optimum efficiency of the corrosion reduction mechanisms. This is a critical matter as the distribution of inhibitor will be subject to non-uniform filming due to changing flow regimes, geometry and layout of piping and vessels etc.

Corrosion Control

Distribution of corrosion probes and coupons should be used to ensure that all wetted parts of systems are covered to give a wide and accurate measure of the corrosion status of all systems. Prior to the selection of any inhibitor mixture or formulation being used, the chemicals will need to be validated as being fit for purpose for the mechanisms of corrosion predicted.

The periods of inhibitor “loss-age” are dependent on the flow patterns in play at the time of the inhibitor loss of injection. But it is reasonable to assume that most “cathodic” (acting on cathode reaction sites) and filming inhibitors will be sufficiently successful in that regard.

Some dangers exist if the inhibitor mixture is effectively under anodic control (acting on anodic reaction sites alone), and under certain circumstances of low dose-age it is thought that accelerated pitting may occur due to an adverse anodic/cathodic area ratio. If that occurs rapid loss of wall may occur.

Flow Velocity and Shear Stress

The Corrosion Management Strategy must assess water entrainment tendencies for multiphase flows, and derive water droplet entrainment tendencies. Thus re-entrainment propensity will be best defined by some discrete flow assurance predictions (e.g. Olga/Hysis) to determine water wetting areas or sites, as well as areas subject to high fluid shear stresses (beyond the 150Pa as limited by Norsok M506).

Corrosion Integrity

It is suggested that once production has started the corrosion modeling routines can be re-visited and actual flow rates, flow regimes, etc. can be re-calibrated against monitoring and inspection data, as well as non-dimensional analyses to help determine corrosion risks as they may occur, and therefore give the company opportunity to respond in a timely manner and address any corrosion issues as early as possible.

Dead legs and stagnation

Most facility piping will have tight layouts, and there will likely be some geometry related to deadleg or laminar flow zones. The role of such deadlegs and semi-stagnant flow regime zones will present a challenge since inhibitors are often known to exhibit a loss of efficiency under such areas as active bacterial species in the formulation are depleted in such occluded areas. Therefore inhibitor distribution and replenishment are of critical importance of for all steel piping. The planned use of frequent fluid sampling will be an important part of the future more detailed Integrity Management process.

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answered Aug 19, 2014 by pasmith (3,320 points)

Materials Options and CRA

The selection of fit for purpose materials and CRA is always a difficult task; often based on the technical arguments regarding inherent corrosion resistance, surface oxide passivity properties, loss of mechanical properties, etc. But more frequently, the differentiating arguments are based on cost, schedule and timely availability.

Appropriate CRA must be selected for critical items as identifiable by the preliminary corrosion assessments in relation to the 25 year life with minimal expectations of corrosion or degradation. That argument is often based on the efficacy and economics steel plus inhibitors as compared to the use of inherently safer design, whereupon higher grades CRA are used, with an accepted higher upfront costing (CAPEX). Nevertheless even high grade CRA will still need some monitoring (less stringent) in all its forms; solid, weld clad, mechanical overlay and especially at any interfaces with steel, etc.

Regarding piping and equipment, some differences in the methods of monitoring and corrosion integrity assurance will exist and those will need to be identified as part of the detailed IM plans. For example, piping will rely primarily on U/T spot and area based measurements, as well as rigorous fluid sampling, testing and flowrate monitoring whereas equipment such as heat exchanger shell and tubing, rotating parts and pump impellers will need more particular attention based on regular inspection, and maintenance; perhaps more in line with mechanical condition monitoring.

Materials Performance

Once the mechanical materials selection is made, it will be prudent to appraise the corrosion integrity performance over the life cycle as best as is practicable. This will include the integration of materials corrosion data with industry experience data so that the Corrosion Management Strategy approach allows the asset to operate efficiently with best attendance to degradation issues (which may be expected over the life cycle) before they develop into difficult production impediments.

It should be noted that with respect to industry experience primarily in the GOM, final material selection should include a consideration for the impact of other parameters especially, H2S* (ppm levels and likely increases), chlorides (ppm levels expected and their fluctuation), and sand or particulate content (size, concentration, sharpness etc). It should be noted that since most corrosion models do not address H2S corrosion directly nor factor for chlorides, both of which can be corrosion accelerators.

Note*: The ISO 15156 addresses sour cracking only and not weight loss or metal dissolution per se. Thus whilst sour service cracking is NACE/ISO ‘code’ driven; the sour corrosion aspect will draw heavily from published research, which suggests that small amounts of H2S (for example <20 ppm for these type environments) can be beneficial due to an enhanced surface passivity type phenomena; but concentrations >50 ppm appear to have a tendency to accelerate sour service corrosion (pitting). 

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