Safety from a design consideration

Leokadia Rucinski and Binder Singh

May 1, 2015

Preventing corrosion is necessary to avoiding production failures. Leokadia Rucinski and Genesis’ Binder Singh provide details.

Fig. 1: A collage of somewhat unusual corrosion phenomena, many of which are now being more openly discussed in the industry.  Images from Genesis.

As deepwater developments and ultra-deepwater operations are increasing, proactive asset integrity management is key to safety. For instance, projects at 5000ft or more, represent roughly a third of all ultra-deepwater operations globally. And projects are expected not only in deeper waters, but harsher environments, such as the Arctic.

The difficulty for both designers and operators is that the offshore environments are typically harsher, more remote and timely feedback on subsea pipelines is not readily available – compared to shallow water operations or onshore environments.

The challenge is maintaining the integrity of deep pipelines, particularly under the two extreme value conditions namely: low flow or stagnant conditions (dead legs), and impinging high velocity flows; the latter including particulate erosion and fluid cavitation. Some of the specific challenges of deepwater and ultra-deepwater drilling include mitigating high-pressure and high-temperature environments, deeper and hotter wells, and fast-moving fluids. According to SPE, planning for the presence of acidic gases, such as carbon dioxide and hydrogen sulfide, is more common in deepwater operations. The clear focus also means recognition and acceptance of the accompanying prediction and modeling challenges.

While pipeline failure can be attributed to internal corrosion around 50% of the time, external corrosion is also an issue, representing 15% of all failures.

As cathodic protection is well understood and “codified,” external corrosion is more readily addressed by the proper use of existing industry standards and practices. By contrast, internal corrosion is more complex, as solutions are addressed through knowledge management and modeling. There are many commercial and joint industry projects focused on corrosion modeling under continual development. Unfortunately, most if not all, tend to assess for general (uniform) corrosion only. However, virtually all corrosion problems are localized and often manifest in the form of pitting.

Why now?

Many of the industry’s safety improvements have, unfortunately, been the result of accidents, or “lessons learned.” Corrosion or related phenomena have been a catalyst leading to several industrial accidents: Flixborough (1974), Bhopal (1984), Piper Alpha (1988), Carlsbad (2000), Prudhoe Bay (2006), Richmond Refinery (2012). In a post-Macondo world, owners and operators are more readily open to considering such new approaches early on (capex phase).

Offshore corrosion case histories have not always been readily available, but the better exchanges of quantifiable data have led to software development with analytics and searchable benchmarking. (See collage, figure 1.)

The main root cause of the devasting 1988 accident at Piper Alpha has primarily been attributed to a failure of the permit to work. However, delving further, the planned maintenance work order was due to serious corrosion issues, which were deferred for many years to avoid interruption of production activities.

Since Piper Alpha, many changes have taken place in the industry, and the North Sea region has seen many successes, and hopefully a de facto alignment of the North Sea and Gulf of Mexico regions will help improve matters further, for the industry as a whole. The results of better overall fabric maintenance testing, inspection, more creative monitoring, and pipeline pigging will be a big plus.

Fig. 2: Comparative routes for best corrosion and integrity management. The centerline proactive is always the best option. Source: Genesis.

Managing corrosion and asset integrity

Managing corrosion and the integrity of deep pipelines is a three-fold process: proactive, ongoing and reactive.

Proactive work is becoming more common and considered economically more rational. According to NACE, corrosion-related costs for monitoring, replacing and maintaining pipelines are estimated around a staggering $450 billion for the US alone. The expense shows a clear need for closer adherence to proactive corrosion management (See Figure 2).

Proactive pipeline integrity management

Proactive pipeline integrity management generally requires multiple approaches. With a design goal of a 25-year lifetime for this type of an asset, investing up front in proactive integrity management is smart for safety reasons and necessary business sensibilities. The first of these, for cost-saving reasons, is to use conventional material (i.e. carbon steel), as its properties (malleability, welding, costs, availability) are well-established. The second option is to increase the thickness of the pipe, however, this is often costly and usually avoided for the viability of project.

However, if the fluids prove challenging, the pipeline can be lined with an upgraded metallurgy, such as nickel-chrome-molybdenum alloy. For instance, if, the calculations show an accelerated corrosion rate (usually in excess of 10mm/y) or an expected loss of mechanical integrity within an unacceptable (often pre-determined time frame), then corrosion resistant alloy (CRA) may be considered. In the latter scenario, the alloy may be mechanically sleeved, clad or welded to the internal diameter. Thus, the CRA acts as a barrier between the high-pressure, high-temperature, high-velocity multiphase flows. The selection of a CRA can be challenging and choices must be made between stainless steels, duplex and nickel based alloys. It is important to realize that the higher alloys are more resistant to localized corrosion (pitting and crevice criteria per the commonly accepted PREN, CCT, CPT, and cyclic polarization techniques).

But most importantly, none are entirely immune, and often can be made to corrode under physical and electrochemical upsets outside the design envelope. This type of simulation is often referred to as corrosion under excursions (CUE). To meet this, we again revert back to the idea of risk and the ALARP condition, where the risk of a corrosion failure or issue is deemed to be as low as reasonably practicable.

The major problem that arises in this scenario is localized corrosion (pitting by common use-age), and as mentioned earlier, modeling can be conducted to analyze this risk, which can be considerable. Still, it is an attractive and cost-effective methodology, provided the data are sensible and corroborated by appropriate field or inspection data. The field data can be used analogously to nearby fields. Reliance on parallel laboratory data is fine, but should be supported by pragmatic inspection or monitoring data, where feasible. Any proper qualification of modeling and chemical treatments must be performed with realistic controls, ideally comparing uninhibited, inhibited and modeling trends.

The fourth solution is coatings for the interior of the pipe. To date, this isn’t a truly viable option since transported breakdown deposits would degrade and/or clog the system, by creating further secondary localized corrosion cells. However, it is an option that is still being considered and coating companies are reformulating products for high-temperature and high-pressure environments.

Of course, in principle the major benefit of using CRAs is that operators don’t need to use chemicals or inhibitors. For steel alone, it is always required to have an acceptable inhibitor efficiency (typically 90-97%), and an acceptable availability (often 90-98%) for the steel/inhibitor combination to work. Prolonged periods without an inhibitor can pose a problem if new corrosion initiation cells are created or old ones are re-activated. A well-selected and applied CRA, by comparison, simply does not require that type of maintenance.

Ongoing management

Ongoing monitoring after installation plays an important role to check for the corrosion condition of a pipe or a riser. There are different assessment methods: probe, coupon, monitoring spool pigging, advanced mapping and guided wave technology, to name a few. However, there is no confident way to look at the status of subsea infrastructure. Most of the inspection is conducted visually, either subsea via ROV or from the topsides of the platform, where access is better. Often a change in monitoring technique depends on the data and trend assessment. That’s where intelligent (or smart) pigging comes into play. Pigging captures and records full length information for future trend analysis and risk-based inspection planning.

Coupons, which calculate the material loss more directly, can also be used effectively on topsides and may have application for the subsea, too. Likewise various probes, which are designed to withstand high pressure and high temperatures, can be used to measure near instantaneous metal loss (i.e. ER, LPR, potential probes). Similarly, U/T mapping and guided wave technologies are gaining ground in terms of application. Through calibration and qualification with blind controls and artificial defects is always recommended by independent third-party to verify reliability and accuracy. The growth of these and other methods all have a way of better making the case for integrated or total integrity management programs. Most, if not all, such plans ultimately save money and offer a good ROI, but it’s the improvement on existing methods and tools which are likely to provide the differentiators to capture and monetize safety and integrity management.

Overall, the subsea environment is difficult. As noted earlier, failure can also happen on the exterior of the pipe, but the biggest concern may be at the touch down zone of the steel catenary riser interface, as it connects to the pipeline. In this scenario, there can be dangerous corrosion/erosion flow at the inside of the bend; and a possible weakness in CP current delivery under shielded areas of the outside- especially if unusual microbial (MIC) activity can occur. This combination while a low-risk phenomena, can have high risk consequences if it occurs, and a plausible asset threat due to proximity of the safety critical riser component. The challenge illustrates the importance of relevant monitoring and close visual external inspection, matched by carefully internal monitoring. In principle, both can be conducted subsea by ROV with appropriate tooling.

The way forward

Deepwater operations have increased internal corrosion control, safety, and cost challenges. Starting corrosion control at inception ensures a stronger corrosion risk assessment and therefore, better lifecycle integrity management.

To date, the regulations for specific corrosion control and monitoring are still in the infancy stage, but the industry is moving forward and companies see high value in implementing integrity management programs. For instance, the role of corrosion management is strongly implicit in the North Sea and Gulf of Mexico regulations, and may be spelt out more clearly in the future.

Cultivating a safety mindset at the start of projects is crucial to ensure the participation of materials and corrosion engineers. From a mechanical integrity perspective, it is very important for engineers to think carefully beyond immediate design codes of practice since corrosion and degradation can kick in fairly soon after startup depending on the aggression of multiphase production fluids. And once engineers collectively accept the subtleties of materials performance as opposed to materials selection, the industry may be well on the way to more effective and reliable solutions all-round. Within the industry, we can expect to see a convergence in regulations, combining the goal-setting standards of the North Sea and the Gulf of Mexico, with an emphasis of the principles of inherently safe design, integrity management (IM) programs, HAZID, HAZOP, and better interpretation of ALARP.

Leokadia Rucinski is a freelance writer based in Houston.


Binder Singh
serves as principal integrity engineer at Genesis, a wholly-owned subsidiary of Technip, in Houston. He holds a BEng in Mechanical Engineering from Liverpool University, England; and MSc, and PhD in corrosion from the University of Manchester, England. He is a UK Chartered Engineer, and Texas licensed professional engineer. Binder is an elected Fellow of the Institution of Mechanical engineers, Fellow of the Institute of Marine Engineers Scientists and Technologists; He is the elected chairman of the IMECHE Texas Branch for the period 2013-2015; and active within NACE, ISO and SPE ventures.