Wood Group Kenny’s Luis F. Garfias outlines the challenges relating to material selection and testing for eventual use in harsh environments.
Photo by Robert Callaway.
The increasingly extreme environments faced in oil and gas production are posing more demand on the materials that comprise the vital infrastructure for hydrocarbon extraction and processing. Pushing into frontier fields and deeper reservoirs, while leveraging new technologies and processes to maximize recovery, results in the need for smarter thinking around materials selection, testing, and qualification.
High pressure and high temperature (HPHT) places high strain on materials, and the increasing parameters are evident in the recent reclassification of HPHT to 10,000 psi (689.5 bar) and 350°F (176.6°C). There is a strong safety, and efficiency, case for ensuring correct material selection, accurate testing replicating the environment, and upfront modeling before a material or component can be declared fit for service.
The main goal of integrity management (IM) is to manage the long term integrity of equipment, ensuring that assets perform their required function effectively and efficiently, while safeguarding people, the environment and minimizing capital cost expenditure. Life extension depends on effective IM to reach an extended service life, but IM and materials engineering should be done during the design phase. It should consider the environmental interaction of the materials during the qualification of the new technologies to ensure strategic inclusion of the relevant monitoring systems for corrosion, flow, temperature, etc., to minimize asset degradation over time and to ensure their performance for 20+ years.
Fig. 1. Shows the stress-strain curve, pressurization and loading with 50 cycles during RSRT of cladded UNS N06625. Image from NACE Paper #10323.
Internal corrosion in harsh environments
The most important variables for harsh environments (from the point of view of internal corrosion) include HP, HT, CO2, H2S, the presence of chlorides and other chemicals. The combination of these variables with crude or gas typically results in a harsh environment where materials selection is critical and where corrosion monitoring, from wells to production and processing facilities, may also be required.
Top of the line corrosion (TOLC) is an example of a harsh environment that arises with the transport of hydrocarbons with water (and gas) resulting in water condensation in the upper part of the pipeline, where the corrosion inhibitors contained in the fluid cannot inhibit corrosion in the gas phase. Corrosion modeling can assess the most susceptible areas along the pipeline and assist to select the use of corrosion resistant alloys (CRAs) or other engineering strategies to mitigate TOLC.
Another prevention method used during operation is corrosion monitoring. Typically, this would involve coupons or online monitoring systems, although more innovative methods are currently being developed as alternative monitoring. For example, a good flow assurance program can predict extreme environmental conditions that can impact the corrosion processes taking place while the hydrocarbon is being transported. There is a strong incentive to use more than one methodology for corrosion monitoring.
Typically, corrosion monitoring doesn’t shed light on the corrosion mechanisms taking place within the harsh environment; that is where corrosion coupons, modeling and flow studies can be an ally and complement one another to provide meaningful corrosion information. A good integrity management plan can lead to cost savings by ensuring the selection of the right materials and technology, and use of the correct tools for corrosion monitoring during the lifetime of the asset.
Fig. 2. In-situ microscopy and electrochemical testing at HPHT in sour environments. Image from NACE Paper C2012-0001514.
Testing and qualification for harsh environments
Mechanical and corrosion testing can be done using conventional techniques and international standards. However, the typical qualification of materials for their use in extreme and/or harsh environments is usually done under ideal conditions, generally those stated in the international standards. Few qualification programs take into consideration the real environment in which the materials will be operating and typically have a poor understanding of the acceleration factors for their basis of qualification.
For example, using constant load testing (which is simple and widely understood) generally oversimplifies the problem and cannot address corrosion fatigue under the real cycling conditions. Similarly, other tests such as slow strain rate testing (SSRT), which is aggressive and rapid, can be too aggressive and it can be difficult to determine if cracking occurred inside service conditions. On the other hand, ripple strain rate testing (RSRT) includes corrosion fatigue and is adaptable, but with the drawback of being more complex and costly than constant load testing and SSRT. Still, all of those methodologies need to take into consideration the real environment and should mimic actual conditions in order to be acceptable as qualification methods.
Fig. 3. Microscopy and electrochemistry at 180°C (356°F) in 20,000 ppm chloride (40 bar CO2, 0.025 bar H2S and 0.02 M CH3COOH) of a duplex stainless steel. Image from NACE Paper C2012-0001526.
In-situ testing to simulate internal corrosion in harsh environments
Corrosion testing in harsh environments, which typically contain H2S, CO2 and NaCI in a liquid/gas mixture, is typically conducted in autoclaves at HPHT, involving several samples that will be immersed in the liquid/gas mixture under HPHT. The tests can last from days to months and in some cases the samples are totally disintegrated at the end of the tests. Therefore, no assessment of the expected lifetime of the metal can be done using weight loss and no assessment of the type of corrosion mechanism can be done on the coupons.
Ideally, the metals should be observed during the test to identify the onset of corrosion (for example general corrosion or localized corrosion) while the sample is immersed in the HPHT harsh environment. This can be done through a new methodology using a mini-autoclave that allows concurrent and in-situ microscopy and electrochemical tests in real time.
In Figure 3, the sample was heated to 180°C (356°F) in 20,000 ppm chloride (40 bar CO2, 0.025 bar H2S and 0.02 M CH3COOH). Pitting corrosion was confirmed both visually and in the electrochemical signature.
The advantage of using this technique is that it provides real-time visual confirmation of the processes (corrosion, degradation, microbial attack, etc.) that happens in the material inside the autoclave while the sample is immersed in the HPHT harsh environment. Another advantage is that the material can be monitored over time and video recording can be used to compare their interaction with the environment. However, this technique can only be used below 4000psi and 400°C (which is a limitation given by the materials of construction of the window).
Many testing programs exceed 150°C (302°F), but range from 3000psi (206.8 bar) to 15,000psi (1034 bar). New industry standards for HPHT are being developed. For example, the current API 14A, Edition 11 standard for surface-controlled subsurface safety valves (SCSSVs) requires that SCSSVs with a working pressure >10,000psi (689.5 bar) be tested to 5000psi (344.7 bar) above working pressure, rather than the 1.5 times working pressure requirement of API 14A, Edition 10. A design guideline for HPHT is currently being developed (API 17TR8) by many experts from the oil and gas industry. These new design guidelines will serve as a starting point for testing and qualification at HPHT in harsh environments.
Standard testing is the common approach in the majority of cases, but the correct approach will be to model the environment and mimic the actual conditions expected in the field. This applies to corrosion testing, mechanical testing (fatigue, fracture, hydrogen, cyclic loading, etc.), and dynamic testing in harsh environments. All modeling and testing needs to take into account the actual environment, the stresses, and simulate the expected lifetime, as well as ensuring that the acceleration factors for the qualification testing are in good agreement with the environments and lifetimes expected for the asset.
Measurements for reservoir conditions can often be made in error; not due to the measurements being performed improperly, but that concentrations, pressures and temperatures are measured at different locations and at lower temperatures. This causes problems as the amount of dissolved acid gases is highly dependent on temperature and pressure specific to each condition.
Well fluid compatibility (sour vs. sweet service) is another key issue, as are temperature de-rating effects on minimum yield strength. A finite understanding of material properties is essential.
Regarding non-metallic materials, the industry is currently developing polymers and seals that can withstand these ultra-HPHT well conditions up to 30,000 psi (2068.5 bar) and 260°C (500°F) while retaining mechanical properties, chemical performance, and well fluid compatibility. Reliability prediction, environmental concerns and safety issues must be addressed, and further seal research needs to be conducted. In some cases, metal-to-metal seals may replace elastomers.
The crux of the challenges relating to materials in harsh environments is the need for accurate testing and qualification in the context of the actual operating environment, correct material selection for each application, and the use of modeling in the early project stages.
There are a number of variables which must be considered when designing a device, planning to build a system or simply selecting a material for extreme and/or harsh environments. Different considerations must be taken for subsea, topside, or onshore oil and gas production; the nature of the HPHT reservoir will highly influence the materials selection. Having the correct materials in place for the purpose and using the optimum monitoring systems are essential to avoid failures.
Luis F. Garfias is a materials and testing consultant at Wood Group Kenny in Houston, focusing on projects related to materials, asset integrity management and testing at HPHT using electrochemistry and microscopy. He is an active member of NACE International and The Electrochemical Society. Garfias holds a B.Sc. in chemical engineering from Universidad Autonoma de Yucatan (Mexico), a M.Sc. in corrosion science and engineering from University of Manchester Institute of Science and Technology (UMIST - UK) and a Ph.D. in materials science from Oxford University (UK).