NIST calculates H2 pipeline can cost up to 68% more than nat gas pipeline; proposes code change to reduce cost
20 July 2015
Pipelines to carry hydrogen cost more than other gas pipelines because of the measures required to combat the damage hydrogen does to steel’s mechanical properties (e.g., hydrogen embrittlement, HE) over time. Researchers at the National Institute of Standards and Technology (NIST) have now calculated that hydrogen-specific steel pipelines can cost as much as 68% more than natural gas pipelines, depending on pipe diameter and operating pressure.[1] By contrast, a widely used cost model[2] suggests a cost penalty of only about 10%.
However, according to the new NIST study, hydrogen transport costs could be reduced for most pipeline sizes and pressures by modifying industry codes[3] to allow the use of a higher-strength grade of steel alloy without requiring thicker pipe walls.
| High-strength, low-alloy steel (HSLA) |
|---|
| HSLA steels were first developed in the 1960s for large-diameter oil and gas pipelines. The line pipe used in these projects required higher strength and toughness than mild carbon steel, and good weldability provided by a low-carbon equivalent. |
| Two technology developments enabled the use of HSLA steel in large-diameter pipelines: the thermomechanical rolling process, and the use of niobium (Nb), vanadium (V) and titanium (Ti) as microalloying components. These developments permitted the manufacture of higher strength steels without additional expensive heat treatments. |
| Early HSLA line pipe steels typically relied on reduced pearlite-ferrite microstructures to make line pipe grades up to X60 and X65. Extensive research in the 1970s and early 1980s successfully developed higher strengths than X70 using various steel compositions, many employing a Mo-Nb (molybdenum-niobium) combination. New process technology such as accelerated cooling enabled the development of even higher strengths with much leaner Mo-free alloy designs, according to the International Molybdenum Association. |
| Mainstream HSLA line pipe steel typically contains 0.05 to 0.09% carbon, up to 2% manganese and small additions (usually max. 0.1%) of niobium, vanadium and titanium in various combinations. The preferred production route for this material is thermomechanical rolling to maximize grain refinement, which is the only strengthening mechanism that improves both strength and toughness simultaneously. |
| However, because many rolling mills either cannot apply the required cooling rates after finish rolling or do not even have the required accelerated cooling equipment, a practical available solution is to use selected alloy additions such as Mo to obtain the desired steel properties. |
The stronger steel is more expensive, but dropping the requirement for thicker walls would reduce materials use and related welding and labor costs, resulting in a net cost reduction. The code modifications, which NIST has proposed to the American Society of Mechanical Engineers (ASME), would not lower pipeline performance or safety, the NIST authors say.
The cost savings comes from using less—because of thinner walls—of the more expensive material. The current code does not allow you to reduce thickness when using higher-strength material, so costs would increase. With the proposed code, in most cases, you can get a net savings with a thinner pipe wall, because the net reduction in material exceeds the higher cost per unit weight.
—James Fekete, a co-author of the study
The NIST study is part of a federal effort to reduce the overall costs of hydrogen fuel. Much of the cost is for distribution, which likely would be most economical by pipeline. The US contains more than 300,000 miles (483,000 km) of pipelines for natural gas but very little customized for hydrogen.
Existing codes for hydrogen pipelines are based on decades-old data. NIST researchers are studying hydrogen’s effects on steel to find ways to reduce pipeline costs without compromising safety or performance.
As an example, the new code would allow a 24-inch (61 cm) pipe made of high-strength X70 steel to be manufactured with a thickness of 0.375 inches (9.52 mm) for transporting hydrogen gas at 1500 psi (10.3 MPa). (In line with industry practice, ASME pipeline standards are expressed in customary units.)
According to the new NIST study, this would reduce costs by 31% compared to the baseline X52 steel with a thickness of 0.562 inches (14.3 mm), as required by the current code.
In addition, thanks to its higher strength, X70 would make it possible to safely transport hydrogen through bigger pipelines at higher pressure—36-inch (91-centimeter) diameter pipe to transport hydrogen at 1500 psi—than is allowed with X52, enabling transport and storage of greater fuel volumes. This diameter-pressure combination is not possible under the current code.
The proposed code modifications were developed through research into the fatigue properties of high-strength steel at NIST’s Hydrogen Pipeline Material Testing Facility. In actual use, pipelines are subjected to cycles of pressurization at stresses far below the failure point, but high enough to result in fatigue damage. Unfortunately, it is difficult and expensive to determine steel fatigue properties in pressurized hydrogen.
As a result, industry has historically used tension testing data as the basis for pipeline design, and higher-strength steels lose ductility in such tests in pressurized hydrogen. But this type of testing, which involves steadily increasing stress to the failure point, does not predict fatigue performance in hydrogen pipeline materials, Fekete says.
NIST research has shown that under realistic conditions, steel alloys with higher strengths (such as X70) do not have higher fatigue crack growth rates than lower grades (X52). The data have been used to develop a model[4] for hydrogen effects on pipeline steel fatigue crack growth, which can predict pipeline lifetime based on operating conditions.
The studies at NIST’s hydrogen test facility were supported by the Department of Energy and Department of Transportation.
References
[1] J.W. Sowards, J.R. Fekete and R.L. Amaro (2015) “Economic impact of applying high strength steels in hydrogen gas pipelines.” International Journal of Hydrogen Energy doi: 10.1016/j.ijhydene.2015.06.090
[2] DOE H2A Delivery Analysis. US Department of Energy
[3] ASME B31.12 Hydrogen Piping and Pipeline Code
[4] R.L. Amaro, N. Rustagi, K.O. Findley, E.S. Drexler and A.J. Slifka (2014) “Modeling the fatigue crack growth of X100 pipeline steel in gaseous hydrogen.” Int. J. Fatigue, 59 pp 262-271 doi: 10.1016/j.ijfatigue.2013.08.010
Resources
Hejazi, D., Haq, A. J., Yazdipour, N., Dunne, D. P., Barbaro, F. and Pereloma, E. V. (2010) “Role of microstructure in susceptibility of X70 pipeline steel to hydrogen embrittlement.” A. Morton and J. Nie In Pacific Rim International Conference on Advanced Materials and Processing, 2-6 Aug, 2010, Cairns, Australia. Materials Science Forum, 654-656 162-165.
Talip Y. Alp and Faisal I. Iskanderani (2002) “Development Of Hsla Steel For Hydrogen Service In Oil And Gas Industries” The 6th Saudi Engineering Conference, KFUPM, Dhahran, December 2002 Vol. 5. 3
Well, well, the solution already exist for affordable high performance H2 pipelines.
Let's start with a H2 network along main highways to reduce the number of clean H2 generation stations.
Some existing NG pipelines may be adapted to transport H2?
Posted by: HarveyD | 20 July 2015 at 04:28 PM
Another way of transporting H2 through less costly pipelines is to attach it to a larger atom, like nitrogen or carbon.
Posted by: ai_vin | 20 July 2015 at 05:27 PM
H2 is “rocket science” and should not be used in any other direct application in the transport sector. If we, for some reason, would have a surplus of H2, it can be used instantly in the refinery sector, where we currently have a deficit of H2 (in some cases, H2 has to be produced locally). If the H2 surplus would be big, we could make synfuels using e.g. CO2 as the other component. One such example (besides favoured liquid fuels) would be synthetic natural gas (as indicated by ai_vin). Making H2 from NG, as we do today and with the (potential) objective of using it as an automotive fuel does not make sense.
Posted by: Peter_XX | 21 July 2015 at 12:32 AM
10% is a reasonable premium.
Not many dedicated H2 pipelines would be needed for many years though as it can be transported mixed in with NG as Germany, the UK and Hawaii plan.
Posted by: Davemart | 21 July 2015 at 01:44 AM
BTW, the old 'town gas' made from coal was around 50% hydrogen, and we have been piping that around for 150 years or so, so we have considerable experience.
Posted by: Davemart | 21 July 2015 at 01:46 AM
Better yet, just continue transporting NG as usual, but split it down to hydrogen at the local electrical substation, with the help of excess energy from the local step-down transformer. This is frankly the best place for fuel cells to elaborate on the job, as they are big, expensive, generate large amounts of waste heat, and would be capable of massive gas leaks.
But what would I do with this stuff at home?
Posted by: kalendjay | 21 July 2015 at 02:22 PM
In New York state will replace all of their natural gas pipelines in 75 years.
More than half of the nation's pipelines are at least 50 years old.
Don't expect these kind of changes to make a difference very quickly.
Posted by: NewtonPulsifer | 21 July 2015 at 03:30 PM