Corrosion Rules of Thumb - Material Selection Considerations for Various Forms of Corrosion

In order to prevent corrosion related failure modes from occurring they should be considered during the design and material selection stages of system development. Accounting for many of the issues that are correlated with corrosion, including test, design, and metallurgical factors facilitates the development of an inherently corrosion resistant design. This article addresses the major considerations for the common forms of corrosion that factor into design and material selection, and presents some general ‘rules of thumb’ used in selecting materials for corrosion resistance.

The ‘rules of thumb’ are contained in the following sections that address each of the main forms of corrosion. The sections identify the major failure modes, followed by discussions of the test, design, and metallurgical considerations. With respect to test and design considerations, the primary properties used for quantitative measurement, if there are any, are identified. For many forms of corrosion, there are no quantitative measurement techniques, and thus materials are only rated based upon their relative susceptibilities. Additional design features that are conducive to the creation of corrosive microenvironments are highlighted. The primary metallurgical factors for each form of corrosion are also identified. Some of the major material classes are discussed as to their relative susceptibility and resistance to the form of corrosion under consideration. Together, this information provides a basis for the down-selection of candidate materials. The information discussed above has been organized into six categories for each form of correction including  :

1. measurement
2. design considerations
3. misapplication of data
4. metallurgical features
5. susceptible alloys
6. resistant alloys.

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Corrosion Control in Engineering Design

Corrosion involves the reaction of a metallic material with its environment and is a natural process in the sense that the metal is attempting to revert to the chemically combined state in which it is almost invariably found in the earth’s crust. Whilst it is, therefore, a process that may be expected to occur, it should not be regarded as inevitable and its control or prevention is possible through a variety of means. The latter have their origins in electrochemistry, since the reactions involved in causing corrosion are electrochemical in nature, but corrosion control is as much in the hands of the engineering designer as it is the province of the corrosion prevention specialist. To the engineer, corrosion may be regarded as resulting in a variety of changes in the geometry of structures or components that invariably lead, eventually, to a loss of engineering function e.g. general wastage leading to decrease in section, pitting leading to perforation, cracking leading to fracture.

The rusting of ordinary steel is the most common form of corrosion and overall adds up to a high proportion of the total cost attributed to corrosion. General corrosion, in which the whole of the exposed metal surface is attacked, may lead to failure in the engineering sense, but this is usually avoided by the application of suitable control measures. All corrosion, however, is not of the general type and localised effects may pose more complex problems, especially in the engineering context. It is important to realise that corrosion characteristics are not inherent properties of alloys, as are yield strength, electrical conductivity and the like, since they relate to a combination of alloy and environment. Consequently, an alloy may be very resistant to corrosion in a particular environment, yet perform poorly in another, and even in a given environment factors like temperature, rate of flow and geometrical aspects may be critical. In any event, the significance of corrosion to the engineer is that it leads to loss of engineering function and the following examples have been chosen to illustrate this in a variety of the branches of engineering. They also serve to define some of the commoner forms of aqueous corrosion and their various consequences.

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Basics of Corrosion Measurements

Mixed-Potential Theory consists of two simple hypothesis: (1) any electrochemical reaction can be divided into two or more partial oxidation and reduction reactions and (2) there can be no net accumulation of electric charge during an electrochemical reaction. It can be experimentally demonstrated that electrochemical reactions are composed of two or more partial oxidation or reduction reactions. The second hypothesis is a restatement of the law of conservation of charge. It follows that during the corrosion of an electrically isolated metal sample, the total rate of oxidation must equal the total of reduction...

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Corrosion Theory and Corrosion Protection

The annual cost of corrosion and corrosion protection in the United States is estimated by the National Association of Corrosion Engineers (NACE) to be in excess of 10 billion dollars. This figure is perhaps less intimidating considering that corrosion occurs, with varying degrees and types of degradation, whenever metallics are used. b. Corrosion can be mitigated by five basic methods: coatings, cathodic protection, materials selection, chemical inhibitors, and environmental change. A basic understanding of corrosion will enable USACE personnel to comprehend how these methods help prevent corrosion, and it will establish an overall introduction to the purpose for the entire engineer manual on painting

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The Electrochemistry of Corrosion

The surfaces of all metals (except for gold) in air are covered with oxide films.  When such a metal is immersed in an aqueous solution, the oxide film tends to dissolve.  If the solution is acidic, the oxide film may dissolve completely leaving a bare metal surface, which is said to be in the active state.  In near-neutral solutions, the solubility of the oxide will be much lower than in acid solution and the extent of dissolution will tend to be smaller.  The underlying metal may then become exposed initially only at localised points where owing to some discontinuity in the metal, e.g. the presence of an inclusion or a grain boundary, the oxide film may be thinner or more prone to dissolution than elsewhere.  If the near-neutral solution contains inhibiting anions, this dissolution of the oxide film may be suppressed and the oxide film stabilised to form a passivating oxide film which can effectively prevent the corrosion of the metal, which is then in the passive state...

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Introduction to Corrosion Phenomenon

The objective of this talk is to provide broad-brush comments on a wide range of corrosion phenomena in order to provide a measure of common ground for the more detailed talks which follow, and also to discuss in slightly greater depth a few topics for which time does not allow individual coverage. The topics discussed are restricted to those included in the area commonly called “wet” corrosion; atmospheric corrosion and corrosion at high temperatures will be treated separately. At this stage, at least, the treatment will not be either deeply chemical or deeply mechanistic, but will be restricted to factual discussion of the ways in which corrosion may lead to materials problems in practice.

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Beginners Guide to Corrosion

This document has been prepared by Bill Nimmo and Gareth Hinds of NPL’s Corrosion Group from various source material. It is intended to give an introduction to corrosion and its control in non-technical terms. More technical information is available on other areas of the NPL NCS website.

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Corrosion Control Basic

A short introduction to corrosion and its control corrosion of metals and its prevention.
Discussed topic includes :

i) What is corrosion
ii) The consequences of corrosion
iii) Chemistry of corrosion
iv) Factos control corrosion rate
v) Corrosion prevention

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Performance of Duplex Stainless Steels in Hydrogen Sulphide-Containing Environmen

Performance of Duplex Stainless Steels in Hydrogen Sulphide-Containing Environments

This paper addresses relevant past papers in previous 'Duplex' conferences in the light of present-day knowledge, and shows which aspects have been emphasised at different times over the last 15 years. From this review conclusions are drawn which may assist in making decisions on the application of duplex stainless steels in future. A critique of currently used and mis-used test methods is included.

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Modelling Corrosion Rates in Oil Production Tubing

Modelling Corrosion Rates in Oil Production Tubing

Data related to tubing corrosion in an oil field have been compiled and analysed in terms of angle of well tubing deviation, watercut and fluid velocity. Using a semi-empirical formula for C02 corrosion prediction, it was possible to model the effect on corrosion of the light crude oil produced from a field in the Middle East by means of a multiplier for the corrosion rate, the oil factor. A good level of correlation was achieved between field measured corrosion rates and calculated values using the model established for this specific field. The model was incorporated in a user-friendly computer programme suitable for analysing ongoing corrosion risks and anticipating future field developments.

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The Influence of Crude Oils on Well Tubing Corrosion Rates

The Influence of Crude Oils on Well Tubing Corrosion Rates

An empirical formula derived from two sets of field data on tubing corrosion gives a satisfactory description for two different oil fields of the influence on corrosion of the API gravity of the oil and its watercut. A remarkably good level of agreement was found between predicted corrosion rates using this formula and field corrosion measurements. It reproduces the general concept that heavier oils are more protective than light ones, and that very light oils give hardly any protection at all. It also reflects the likelihood of various modes of corrosion associated with competitive wetting of the steel by water and oil arising from different modes of water entrainment. The link between API gravity, emulsion stability and water wetting of steel by an oil-water mixture is provided by considering the changes in interfacial tensions in the oil-water-steel system.

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Control of Corrosion in Oil and Gas Production Tubing

Control of Corrosion in Oil and Gas Production Tubing

Controlling corrosion in production tubing is essential for maintaining production and for preventing loss of well control. Materials for use downhole have to meet criteria for corrosion resistance and also mechanical requirements. The potential corrosion rate can be estimated and the risks of sulphide stress corrosion cracking (SSCC) assessed on the basis of the anticipated environmental conditions and flow regime. Material options for tubing can then be consid- ered on the basis of published corrosion test data and also field experience. Candidate materials may be tested under the precisefield conditions expected in order to ensure that overconservative choices are not made. Corrosion inhibitors, coated carbon steel, andfibre reinforced plastic tubing have temperature, pow regime, and mechanical limitations. Specific cowosion resistant alloys (CRAs) have environmental limitations with respect to temper- ature, hydrogen sulphide, and chloride content. Details offeld experience with all of these material options are given. There exists a large amount of experience with CRAs for downhole applications. Correctly selected CRAs have a good track record of service, even for hostile. H,S containing conditions. There are afew limited examples of CRA clad tubing. This product may be one that needs re-evaluation as it offers potential for economtc use of costly but effective CRAs.

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A Guideline To The Successful Use Of Duplex Stainless Steels For Flowlines

A Guideline To The Successful Use Of Duplex Stainless Steels For Flowlines

Duplex stainless steels have been widely used for flowlines carrying oil and gas, with more than 845km now in service. Successful application requires selection of the correct steel grade, use of the material in the correct heat treatment condition, attention to specific procedures when welding, correct design of the cathodic protection system and control during the commissioning period. This paper details correct practice in all these areas, providing sound guidelines for the successful application of duplex stainless steels for flowlines.

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HSE Corrosion Protection

Corrosion Protection
Report of HSE on Corrosion Control and Corrosion Protection in Offshore and Oil&Gas

 

This Offshore Technology (OT) Report provides technical information on the protection of Offshore Installations against corrosion. It is based on guidance previously contained in Section 12 of the Fourth Edition of the Health and Safety Executive’s ‘Offshore Installations : Guidance on Design, Construction and Certification’(1) which was withdrawn in 1998. As discussed in the Foreword, whilst the text has been reformatted for Offshore Technology publication, the technical content has not been updated. The appropriateness and currency of the information contained in this document must therefore be assessed by the user for any specific application...

 

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Offshore external corrosion guide

Offshore external corrosion guide

This guide is intended to enable OSD inspectors to make consistent judgement on the extent of external corrosion related to the installation’s hydrocarbon systems. The guide identifies a sample of six common forms of external corrosion and provides information on :

• where to look; and
• what to look for.
  

The six areas of concern are :

1. corrosion under insulation (CUI);
2. firewater mains and deluge system;
3. flanges and plant bolting;
4. valves;
5. pipe supports and pipe coatings; and
6. threaded plugs.

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High Performance Age-Hardenable Nickel Alloys Solve Problems in Sour Oil and Gas Service

High Performance Age-Hardenable Nickel Alloys Solve Problems in Sour Oil and Gas Service

The new frontier of oil and gas exploration will be with deep wells, particularly in deepwater. Most of the “easy-to-pick” fruit have been taken with shallow field development. Compared to shallow wells, deep wells generally require more high-performance, nickel-base alloys. Wells are categorized as being either “sweet” or “sour.” Sweet wells are only mildly corrosive, while sour wells are very corrosive. Sour wells can contain hydrogen sulfide, carbon dioxide, chlorides, and free sulfur. There are different levels of corrosive conditions that are compounded by temperatures up to 500 F (260 C) and pressures up to 25,000 psi (172 MPa). Deep wells generally have higher temperatures and pressures. Material selection is especially critical for sour gas wells. The materials of choice must be corrosion-resistant, cost-effective, reliable, and have the required strength for the well conditions. As these conditions become more severe, material selection changes from carbon steels for “sweet” wells, to duplex (austenitic-ferritic) stainless steel, to INCOLOY alloys 825 or

925™, to INCONEL alloys 725HS and 725™ for sour well service...

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A guide on the use of International Standard NACE MR 0175/ISO 15156

A guide  on the use of International Standard NACE MR 0175/ISO 15156

The NACE MR0175/ISO 15156 International Standard for the selection of crackresistant materials for use in H2S-containing environments has had a significant impact on various aspects of the oil & gas industry in Canada. For this reason, CAPP Pipeline Technical Committee felt it was important to create a supporting document, which could be used by industry as a reference tool to: · provide a brief overview of the NACE/ISO publication, outlining the most significant changes and their implication to the industry, · provide guidance and assistance on how to apply the new publication using simple to follow flowcharts, and clarification examples, · provide sample forms which could be used to meet the intent of the publication. This document is not intended to supersede the NACE MRO175/ISO 15156 International Standard. It is intended to serve a as a Guide for working with and complying with the NACE MRO175/ISO 15156 International Standard. In the case of any inconsistencies between the NACE MRO175/ISO 15156 International Standard and the guidance provided in this document, the International Standard should be adhered to.

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References

i) Corrosion Control in Petroleum Production: Tpc Publication 5 (Tpc Publication, 5)

ii) Corrosion and Its Control: An Introduction to the Subject

iii) Corrosion and Corrosion Control

Rewiew of corrosion management for offshore oil and gas processing

Rewiew of corrosion management for offshore oil and gas processing

Report of HSE regarding Corrosion Management and Control in Offshore Oil&Gas - The aim of this document has been to capture "best practice" from industry on corrosion management for offshore processing facilities into a single document that will be in the public domain. Whilst the many of the problems and solutions described in this report are applicable to all aspects of oil & gas production, including design, installation, production and transportation for onshore and offshore facilities, the report is focused on operational aspects for offshore process plant and facilities. Corrosion management also covers other integrity risks, including those from stress corrosion cracking, embrittlement, erosion, etc., as well as “simple corrosion” (i.e. general, pitting and crevice corrosion).

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References

i) Corrosion Control in Petroleum Production: Tpc Publication 5 (Tpc Publication, 5)

ii) Corrosion and Its Control: An Introduction to the Subject

iii) Corrosion and Corrosion Control

Recommended Practice for mitigation of internal Corrosion in Sour Gas Gathering Systems

Recommended Practice for mitigation of internal Corrosion in Sour Gas Gathering Systems

Corrosion is a dominant contributing factor to failures and leaks in pipelines. To deal with this issue, the CAPP Pipeline Technical Committee has developed industry recommended practices to improve and maintain the mechanical integrity of upstream pipelines. They are intended to assist upstream oil and gas producers in recognizing the conditions that contribute to pipeline corrosion incidents, and identify effective measures that can be taken to reduce the likelihood of corrosion incidents. This document addresses design, maintenance and operating considerations for the mitigation of internal corrosion in sour gas pipeline systems constructed with carbon steel materials. Within this document, sour gas corrosion could be expected to occur when: · H2S concentration in the gas phase is greater than 500 ppm (These limits are supplied as a guideline only and may not be absolute) · H2S is dissolved in free water This document does not address failures due to environmental cracking such as sulphide stress cracking (SSC) and hydrogen induced cracking (HIC). This document also does not address gas gathering systems fabricated with aluminum and non-metallic materials.

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References

i) Corrosion Control in Petroleum Production: Tpc Publication 5 (Tpc Publication, 5)

ii) Corrosion and Its Control: An Introduction to the Subject

iii) Corrosion and Corrosion Control

Selection guidelines for corrosion resistant alloys in the oil and gas industry

Selection guidelines for corrosion resistant alloys in the oil and gas industry

The selection of Corrosion Resistant Alloys, CRAs, for producing and transporting corrosive oil and gas can be a complex procedure and if improperly carried out can lead to mistakes in application and misunderstanding about the performance of a CRA in a specific service environment. There is a variety of ways individuals and companies select CRAs for anticipated well and flowline conditions. Companies with large research facilities typically initiate a test program that involves simulating the particular part of the field environment under study (i.e., flowlines versus downhole). Then a group of alloys, based on information available, is selected that represents a possible range of alternatives. Rather than test all alloys all the time, it is more cost-effective and less time- consuming to test only a few CRAs that are likely candidates. This approach can easily require 1 to 3 years to accomplish at considerable expense.

Another selection procedure is to review the literature for corrosion data that generally applies to the anticipated field conditions. This can result in elimination of those CRAs that are not good candidates and, thus, narrow the number of candidate alloys for testing. The selected CRAs are then tested under very specific conditions to fill gaps in literature data and/or field experience. Care must be taken when using this approach because, for example, the corrosion resistance of many CRAs at one temperature is not necessarily indicative of their corrosion resistance at other temperatures. Likewise, changes in critical environmental components such as elemental sulphur can have a profound impact on the resistance to stress corrosion cracking, SCC, another important factor in alloy selection.

The quickest and least expensive alloy selection method is simply to review the literature, and existing or similar field data, and make the selection. This method can be quite unsatisfactory since certain critical factors or conditions will not be known and must be assumed. A greater chance for error exists in this selection approach, introducing a potential for failure of the CRA or use of a more expensive alloy than is required. It is advisable, if this method is used, to consult with someone who has a working knowledge of CRAs and their applications. Finally, a CRA selection method that is not recom- mended but is often used is to select a CRA that is readily available or most economical, without regard to its corrosion resistance in the intended environment. Misapplication of CRAs is becoming more common for this reason and has resulted in corrosion and cracking problems of the inappropriately selected alloys........

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References
i) Corrosion Resistant Materials Handbook
ii) Corrosion Resistant Materials Handbook 1966
iii) Corrosion resistant materials handbook, 1966
iv) Corrosion Resistant Materials Handbook
v) Process Industries Handbook of Corrosion Resistant Materials

NORSOK M-001 - Material Selection for Corrosion Control in Offshore Oil & Gas Facilities

Norsok Standard:
Material Selection for Corrosion Control in Offshore Oil & Gas Facilities

A NORSOK standard gives recommendations, requirements and guidelines for materials use in oil and gas production. This revision includes requirements from NORSOK M-CR-505 "Corrosion monitoring design", which is withdrawn. The evaluation of internal corrosivity in hydrocarbon systems is rewritten and considers corrosion inhibitor availability instead of efficiency, and the maximum hardness and yield strength requirements of materials to be cathodically protected have been lowered.

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References

i) Corrosion Control in Petroleum Production: Tpc Publication 5 (Tpc Publication, 5)

ii) Corrosion and Its Control: An Introduction to the Subject

iii) Corrosion and Corrosion Control

Duplex, Super Duplex Stainless Steels, Cupronickels and Corrosion Mechanisms

Offshore materials selection, Duplex Steel, SuperDuplex Steel, Corrosion Control - Materials selections must be given detailed attention at every stage of the design, construction and operation of systems and equipment for application in offshore oil and gas production. Full attention must be given to general corrosion resistance, selective corrosion resistance (by pitting and crevice attack) and stress corrosion cracking susceptibility in sour hydrogen sulphide environments if failures, loss of production and costly maintenance are to be avoided. Even more important than these considerations is the need to maintain offshore safety. Thus the specification and use of materials which combine corrosion resistance with high mechanical strength is a fundamental requirement.

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References
i) Corrosion Resistant Materials Handbook
ii) Corrosion Resistant Materials Handbook 1966
iii) Corrosion resistant materials handbook, 1966
iv) Corrosion Resistant Materials Handbook
v) Process Industries Handbook of Corrosion Resistant Materials

Aqueous Co2 Corrosion of Mild Steel

A tutorial from Ohio Uversity on CO2 - H2S corrosion in Oil&Gas- As the oil and gas emerge from the geological formation they are always accompanied by some water and varying amounts of “acid gases”: carbon dioxide, 2 CO and hydrogen sulfide, H S 2 . This is a corrosive combination which affects the integrity of mild steel. Even if this has been known for over 100 years, yet aqueous 2 CO and H S 2 corrosion of mild steel still represents a significant problem for the oil and gas industry.1

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Dehydration by Molecualr Sieves (MS)

Molecular sieves are crystalline metal alumina silicates having a three dimensional interconnecting network of silica and alumina tetrahedra. Natural water of hydration is removed from this network by heating to produce uniform cavities which selectively adsorb molecules of a specific size.

A 4 to 8-mesh sieve is normally used in gas phase applications, while the 8 to 12-mesh type is common in liquid phase applications. The powder forms of the 3A, 4A, 5A and 13X sieves are suitable for specialized applications.

Long known for their drying capacity (even to 90°C), molecular sieves have recently demonstrated utility in synthetic organic procedures, frequently allowing isolation of desired products from condensation reactions that are governed by generally unfavorable equilibria. These synthetic zeolites have been shown to remove water, alcohols (including methanol and ethanol), and HCl from such systems as ketimine and enamine syntheses, ester condensations, and the conversion of unsaturated aldehydes to polyenals.

3A molecular sieve : 0.6 K2O: 0.40 Na2O : 1 Al2O3 : 2.0 ± 0.1SiO2 : x H2O

4A molecular sieve : 1 Na2O: 1 Al2O3: 2.0 ± 0.1 SiO2 : x H2O

5A molecular sieve : 0.80 CaO : 0.20 Na2O : 1 Al2O3: 2.0 ± 0.1 SiO2: x H2O

13X molecular sieve : 1 Na2O: 1 Al2O3 : 2.8 ± 0.2 SiO2 : xH2O

Regeneration (activation)
Regeneration in typical cyclic systems constitutes removal of the adsorbate from the molecular sieve bed by heating and purging with a carrier gas. Sufficient heat must be applied to raise the temperature of the adsorbate, the adsorbent and the vessel to vaporize the liquid and offset the heat of wetting the molecular-sieve surface. The bed temperature is critical in regeneration. Bed temperatures in the 175-260° range are usually employed for type 3A. This lower range minimizes polymerization of olefins on the molecular sieve surfaces when such materials are present in the gas. Slow heat up is recommended since most olefinic materials will be removed at minimum temperatures; 4A, 5A and 13X sieves require temperatures in the 200-315 °C range.

After regeneration, a cooling period is necessary to reduce the molecular sieve temperature to within 15° of the temperature of the stream to be processed. This is most conveniently done by using the same gas stream as for heating, but with no heat input. For optimum regeneration, gas flow should be countercurrent to adsorption during the heat up cycle, and concurrent (relative to the process stream) during cooling. Alternatively, small quantities of molecular sieves may be dried in the absence of a purge gas by oven heating followed by slow cooling in a closed system, such as a desiccator.

Physical Properties Of ETHANE

Physical State at 15° C and 1 atm: Gas
Molecular Weight: 30.07
Boiling Point at 1 atm: –127.5°F = –88.6°C = 264.6°K
Freezing Point: –279.9°F = –183.3°C = 89.9°K
Critical Temperature: 90.1°F = 32.3°C = 305.5°K
Critical Pressure: 708.0 psia = 48.16 atm = 4.879 MN/m2
Specific Gravity: 0.546 at -88.6°C (liquid)
Liquid Surface Tension: 16 dynes/cm = 0.016 N/m at –88°C
Liquid Water Interfacial Tension: (est.) 45 dynes/cm = 0.045 N/m at –88°C
Vapor (Gas) Specific Gravity: 1.1
Ratio of Specific Heats of Vapor (Gas): 1.191
Latent Heat of Vaporization: 211 Btu/lb = 117 cal/g = 4.90 X 105 J/kg
Heat of Combustion: –20,293 Btu/lb = –11,274 cal/g = –472.02 X 105 J/kg
Heat of Decomposition: Not pertinent
Heat of Solution: Not pertinent
Heat of Polymerization: Not pertinent
Heat of Fusion: 22.73 cal/g
Limiting Value: Currently not available
Reid Vapor Pressure: Very high

Source

Physical Properties Of METHANE

Physical State at 15° C and 1 atm: Gas
Molecular Weight: 16.04
Boiling Point at 1 atm: –258.7°F = –161.5°C = 111.7°K
Freezing Point: –296.5°F = –182.5°C = 90.7°K
Critical Temperature: –116.5°F = –82.5°C = 190.7°K
Critical Pressure: 668 psia = 45.44 atm = 4.60 MN/m2
Specific Gravity: 0.422 at –160°C (liquid)
Liquid Surface Tension: 14 dynes/cm = 0.014 N/m at –161°C
Liquid Water Interfacial Tension: (est.) 50 dynes/cm = 0.050 N/m at –161°C
Vapor (Gas) Specific Gravity: 0.55 1.0
Ratio of Specific Heats of Vapor (Gas) : 1.306
Latent Heat of Vaporization: 219.4 Btu/lb = 121.9 cal/g = 5.100 X 105 J/kg
Heat of Combustion: –21,517 Btu/lb = –11,954 cal/g = –500.2 X 105 J/kg
Heat of Decomposition: Not pertinent
Heat of Solution: Not pertinent
Heat of Polymerization: Not pertinent
Heat of Fusion: 13.96 cal/g
Limiting Value: Currently not available
Reid Vapor Pressure: Very high

Physical Properties Of OXYGEN

# Molecular Formula: O2
# Molecular Weight: 31.999
# Boiling Point @ 1 atm: -297.4°F (-183.0°C, 90oK)
# Freezing Point @ 1 atm: -361.9°F (-218.8°C, 54oK)
# Critical Temperature: -181.8°F (-118.4°C)
# Critical Pressure: 729.1 psia (49.6 atm)
# Density, Liquid @ BP, 1 atm: 71.23 lb/scf
# Density, Gas @ 68°F (20°C), 1 atm: 0.0831 lb/scf
# Specific Gravity, Gas (air=1) @ 68°F (20°C), 1 atm: 1.11
# Specific Gravity, Liquid (water=1) @ 68°F (20°C), 1 atm: 1.14
# Specific Volume @ 68°F (20°C), 1 atm: 12.08 scf/lb
# Latent Heat of Vaporization: 2934 BTU/lb mole
# Expansion Ratio, Liquid to Gas, BP to 68°F (20°C): 1 to 860
# Solubility in Water @ 77°F (25°C), 1 atm: 3.16% by volume

Physical Properties Of HYDROGEN

# Molecular Weight: 2.016
# Boiling Point @ 1 atm: -423.0°F (-252.8°C, 20oK)
# Freezing Point @ 1 atm: -434.5°F (-259.2°C, 14oK)
# Critical Temperature: -399.8°F (-239.9°C)
# Critical Pressure: 188 psia (12.9 atm)
# Density, Liquid @ B.P., 1 atm: 4.23 lb./cu.ft.
# Density, Gas @ 68°F (20°C), 1 atm: 0.005229 lb./cu.ft.
# Specific Gravity, Gas (Air = 1) @ 68°F (20°C), 1 atm: 0.0696
# Specific Gravity, Liquid @ B.P., 1 atm: 0.0710
# Specific Volume @ 68°F (20°C), 1 atm: 192 cu. ft./lb.
# Latent Heat of Vaporization: 389 Btu/lb. mole
# Flammable Limits @ 1 atm in air 4.00%: -74.2% (by Volume)
# Flammable Limits @ 1 atm in oxygen 4.65%: -93.9% (by Volume)
# Detonable Limits @ 1 atm in air 18.2%: -58.9% (by Volume)
# Detonable Limits @ 1 atm in oxygen 15%: -90% (by Volume)
# Autoignition Temperature @ 1 atm: 1060°F (571°C)
# Expansion Ratio, Liquid to Gas, B.P. to 68°F (20°C): 1 to 848