Design Implications Associated with the Addition of Hydrogen at Upstream and Midstream Facilities

Posted on March 22nd, 2021
Posted in Newsletter Volume 1    Tags:

Hydrogen is a growing subject matter not just in the oil and gas industry but in the energy conversation. It is a clean fuel that does not contribute to greenhouse gases in the atmosphere when burned / reacted.  While there are oil and gas facilities, such as refineries, that are familiar with the design requirements related to hydrogen, it will be unfamiliar to many upstream and midstream operators.  If hydrogen is being evaluated as a new fuel source at an oil and gas facility, there are design requirements that must be considered during the project to ensure a safe and successful execution.

Electrical area classifications are assigned to places where a fire or explosion potential may exist, as electrical equipment installed in such locations could provide an ignition source.  Area classifications are based on the flammability and auto-ignition temperature of a hazardous material, as well as the likelihood of the hazardous material to be present in a flammable concentration.  A majority of upstream and midstream oil and gas facilities are designed for Class 1, Division 2, Groups C and D.  The Class 1, Division 2 assignments designate that ignitable concentrations of flammable substances are not likely to exist under normal operating conditions.  The group designations are related to the specific chemical properties of the materials present, such as minimum ignition energy and upper and lower explosive limits.  Group D includes propane and methane, and Group C includes ethylene.  Hydrogen is included in Group B due to its wide flammability range, so the area classification, and thereby design requirements, become more stringent when hydrogen is present.

Vendors use to providing equipment and instrumentation for the typical oil field Class 1, Div 2, Groups C/D area classification can easily overlook the Group B requirement.  Oftentimes equipment and / or instrumentation with the additional rating requirements will be more expensive, making it easier to select cheaper, but deficient, units.   Lead times for equipment / instrumentation may be similar with a Group B designation, but if selections are made that are not suited to the requirements, this could lead to project delays once the deficiencies are uncovered.  In some instances, the operator’s preferred vendors may not be able to provide equipment and/or instrumentation to meet the more stringent area classification.

There may be difficulty in getting instrumentation with the right area classification, necessitating the addition of purge boxes which introduces another opportunity for increased cost and schedule delay.  In other cases, vendors may propose “explosion proof” instrumentation to satisfy the requirement, but “explosion proof” does not necessarily mean the units are rated for Group B.

In conclusion, owners and designers should be mindful that the addition of hydrogen introduces complexities in project execution.  The increased opportunity for error associated with the addition of hydrogen to an oil and gas facility means that all RFQs and bids must be conditioned especially carefully when selecting equipment and / or instrumentation. Owners should consider if a more nuanced Area Classification Study is warranted, which could add some complexity to the facility but possibly simplify overall project execution if hydrogen won’t be present site-wide. If hydrogen is being added to an existing facility, the operator must also review the existing equipment / instrumentation on site to determine if any modifications are required to meet the requirements of the Group B designation.  Operators can expect some increase in cost and possibly lead time with the addition of hydrogen.