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Managing hydrogen sulphide detection offshore

Offshore Information Sheet No. 6/2009

(Issued April 2009)

Contents

Introduction

This information sheet provides guidance for dutyholders on detecting and managing hydrogen sulphide (H2S) hazards in hydrocarbon processing systems. As reservoirs begin to water out, hydrogen sulphide can become an issue when processing returning fluids. The gas is toxic in relatively low concentrations and the risks to the workforce need to be addressed as soon as its’ presence becomes known. It is not intended to provide detailed advice on workplace exposure limits, which are detailed in EH40[1].

Background

Hydrogen sulphide is considered a broad-spectrum poison, meaning that it can poison several different systems in the body, although the nervous system and respiratory systems are most affected. Besides being highly toxic H2S is a flammable gas. It is heavier than air and hence tends to accumulate in low-lying areas. It is pungent but rapidly destroys the sense of smell.

H2S is toxic at breathable concentrations between 500-1000ppm, but death is not instantaneous. However, at concentrations of greater than 1000ppm, H2S is rapidly lethal[1]. Industry practice is to recognise that fatality from H2S exposure can occur over a wide concentration band but at around 500–1000ppm exposure for a short period, the fatal exposure levels would be significant[2]. EH 40 defines the concentrations for exposed populations and ‘normal working conditions'. 

800ppm is the generally accepted lethal concentration for 50% of an exposed human population for 5 minutes exposure (LC50).

Some further details on concentrations and effects are given below:-

HSE sets limits for the control of hazardous substances in air. They are known as workplace exposure limits (WELs) and are set to help protect the health of workers who may be exposed to such substances.  These limits are concentrations of hazardous substances in the air, averaged over a specific period referred to as a time-weighted average (TWA).  Two time periods are used: long-term (8 hours) and short-term (15 minutes). Short-term exposure limits (STEL) are set to help prevent acute effects such as eye irritation, which may occur following exposure for a few minutes. WEL limits are published in EH 40. HSE does not set limits or publish information on concentrations of gasses that are immediately dangerous to life or health (IDLH). However, the National Institute of Safety and Health (NIOSH) in the USA has set IDLH figures for a number of substances, which may be used by dutyholders.

Standards and guidance

ISO 10418[2] covers industry practice for handling H2S and is based on the accepted criterion that significant fatalities would occur from exposure to H2S  in gas at concentrations of 500-1000ppm. Detection guidance is based on the argument that the hydrocarbon gas detection system will provide adequate detection if the H2S is below 500ppm in the hydrocarbon (HC) process streams. This is an acceptable argument only if it can be demonstrated that the HC detection system is ~100% effective. Above 500ppm specific H2S detection is required.

Hydrogen sulphide has a WEL of 5 ppm 8-hour TWA based on data indicating a shift towards anaerobic respiration at exposures to 10 ppm.

NIOSH has set a concentration of 100 ppm as IDLH.

In the UK sector of the North Sea hydrocarbon gas detection equipment is demonstrably not 100% effective for open modules[3].  Analysis of the Hydrocarbons Releases database[4] indicates that HC detection systems on UK offshore Installations detect ~60% hydrocarbon gas leaks in open modules. This is no reflection on the reliability and availability of the equipment. Process modules are open to the environment to minimise explosion overpressures (due to congestion factors), but this unfortunately helps to defeat the effectiveness of the gas detection systems.

Use of hydrocarbon detection systems for H2S monitoring need to take account of this “detection effectiveness”.

Hazard identification and management

Production of liquid and gaseous hydrocarbons containing hydrogen sulphide in significant amounts can be hazardous to people. H2S in hydrocarbon fluids has the potential to form sulphur dioxide (SO2) via combustion. Flaring hydrocarbon gas containing measurable quantities of H2S needs to be managed to ensure the SO2 produced does not present a toxic hazard. Combinations of H2S, SO2 and hydrocarbon gaseous mixtures also need to be considered in terms of their accumulated toxic load.

H2S presence in reservoir streams tends to increase with time and it is important therefore that dutyholders ensure that if the concentration levels in modules begin to increase the toxicity status of the areas are revised accordingly. The recommended strategy for fixed and portable detection is based on accepted management practice for confined space entry, and normally accessible process modules.

On an offshore installation, the standards[2,5] recommend a 3-tier approach to H2S gas detection; similar to the flammable hazardous area classification arrangements:-

Category 0: Areas where H2S will be present during normal operations – confined spaces, vessels etc.

Fixed H2S detection is not recommended in areas where H2S is known to be present at high concentrations during normal operations. The argument is that if the presence of the toxic gas is known and known to be unacceptably high, there is no reason for installing detection.

Access is controlled by special precautions, confined space entry management, that starts with the removal of H2S and initial entry is by specifically trained personnel with portable H2S detection equipment wearing breathing apparatus (BA) and other protective equipment.

Category 1: Areas in which H2S may be encountered during normal operations

Entry is only allowed with portable toxic detection equipment and fixed detection is recommended for these areas to maintain a risk history, but should not be used for making safety-related decisions.

Category 2: Areas which are H2S free in the atmosphere during normal operations, but which may be contaminated by a leak, or equipment malfunction or intrusive activities.

For ‘open access modules’, where H2S is not normally present but could be following a leak, fixed detection is recommended in certain scenarios. This is based on a concentration of 500 ppm H2S in the ‘carrier’ stream of process fluids. If the H2S concentration is below 500ppm, in the carrier stream, the areas may be classified as “2A” and H2S detection is via the standard hydrocarbon detection instruments. At concentrations greater than 500ppm, in the carrier stream, the area is designated “2B”, and requires a H2S specific detection system because the hydrocarbon detection systems cannot provide a timely response to the more harmful, higher H2S concentrations levels. 

This argument is based on an assumption in the standard[2] (unsubstantiated) that process hydrocarbon carrier gas on release is diluted to 1% by air entrainment. Hence if the hydrocarbon gas contained 500ppm H2S, the toxic component would be diluted to 5ppm; the occupational exposure limit (OEL) for the gas. However, there is no supporting argument in the standard that a 100:1 dilution will be achieved if a hydrocarbon gas stream is released to atmosphere.

Dutyholders are advised that dilution of gaseous jets by air entrainment on release is complicated and a dilution factor of 100:1 cannot be assumed. It should be noted that the <500ppm H2S with dilution argument would hold at lower entrainment dilutions (e.g. 2% and above) provided that the time to alarm for the hydrocarbon detector was always less than the time to alarm for the H2S detector. This depends on the alarm level (e.g. 5ppm for H2S and 20% LEL (lower exposure limit) for HC) and the response time of the different detectors. Typical HC detectors respond faster than typical H2S detectors but their relative times to alarm should always be provided to justify this approach, notwithstanding the fact that HC detectors are less than 100% effective.

It is recommended that dutyholders have active monitoring systems in place where the presence of H2S is known to exist in process streams. The systems should be demonstrably effective in quantifying the levels of the gas in breathable atmospheres. Secondly dutyholders need to identify the likely frequency of leakage from the H2S carrier (process) stream and worker occupancy within adjoining areas, to provide a measure of the risk from inhalation of the gas in “open access modules”. This information is also necessary for the designation of modules as 2A and 2B areas.  

Gas detection on offshore installations generally operates with an alarm and action at 20% and 50-60% LEL. Some dutyholders operate their hydrocarbon detection systems at 10% and 25% LEL, which provides a more sensitive detection level.

It is suggested that best practice would be to operate hydrocarbon gas detection systems at the more sensitive values of 10% & 25% LEL.

Relevant legal requirements

References

  1. Workplace exposure limits: Containing the list of workplace exposure limits for use with the Control of Substances Hazardous to Health Regulations 2002 (as amended) EH 40/2005 HSE Books 2005 ISBN 0717629775
  2. ISO 10418 - Petroleum and natural gas industries - Offshore production installations - Analysis, design, installation and testing of basic surface process safety systems
  3. Offshore hydrocarbon releases 2001-2008 RR672 HSE Books 2008
  4. Hydrocarbon releases database
  5. API RP 14C Recommended practice for analysis, design, installation and testing of basic surface safety systems for offshore production platforms
  6. Prevention of fire and explosion, and emergency response on offshore installations. Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995 Approved Code of Practice and Guidance L65 Second edition HSE Books 1997 ISBN 0 7176 1386 0

This information sheet contains notes on good practice which are not compulsory but which you may find helpful in considering what you need to do

Updated 2011-09-29