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Onshore Environmental Risks - Air Pollution

Air emissions

The main sources of continuous or non-continuous air emissions resulting from onshore activities include:

Combustion sources from power and heat generation, Use of compressors, pumps, and reciprocating engines (boilers, turbines, and other engines), Flaring and venting of hydrocarbons, Fugitive emissions.

Principal pollutants from these air emission sources include:

  1. Nitrogen oxides,
  2. Sulfur oxides,
  3. Carbon monoxide and particulates,
  4. Additional pollutants:
    1. Hydrogen sulfide (H2S)
    2. Volatile organic compounds (VOC) methane and ethane
    3. Benzene
    4. Ethyl benzene
    5. Toluene, and xylenes (BTEX)
    6. Glycols
    7. Polycyclic aromatic hydrocarbons (PAHS).

Significant amount of toxic gas emissions from the site facilities and activities shall be quantified annually in accordance with nationally/internationally recognized methodologies and reporting procedures in order to reduce air emissions. Also, cost effective options that are technically feasible shall be evaluated for reducing these emissions.

Air quality impacts should be estimated by the use of baseline air quality assessments and atmospheric dispersion models to establish potential ground level ambient air concentrations during facility design and operations planning. These studies should ensure that there are no adverse impacts on human health and the environment.

Exhaust gases

The most significant sources of exhaust gas emissions from onshore facilities are:

  1. Combustion of gas or liquid fuels in turbines, boilers, compressors, pumps and other engines for power and heat generation
  2. Water injection
  3. Oil and gas export, etc.

Air emission specifications should be considered during all equipment selection and procurement.

Venting and flaring

Associated gas brought to the surface with crude oil during oil production is sometimes disposed off at onshore facilities by venting or flaring to the atmosphere. This practice is now widely recognized to be a waste of a valuable resource, as well as a significant source of green house gas (GHG) emissions. However, flaring or venting are also important safety measures used on onshore oil and gas facilities to ensure gas and other hydrocarbons are safely disposed in the event of an emergency, power or equipment failure, or other plant upset condition.

Measures consistent with the Global Gas Flaring and Venting Reduction Voluntary Standard (part of the World Bank Group’s Global Gas Flaring Reduction Public-Private Partnership (GGFR program3) should be adopted when considering flaring and venting options for onshore activities. The standard provides guidance on how to eliminate or achieve reductions in the flaring and venting of natural gas.

Continuous venting of associated gas is not considered as a good practice and should be avoided. The associated gas stream should be routed to an efficient flare system, although continuous flaring of gas should be avoided if feasible alternatives are available.

Before flaring is adopted, feasible alternatives for the use of the gas should be evaluated to the maximum extent possible and integrated into production design.

Alternative options may include gas utilization for on-site energy needs, export of the gas to a neighboring facility or to market, gas injection for reservoir pressure maintenance, enhanced recovery using gas lift, or gas for instrumentation. An assessment of alternatives should be adequately documented and recorded.

If none of the alternative options are currently feasible, then measures to minimize flare volumes should be evaluated and flaring should be considered as an interim solution, with the elimination of continuous production associated gas flaring as the preferred goal. If flaring is necessary, continuous improvement of flaring through implementation of best practices and new technologies should be demonstrated.

The following pollution prevention and control measures should be considered for gas flaring:


  1. Implementation of source gas reduction measures to the maximum extent possible,
  2. Use of efficient flare tips, and optimization of the size and number of burning nozzles,
  3. Maximizing flare combustion efficiency by controlling and optimizing flare fuel/air stream flow rates to ensure the correct ratio of assist stream to flare stream,
  4. Minimizing flaring from purges and pilots, without compromising safety, through measures including installation of purge gas reduction devices, flare gas recovery units, inert purge gas, soft seat valve technology where appropriate, and installation of conservation pilots,
  5. Minimizing risk of pilot blow-out by ensuring sufficient exit velocity and providing wind guards,
  6. Use of a reliable pilot ignition system,
  7. Installation of high-integrity instrument pressure protection systems, wherever necessary, to reduce high-pressure events and to avoid or reduce flaring situations,
  8. Minimizing liquid carry-over and entrainment in the gas flare stream with a suitable liquid separation system,
  9. Minimizing flame lift off and/or flame lick,
  10. Operating flare to control odour and visible smoke emissions (no visible black smoke)
  11. Locating flare at a safe distance from local communities and the workforce including workforce accommodation units
  12. Implementation of burner maintenance and replacement programs to ensure continuous maximum flare efficiency
  13. Metering flare gas.

In the event of an emergency or equipment breakdown, or plant upset conditions, excess gas should not be vented, but should be sent to an efficient flare gas system. Emergency venting may be necessary under specific field conditions where flaring of the gas stream is not possible, or where a flare gas system is not available, such as lack of sufficient hydrocarbon content in the gas stream to support combustion or lack of sufficient gas pressure to allow it to enter the flare system.

Justification for excluding a gas flaring system should be fully documented before an emergency gas venting facility is considered.

To minimize flaring events as a result of equipment breakdowns and plant upsets, plant reliability should be high (>95%) and provision should be made for equipment sparing and plant turn down protocols.

Flaring volumes for new facilities should be etimated during the initial commissioning period so that fixed volume flaring targets can be developed. The volumes of gas flared for all flaring events should be recorded and reported.

Fugitive emissions

Fugitive emissions at onshore facilities may be associated with cold vents, leaking pipes and tubing, valves, connections, flanges, packing, open-ended lines, pump seals, compressor seals, pressure relief valves, tanks or open pits/containments, and hydrocarbon loading and unloading operations.

Methods for controlling and reducing fugitive emissions should be considered and implemented in the design, operation, and maintenance of facilities. The selection of appropriate valves, flanges, fittings, seals, and packing should consider safety and suitability requirements as well as their capacity to reduce gas leaks and fugitive emissions. Additionally, leak detection and repair programs should be implemented.

Vapour control units should be installed, as needed, for hydrocarbon loading and unloading operations. Use of open vents in tank roofs should be avoided by installing pressure relief valves. Vapour control units should be installed, as needed, for the loading and unloading of ship tankers. Vapour processing systems may consist of different units, such as carbon adsorption, refrigeration, thermal oxidation, and lean oil absorption units.

Well testing

During well testing, flaring of produced hydrocarbons should be avoided wherever practical and possible, and especially near local communities or in environmentally sensitive areas. Feasible alternatives should be evaluated for the recovery of hydrocarbon test fluids, while considering the safety of handling volatile hydrocarbons, for transfer to a processing facility or other alternative disposal options. An evaluation of disposal alternatives for produced hydrocarbons should be adequately documented and recorded.

If flaring is the only option available for the disposal of test fluids, only the minimum volume of hydrocarbons required for the test should be flowed and well test durations should be reduced to the extent practical. An efficient test flare burner head equipped with an appropriate combustion enhancement system should be selected to minimize incomplete combustion, black smoke, and hydrocarbon fallout. Volumes of hydrocarbons flared should be recorded.




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  • ASMAA - Algarve Surf and Marine Activities Association
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